FORM 10-Q
Table of Contents

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the Quarterly Period Ended September 30, 2010

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

For the transition period from                  to                 

Commission File No. 1-13726

Chesapeake Energy Corporation

(Exact name of registrant as specified in its charter)

 

Oklahoma   73-1395733
(State or other jurisdiction of incorporation or organization)   (I.R.S. Employer Identification No.)

 

6100 North Western Avenue

 

Oklahoma City, Oklahoma

  73118
(Address of principal executive offices)   (Zip Code)

(405) 848-8000

(Registrant’s telephone number, including area code)

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

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

Indicate by check mark 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]

As of November 3, 2010, there were 653,915,007 shares of our $0.01 par value common stock outstanding.

 

 

 


Table of Contents

 

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

INDEX TO FORM 10-Q FOR THE QUARTER ENDED SEPTEMBER 30, 2010

 

PART I.

  

Financial Information

  
            Page  

Item 1.

  

Condensed Consolidated Financial Statements (Unaudited):

  
  

Condensed Consolidated Balance Sheets as of September 30, 2010 and
December 31, 2009

     1   
  

Condensed Consolidated Statements of Operations for the Three and Nine Months Ended
September 30, 2010 and 2009

     3   
  

Condensed Consolidated Statements of Cash Flows for the Nine Months Ended
September 30, 2010 and 2009

     4   
  

Condensed Consolidated Statements of Equity for the Nine Months Ended
September 30, 2010 and 2009

     6   
  

Condensed Consolidated Statements of Comprehensive Income (Loss) for the Three and
Nine Months Ended September 30, 2010 and 2009

     7   
  

Notes to Condensed Consolidated Financial Statements

     8   

Item 2.

  

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

     41   

Item 3.

  

Quantitative and Qualitative Disclosures About Market Risk

     59   

Item 4.

  

Controls and Procedures

     65   

PART II.

  

Other Information

  

Item 1.

  

Legal Proceedings

     66   

Item 1A.

  

Risk Factors

     66   

Item 2.

  

Unregistered Sales of Equity Securities and Use of Proceeds

     66   

Item 3.

  

Defaults Upon Senior Securities

     66   

Item 4.

  

(Removed and Reserved)

     66   

Item 5.

  

Other Information

     66   

Item 6.

  

Exhibits

     67   


Table of Contents

 

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

 

       September 30,
2010
    December 31,
2009
 
       ($ in millions)  
ASSETS   

CURRENT ASSETS:

      

Cash and cash equivalents

     $ 609      $ 307   

Accounts receivable

       1,454        1,325   

Short-term derivative instruments

       1,087        692   

Deferred income tax asset

              24   

Other

       123        98   
                  

Total Current Assets

       3,273        2,446   
                  

PROPERTY AND EQUIPMENT:

      

Natural gas and oil properties, at cost based on full-cost accounting:

      

Evaluated natural gas and oil properties

       37,391        35,007   

Unevaluated properties

       12,706        10,005   

Less: accumulated depreciation, depletion and amortization of natural gas and oil properties

       (25,232     (24,220
                  

Total natural gas and oil properties, at cost based on full-cost accounting

       24,865        20,792   
                  

Other property and equipment:

      

Natural gas gathering systems and treating plants

       1,837        3,516   

Buildings and land

       1,751        1,673   

Drilling rigs and equipment

       763        687   

Natural gas compressors

       284        325   

Other

       649        550   

Less: accumulated depreciation and amortization of other property and equipment

       (669     (833
                  

Total other property and equipment

       4,615        5,918   
                  

Total Property and Equipment

       29,480        26,710   
                  

OTHER ASSETS:

      

Investments

       1,189        404   

Long-term derivative instruments

       29        60   

Other assets

       362        294   
                  

Total Other Assets

       1,580        758   
                  

TOTAL ASSETS

     $ 34,333      $ 29,914   
                  

 

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

 

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS – (Continued)

(Unaudited)

 

       September 30,
2010
    December 31,
2009
 
       ($ in millions)  
LIABILITIES AND EQUITY   

CURRENT LIABILITIES:

      

Accounts payable

     $ 1,773      $ 957   

Short-term derivative instruments

       26        27   

Accrued liabilities

       1,171        920   

Deferred income taxes

       379          

Income taxes payable

       2        1   

Revenues and royalties due others

       650        565   

Accrued interest

       122        218   
                  

Total Current Liabilities

       4,123        2,688   
                  

LONG-TERM LIABILITIES:

      

Long-term debt, net

       11,445        12,295   

Deferred income tax liabilities

       1,839        1,059   

Long-term derivative instruments

       967        787   

Asset retirement obligations

       291        282   

Revenues and royalties due others

       75        73   

Other liabilities

       320        389   
                  

Total Long-Term Liabilities

       14,937        14,885   
                  

CONTINGENCIES AND COMMITMENTS (Note 3)

      

EQUITY:

      

Chesapeake stockholders’ equity:

      

Preferred stock, $0.01 par value, 20,000,000 shares authorized:

      

5.75% cumulative convertible non-voting preferred stock, 1,500,000 and 0 shares issued and outstanding as of September 30, 2010 and December 31, 2009, respectively, entitled in liquidation to $1.5 billion and $0

       1,500          

5.75% cumulative convertible non-voting preferred stock (series A), 1,100,000 and 0 shares issued and outstanding as of September 30, 2010 and December 31, 2009, respectively, entitled in liquidation to $1.1 billion and $0

       1,100          

4.50% cumulative convertible preferred stock, 2,558,900 shares issued and outstanding as of September 30, 2010 and December 31, 2009, entitled in liquidation to $256 million

       256        256   

5.00% cumulative convertible preferred stock (series 2005B), 2,095,615 shares issued and outstanding as of September 30, 2010 and December 31, 2009, entitled in liquidation to $209 million

       209        209   

5.00% cumulative convertible preferred stock (series 2005), 0 and 5,000 shares issued and outstanding as of September 30, 2010 and December 31, 2009, entitled in liquidation to $0 and $1 million

              1   

Common stock, $0.01 par value, 1,000,000,000 shares authorized, 655,330,601 and 648,549,165 shares issued at September 30, 2010 and December 31, 2009, respectively

       7        6   

Paid-in capital

       12,138        12,146   

Retained earnings (deficit)

       57        (1,261

Accumulated other comprehensive income, net of tax of ($16) million and ($62) million, respectively

       25        102   

Less: treasury stock, at cost; 1,049,382 and 877,205 common shares as of September 30, 2010 and December 31, 2009, respectively

       (19     (15
                  

Total Chesapeake Stockholders’ Equity

       15,273        11,444   

Noncontrolling interest

              897   
                  

Total Equity

       15,273        12,341   
                  

TOTAL LIABILITIES AND EQUITY

     $ 34,333      $ 29,914   
                  

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

 

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

 

     Three Months Ended
September 30,
         Nine Months Ended
  September 30,
 
       2010       2009        2010     2009  
     ($ in millions, except per share data)  

REVENUES:

           

 Natural gas and oil sales

   $ 1,639      $ 1,187         $ 4,698      $ 3,681   

 Marketing, gathering and compression sales

     883        575           2,520        1,660   

 Service operations revenue

     59        49           173        139   
                                   

 Total Revenues

     2,581        1,811           7,391        5,480   
                                   

OPERATING COSTS:

           

 Production expenses

     231        218           652        670   

 Production taxes

     34        25           119        71   

 General and administrative expenses

     125        95           340        259   

 Marketing, gathering and compression expenses

     851        546           2,429        1,569   

 Service operations expense

     52        49           154        136   

 Natural gas and oil depreciation, depletion and amortization

     378        295           1,025        1,037   

 Depreciation and amortization of other assets

     56        62           159        177   

 Impairment or loss on sale of other property and equipment

     37        124           37        159   

 Impairment of natural gas and oil properties

                             9,600   

 Restructuring costs

                             34   
                                   

 Total Operating Costs

     1,764        1,414           4,915        13,712   
                                   

INCOME (LOSS) FROM OPERATIONS

     817        397           2,476        (8,232
                                   

OTHER INCOME (EXPENSE):

           

 Interest expense

     (3     (43        (12     (52

 Loss on redemptions or exchanges of Chesapeake debt

     (59     (17        (130     (19

 Impairment of investments

     (16               (16     (162

 Other income (expense)

     168        (30        202        (25
                                   

 Total Other Income (Expense)

     90        (90        44        (258
                                   

INCOME (LOSS) BEFORE INCOME TAXES

     907        307           2,520        (8,490
                                   

INCOME TAX EXPENSE (BENEFIT):

           

 Current income taxes

     (1               4        1   

 Deferred income taxes

     350        115           966        (3,185
                                   

 Total Income Tax Expense (Benefit)

     349        115           970        (3,184
                                   

NET INCOME (LOSS)

     558        192           1,550        (5,306
                                   

 Net (income) loss attributable to noncontrolling interest

                               
                                   

NET INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE

     558        192           1,550        (5,306

 Preferred stock dividends

     (43     (6        (68     (18
                                   

NET INCOME (LOSS) AVAILABLE TO CHESAPEAKE COMMON STOCKHOLDERS

   $ 515      $ 186         $ 1,482      $ (5,324
                                   

EARNINGS (LOSS) PER COMMON SHARE:

           

 Basic

   $ 0.81      $ 0.30         $ 2.35      $ (8.78

 Diluted

   $ 0.75      $ 0.30         $ 2.24      $ (8.78

CASH DIVIDEND DECLARED PER COMMON SHARE

   $ 0.075      $ 0.075         $ 0.225      $ 0.225   

WEIGHTED AVERAGE COMMON AND COMMON EQUIVALENT SHARES OUTSTANDING (in millions):

           

 Basic

     632        619           631        606   

 Diluted

     744        626           692        606   

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

 

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

 

           Nine Months Ended    
September 30,
 
       2010     2009  
       ($ in millions)  

CASH FLOWS FROM OPERATING ACTIVITIES:

      

NET INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE

     $ 1,550      $ (5,306

ADJUSTMENTS TO RECONCILE NET INCOME (LOSS) TO CASH PROVIDED BY OPERATING ACTIVITIES:

      

Depreciation, depletion and amortization

       1,184        1,214   

Deferred income tax expense (benefit)

       966        (3,185

Unrealized (gains) losses on derivatives

       (45     295   

Realized gains on financing derivatives

       (436     (53

Stock-based compensation

       111        104   

Accretion of discount on contingent convertible notes

       58        60   

(Gain) loss on equity investments

       (120     32   

Loss on redemptions or exchanges of Chesapeake debt

       29        19   

Impairment or loss on sale of other property and equipment

       37        159   

Impairment of natural gas and oil properties

              9,600   

Impairment of investments

       16        162   

Restructuring costs

              12   

Other

       12        8   

Change in assets and liabilities

       609        10   
                  

Cash provided by operating activities

       3,971        3,131   
                  

CASH FLOWS FROM INVESTING ACTIVITIES:

      

Exploration and development of natural gas and oil properties

       (3,718     (2,790

Acquisitions of natural gas and oil proved and unproved properties

       (4,217     (1,348

Additions to other property and equipment

       (968     (1,362

Proceeds from divestitures of proved and unproved properties

       3,107        1,729   

Proceeds from sales of other assets

       328        157   

Additions to investments

       (113     (40

Deposits on acquisitions

       (95       

Other

       11          
                  

Cash used in investing activities

       (5,665     (3,654
                  

CASH FLOWS FROM FINANCING ACTIVITIES:

      

Proceeds from credit facilities borrowings

       10,458        5,563   

Payments on credit facilities borrowings

       (9,863     (7,866

Proceeds from issuance of preferred stock, net of offering costs

       2,562          

Proceeds from issuance of senior notes, net of offering costs

       1,967        1,346   

Cash paid to redeem Chesapeake debt

       (3,434       

Cash paid for common stock dividends

       (142     (135

Cash paid for preferred stock dividends

       (49     (18

Realized gains on financing derivatives

       436        19   

Proceeds from sale of noncontrolling interest in midstream joint venture

              588   

Proceeds from sale/leaseback of real estate surface assets

              145   

Proceeds from mortgage of building

              54   

Net increase (decrease) in outstanding payments in excess of cash balance

       116        (305

Other

       (55     (97
                  

Cash provided by (used in) financing activities

       1,996        (706
                  

Net increase (decrease) in cash and cash equivalents

       302        (1,229

Cash and cash equivalents, beginning of period

       307        1,749   
                  

Cash and cash equivalents, end of period

     $ 609      $ 520   
                  

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

 

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS – (Continued)

(Unaudited)

 

 

 

         Nine Months Ended    
September 30,
 
     2010     2009  

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION OF CASH PAYMENTS FOR:

    

Interest, net of capitalized interest

   $ 103      $ 111   

Income taxes, net of refunds received

   $ (291   $ 176   

SUPPLEMENTAL SCHEDULE OF SIGNIFICANT NON-CASH INVESTING AND FINANCING ACTIVITIES:

As of September 30, 2010 and 2009, dividends payable on our common and preferred stock were $90 million and $52 million, respectively.

For the nine months ended September 30, 2010 and 2009, natural gas and oil properties were adjusted by $116 million and ($72) million, respectively, as a result of an increase (decrease) in accrued exploration and development costs.

For the nine months ended September 30, 2010 and 2009, other property and equipment were adjusted by ($8) million and ($31) million, respectively, as a result of an increase (decrease) in accrued costs.

We recorded non-cash asset reductions to natural gas and oil properties of $2 million and $3 million for the nine months ended September 30, 2010 and 2009, respectively, for asset retirement obligations.

We recorded non-cash asset reductions to natural gas gathering systems of $2 million and $3 million for the nine months ended September 30, 2010 and 2009, respectively, for asset retirement obligations.

During the nine months ended September 30, 2010, holders of our 2.25% Contingent Convertible Senior Notes due 2038 exchanged approximately $11 million in aggregate principal amount for an aggregate of 298,500 shares of our common stock in privately negotiated exchanges.

On May 3, 2010, we converted all 5,000 shares of our outstanding 5.00% Cumulative Convertible Preferred Stock (Series 2005) into 20,774 shares of common stock pursuant to the company’s mandatory conversion rights.

During the nine months ended September 30, 2009, we issued 24,822,832 shares of common stock, valued at $429 million, for the purchase of proved and unproved properties pursuant to an acquisition shelf registration statement.

During the nine months ended September 30, 2009, holders of our 2.25% Contingent Convertible Senior Notes due 2038 exchanged approximately $238 million in aggregate principal amount for an aggregate of 6,707,321 shares of our common stock in privately negotiated exchanges.

On June 15, 2009, we converted all 143,768 shares of our outstanding 6.25% Mandatory Convertible Preferred Stock into 1,239,538 shares of common stock.

On March 31, 2009, we converted all 3,033 shares of our outstanding 4.125% Cumulative Convertible Preferred Stock into 182,887 shares of common stock.

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

 

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF EQUITY

(Unaudited)

 

         Nine Months Ended      
     September 30,  
     2010     2009  
     ($ in millions)  

PREFERRED STOCK:

    

Balance, beginning of period

   $ 466      $ 505   

Issuance of 1,500,000 and 0 shares of 5.75% preferred stock

     1,500          

Issuance of 1,100,000 and 0 shares of 5.75% preferred stock (series A)

     1,100          

Conversion or exchange of 5,000 and 146,801 shares of preferred stock for common stock

     (1     (39
                

Balance, end of period

     3,065        466   
                

COMMON STOCK:

    

Balance, beginning of period

     6        6   

Conversion or exchange of convertible notes and preferred stock for 319,274 and 8,129,746 shares of common stock

              

Issuance of 0 and 24,822,832 shares of common stock for the purchase of proved and unproved properties

              

Stock-based compensation

     1          
                

Balance, end of period

     7        6   
                

PAID-IN CAPITAL:

    

Balance, beginning of period

     12,146        11,680   

Issuance of 0 and 24,822,832 shares of common stock for the purchase of proved and unproved properties

            420   

Conversion or exchange of convertible notes and preferred stock for 319,274 and 8,129,746 shares of common stock

     9        203   

Stock-based compensation

     174        143   

Offering expenses

     (39       

Dividends on common stock

     (95     (138

Dividends on preferred stock

     (44     (17

Allocation of joint venture capital to Global Infrastructure Partners

            (263

Tax benefit (reduction in tax benefit) from exercise of stock-based compensation

     (13     (47
                

Balance, end of period

     12,138        11,981   
                

RETAINED EARNINGS (DEFICIT):

    

Balance, beginning of period

     (1,261     4,569   

Net income (loss)

     1,550        (5,306

Cumulative effect of accounting change, net of income taxes of $89 million

     (142       

Dividends on common stock

     (47       

Dividends on preferred stock

     (43       
                

Balance, end of period

     57        (737
                

ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS):

    

Balance, beginning of period

     102        267   

Hedging activity

     (70     (60

Investment activity

     (7     67   
                

Balance, end of period

     25        274   
                

TREASURY STOCK – COMMON:

    

Balance, beginning of period

     (15     (10

Purchase of 179,140 and 115,430 shares for company benefit plans

     (4     (2

Release of 6,963 and 6,152 shares for company benefit plans

              
                

Balance, end of period

     (19     (12
                

TOTAL CHESAPEAKE STOCKHOLDERS’ EQUITY

     15,273        11,978   
                

NONCONTROLLING INTEREST:

    

Balance, beginning of period

     897          

Sale of noncontrolling interest in midstream joint venture

            588   

Allocation of joint venture capital to Global Infrastructure Partners

            263   

Deconsolidation of investment in CMP

     (897       
                

Balance, end of period

            851   
                

TOTAL EQUITY

   $ 15,273      $ 12,829   
                

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

 

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(Unaudited)

 

       Three Months Ended
September 30,
         Nine Months Ended  
   September 30,  
 
       2010     2009        2010     2009  
       ($ in millions)  

Net income (loss)

     $ 558      $ 192         $ 1,550      $ (5,306

Other comprehensive income (loss), net of income tax:

             

Change in fair value of derivative instruments, net of income taxes of $39 million, $38 million, $153 million and $372 million

       65        62           251        609   

Reclassification of gain on settled contracts, net of income taxes of ($68) million, ($144) million, ($203) million and ($377) million

       (112     (236        (333     (617

Ineffective portion of derivatives qualifying for cash flow hedge accounting, net of income taxes of ($2) million, $2 million, $8 million and ($31) million

       (3     5           12        (52

Unrealized (gain) loss on marketable securities, net of income taxes of $1 million, $4 million, ($4) million and $14 million

       1        6           (7     24   

Reclassification of loss on investments, net of income taxes of $0, $0, $0 and $26 million

                               43   
                                     

Comprehensive income (loss)

       509        29           1,473        (5,299
                                     

(Income) loss attributable to noncontrolling interest

                                 
                                     

Comprehensive income (loss) available to Chesapeake

     $ 509      $ 29         $ 1,473      $ (5,299
                                     

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

 

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

1.

Basis of Presentation and Summary of Significant Accounting Policies

Principles of Consolidation

The accompanying unaudited condensed consolidated financial statements of Chesapeake Energy Corporation and its subsidiaries have been prepared in accordance with the instructions to Form 10-Q as prescribed by the Securities and Exchange Commission (SEC). Chesapeake’s annual report on Form 10-K for the year ended December 31, 2009 (2009 Form 10-K) includes certain definitions and a summary of significant accounting policies and should be read in conjunction with this Form 10-Q. All material adjustments (consisting solely of normal recurring adjustments) which, in the opinion of management, are necessary for a fair statement of the results for the interim periods have been reflected. The results for the three and nine months ended September 30, 2010 are not necessarily indicative of the results to be expected for the full year. This Form 10-Q relates to the three and nine months ended September 30, 2010 (the “Current Quarter” and the “Current Period”, respectively) and the three and nine months ended September 30, 2009 (the “Prior Quarter” and the “Prior Period”, respectively).

Cumulative Effect of Accounting Change

Effective January 1, 2010, in accordance with new authoritative guidance for variable interest entities, we ceased consolidating our 50/50 midstream joint venture with Global Infrastructure Partners within our financial statements and began to account for the joint venture under the equity method (see Note 9). Adoption of this new guidance resulted in an after-tax cumulative effect charge to retained earnings of $142 million, which is reflected in our condensed consolidated statement of equity for the Current Period. This charge reflects the difference between the carrying value of our initial investment in the joint venture, which was recorded at carryover basis as an entity under common control, and the fair value of our equity in the joint venture as of the formation date.

Critical Accounting Policies

We consider accounting policies related to hedging, natural gas and oil properties and income taxes to be critical policies. These policies are summarized in Management’s Discussion and Analysis of Financial Condition and Results of Operations in our 2009 Form 10-K.

 

2.

Financial Instruments and Hedging Activities

Natural Gas and Oil Derivatives

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. 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 our risk management objectives. As of September 30, 2010 and December 31, 2009, our natural gas and oil derivative instruments were comprised of the following types of instruments:

 

   

Swaps: Chesapeake receives a fixed price and pays a floating market price to the counterparty for the hedged commodity.

 

   

Collars: These instruments 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 put and the call strike price, no payments are due from either party. Three-way collars include an additional put option in exchange for a more favorable strike price on the collar. This eliminates the counterparty’s downside exposure below the second put option.

 

   

Call options: Chesapeake sells call options in exchange for a premium from the counterparty. At the time of settlement, if the market price exceeds the fixed price of the call option, Chesapeake pays the counterparty such excess and if the market price settles below the fixed price of the call option, no payment is due from either party.

 

   

Put options: Chesapeake receives a premium from the counterparty in exchange for the sale of a put option. At the time of settlement, if the market price falls below the fixed price of the put option, Chesapeake pays the counterparty such shortfall, and if the market price settles above the fixed price of the put option, no payment is due from either party.

 

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

 

   

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.

 

   

Basis protection swaps: These instruments are arrangements that guarantee a price differential to NYMEX for natural gas from a specified delivery point. For non-Appalachian Basin 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.

All of our derivative instruments are net settled based on the difference between the fixed-price payment and the floating-price payment, resulting in a net amount due to or from the counterparty.

The estimated fair values of our natural gas and oil derivative instruments as of September 30, 2010 and December 31, 2009 are provided below. The associated carrying values of these instruments are equal to the estimated fair values.

 

     September 30, 2010     December 31, 2009  
             Volume                   Fair Value                 Volume                   Fair Value      
Natural gas (bbtu):          ($ in millions)           ($ in millions)  

Fixed-price swaps

     616,190      $ 1,378        492,053      $ 662   

Fixed-price collars

     10,980        37        74,240        92   

Call options

     1,333,619        (481     996,750        (541

Put options

     (58,580     (75     (69,620     (50

Fixed-price knockout swaps

     28,530        5        38,370        17   

Basis protection swaps

     154,502        (52     125,469        (50
                                

Total natural gas

     2,085,241        812        1,657,262        130   
                                

Oil (mbbl):

        

Fixed-price swaps

     8,044        (28     5,475        3   

Call options

     42,259        (622     14,975        (144

Fixed-price knockout swaps

     3,023        35        6,572        32   
                                

Total oil

     53,326        (615     27,022        (109
                                

Total estimated fair value

     $ 197        $ 21   
                    

Pursuant to accounting guidance for derivatives and hedging, certain derivatives qualify for designation as cash flow hedges. Following this guidance, changes in the fair value of 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 accumulated other comprehensive income until the hedged item is recognized in earnings as the physical transactions being hedged occur. Any change in fair value resulting from ineffectiveness is currently recognized in natural gas and oil sales as unrealized gains (losses). Changes in the fair value of non-qualifying derivatives that occur prior to their maturity (i.e., temporary fluctuations in value) are reported currently in the condensed consolidated statements of operations as unrealized gains (losses) within natural gas and oil sales. Realized gains (losses) are included in natural gas and oil sales in the month of related production.

 

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

 

The components of natural gas and oil sales for the Current Quarter, the Prior Quarter, the Current Period and the Prior Period are presented below.

 

     Three Months Ended
September 30,
    Nine Months Ended
September 30,
 
         2010              2009             2010             2009      
     ($ in millions)  

Natural gas and oil sales

   $ 1,074       $ 785      $ 3,243      $ 2,280   

Realized gains (losses) on natural gas and oil derivatives

     512         687        1,484        1,802   

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

     48         (278     (9     (484

Unrealized gains (losses) on ineffectiveness of cash flow hedges

     5         (7     (20     83   
                                 

  Total natural gas and oil sales

   $ 1,639       $ 1,187      $ 4,698      $ 3,681   
                                 

Based upon the market prices at September 30, 2010, we expect to transfer approximately $188 million (net of income taxes) of the gain included in the accumulated other comprehensive income balance to net income (loss) during the next 12 months in the related month of production. All transactions hedged as of September 30, 2010 are expected to mature by December 31, 2022.

We have a multi-counterparty hedge facility with 13 counterparties that have committed to provide approximately 5.6 tcfe of trading capacity and an aggregate mark-to-market capacity of $15.0 billion under the terms of the facility. As of September 30, 2010, we had hedged a total of 2.3 tcfe under the facility. The multi-counterparty facility allows us to enter into cash-settled natural gas and oil price and basis hedges with the counterparties. Our obligations under the multi-counterparty facility are secured by natural gas and oil proved reserves, the value of which must cover the fair value of the transactions outstanding under the facility by at least 1.65 times, and guarantees by certain subsidiaries that also guarantee our corporate revolving bank credit facility and indentures. The counterparties’ obligations under the facility must be secured by cash or short-term U.S. Treasury instruments to the extent that any mark-to-market amounts they owe to Chesapeake exceed defined thresholds. The maximum volume-based trading capacity under the facility is governed by the expected production of the pledged reserve collateral, and volume-based trading limits are applied separately to price and basis hedges. In addition, there are volume-based sub-limits for natural gas and oil hedges. Chesapeake has significant flexibility with regard to releases and/or substitutions of pledged reserves, provided that certain collateral coverage and other requirements are met. The facility does not have a maturity date. Counterparties to the agreement have the right to cease trading with the company on a prospective basis as long as obligations associated with any existing trades in the facility continue to be satisfied in accordance with the terms of the agreement.

Interest Rate Derivatives

To mitigate our exposure to volatility in interest rates related to our senior notes and bank credit facilities, we enter into interest rate derivatives. As of September 30, 2010 and December 31, 2009, our interest rate derivative instruments were comprised of the following types of instruments:

 

   

Swaps: Chesapeake enters into fixed-to-floating interest rate swaps (we receive a fixed interest rate and pay a floating market rate) to mitigate our exposure to changes in the fair value of our senior notes. We enter into floating-to-fixed interest rate swaps (we receive a floating market rate and pay a fixed interest rate) to manage our interest rate exposure related to our bank credit facilities borrowings.

 

   

Collars: These instruments contain a fixed floor rate (floor) and a ceiling rate (cap). If the floating rate is above the cap, we have a net receivable from the counterparty and if the floating rate is below the floor, we have a net payable to the counterparty. If the floating rate is between the floor and the cap, there is no payment due from either party. Collars are used to manage our interest rate exposure related to our bank credit facilities borrowings.

 

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

 

   

Call options: Occasionally we sell call options for a premium when we think it is more likely that the option will expire unexercised. The option allows the counterparty to terminate an open swap on a specific date.

 

   

Swaptions: Occasionally we sell an option to a counterparty for a premium which allows the counterparty to enter into a swap with us on a specific date.

The notional amount of debt hedged and the estimated fair value of our interest rate derivatives outstanding as of September 30, 2010 and December 31, 2009 are provided below.

 

     September 30, 2010        December 31, 2009  
     Notional
Amount
     Fair
    Value    
        Notional 
Amount
     Fair
    Value    
 
     ($ in millions)  

Interest rate:

             

Swaps

   $ 1,300       $ (13      $ 2,925       $ (113

Collars

                       250         (6

Call options

     250         (26        250         (2

Swaptions

     250                   500         (11
                                     

Totals

   $ 1,800       $ (39      $ 3,925       $ (132
                                     

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

Realized gains or losses from interest rate derivative transactions are reflected as adjustments to interest expense in the condensed consolidated statements of operations. The components of interest expense for the Current Quarter, the Prior Quarter, the Current Period and the Prior Period are presented below.

 

      Three Months Ended 
September 30,
      Nine Months Ended 
September 30,
 
     2010     2009      2010     2009  
     ($ in millions)  

Interest expense on senior notes

   $ 167      $ 195       $ 550      $ 572   

Interest expense on credit facilities

     18        18         42        47   

Capitalized interest

     (185     (153      (525     (467

Realized (gains) losses on interest rate derivatives

     (2     (7      (6     (19

Unrealized (gains) losses on interest rate derivatives

     2        (20      (75     (106

Amortization of loan discount and other

     3        10         26        25   
                                 

Total interest expense

   $ 3      $ 43       $ 12      $ 52   
                                 

Our qualifying interest rate swaps are considered 100% effective and therefore no ineffectiveness was recorded for the periods presented above.

Gains and losses related to terminated qualifying interest rate derivative transactions will be amortized as an adjustment to interest expense over the remaining term of the related senior notes. Over the next ten years, we will recognize $36 million in gains related to such transactions.

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 pay Chesapeake 19 million and Chesapeake pays the counterparties $30 million, which yields 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 swap qualifies as a cash flow hedge. The fair value of the cross currency swap is recorded on the condensed consolidated

 

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

balance sheet as a liability of $35 million at September 30, 2010. The euro-denominated debt in long-term debt has been adjusted to $816 million at September 30, 2010 using an exchange rate of $1.3601 to 1.00.

Additional Disclosures Regarding Derivative Instruments and Hedging Activities

In accordance with accounting guidance for derivatives and hedging, 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 condensed consolidated balance sheets. Derivative instruments reflected as current in the condensed consolidated balance sheets represent the estimated fair value of derivatives scheduled to settle over the next twelve months based on market prices/rates as of the balance sheet date. The derivative settlement amounts are not due until the month in which the related underlying hedged transaction occurs. Cash settlements of our derivative arrangements are generally classified as operating cash flows unless the derivative contains a significant financing element at contract inception, in which case, all cash settlements are classified as financing cash flows in the accompanying condensed consolidated statements of cash flows.

The following table sets forth the fair value of each classification of derivative instrument as of September 30, 2010 and December 31, 2009, on a gross basis without regard to same-counterparty netting:

 

          Fair Value  
    

Balance Sheet Location

    September 30, 
2010
     December 31, 
2009
 
          ($ in millions)  

Asset Derivatives:

       

Derivatives designated as hedging instruments:

    

Commodity contracts

   Short-term derivative instruments    $ 438      $ 417   

Commodity contracts

   Long-term derivative instruments      41        36   

Foreign currency contracts

   Long-term derivative instruments             43   
                   

Total

        479        496   
                   

Derivatives not designated as hedging instruments:

    

Commodity contracts

   Short-term derivative instruments      794        318   

Commodity contracts

   Long-term derivative instruments      367        66   

Interest rate contracts

   Long-term derivative instruments      29          
                   

Total

        1,190        384   
                   

Liability Derivatives:

       

Derivatives designated as hedging instruments:

    

Commodity contracts

   Short-term derivative instruments             (1

Interest rate contracts

   Long-term derivative instruments             (11

Foreign currency contracts

   Long-term derivative instruments      (35       
                   

Total

        (35     (12
                   

Derivatives not designated as hedging instruments:

    

Commodity contracts

   Short-term derivative instruments      (145     (42

Commodity contracts

   Long-term derivative instruments      (1,298     (768

Interest rate contracts

   Short-term derivative instruments      (26     (27

Interest rate contracts

   Long-term derivative instruments      (42     (94
                   

Total

        (1,511     (931
                   

Total derivative instruments

      $ 123      $ (63
                   

 

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

 

A consolidated summary of the effect of derivative instruments on the condensed consolidated statements of operations for the Current Quarter, the Prior Quarter, the Current Period and the Prior Period is provided below, separating fair value, cash flow and non-qualifying derivatives.

The following table presents the gain (loss) recognized in net income (loss) for instruments designated as fair value derivatives:

 

               Three Months Ended 
September 30,
        Nine Months Ended 
September 30,
 

Fair Value Derivatives

    

Location of Gain (Loss)

       2010          2009            2010          2009    
              ($ in millions)  

Interest rate contracts

    

Interest expense(a)

     $ 3       $ 13         $ 16       $ 31   
                                            

 

(a)

Interest expense on items hedged during the Current Quarter, the Prior Quarter, the Current Period and the Prior Period was $0, $33 million, $15 million and $66 million, respectively, which is included in interest expense on the condensed consolidated statements of operations.

The following table presents the pre-tax gain (loss) recognized in, and reclassified from, accumulated other comprehensive income (AOCI) and recognized in net income (loss), including any hedge ineffectiveness, for derivative instruments designated as cash flow derivatives:

 

               Three Months Ended 
September 30,
        Nine Months Ended 
September 30,
 

Cash Flow Derivatives

    

Location of Gain (Loss)

       2010          2009            2010         2009    
              ($ in millions)  

Gain (Loss) Recognized in AOCI (Effective Portion)

                   

Commodity contracts

    

AOCI

     $ 94       $ 107         $ 458      $ 819   

Foreign exchange contracts

    

AOCI

       5         1           (34     79   
                                           
          $ 99       $ 108         $ 424      $ 898   
                                           

Gain (Loss) Reclassified from AOCI (Effective Portion)

                   

Commodity contracts

    

Natural gas and oil sales

     $ 179       $ 381         $ 535      $ 994   
                                           
          $ 179       $ 381         $ 535      $ 994   
                                           

Gain (Loss) Recognized (Ineffective Portion and Amount Excluded from Effectiveness Testing)(a)

                   

Commodity contracts

    

Natural gas and oil sales

     $ 2       $ (7      $ (95   $ 83   
                                           
          $ 2       $ (7      $ (95   $ 83   
                                           

 

(a)

In the Current Quarter, the Prior Quarter, the Current Period and the Prior Period, the amount of gain (loss) recognized in net income (loss) represents $5 million, ($7) million, ($20) million and $83 million related to the ineffective portion of our cash flow derivatives and ($3) million, $0, ($75) million and $0, respectively, related to the amount excluded from the assessment of hedge effectiveness.

The following table presents the gain (loss) recognized in net income (loss) for instruments not qualifying as cash flow or fair value derivatives:

 

               Three Months Ended 
September 30,
        Nine Months Ended 
September 30,
 

Non-Qualifying Derivatives

    

Location of Gain (Loss)

       2010         2009            2010          2009    
              ($ in millions)  

Commodity contracts

    

Natural gas and oil sales

     $ 384      $ 28         $ 1,015       $ 324   

Interest rate contracts

    

Interest expense

       (3     14           65         94   
                                           
    

Total

     $ 381      $ 42         $ 1,080       $ 418   
                                           

 

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

 

Concentration of Credit Risk

A significant portion of our credit risk is concentrated in derivative instruments that enable us to hedge a portion of our exposure to natural gas and oil prices, interest rate volatility and exchange rate exposure. 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 we attempt to limit our exposure to non-performance by any single counterparty. On September 30, 2010, our derivative instruments were spread among 14 counterparties. Additionally, our multi-counterparty secured hedging facility described previously includes 13 of our counterparties which are required to secure their natural gas and oil hedging obligations in excess of defined thresholds. We use this facility for all of our commodity hedging.

Other financial instruments which potentially subject us to concentrations of credit risk consist principally of investments in equity instruments and accounts receivable. Our accounts receivable are primarily from purchasers of natural gas and oil and exploration and production companies which own interests in properties we operate. This industry concentration has the potential to impact our overall exposure to credit risk, either positively or negatively, in that our customers may be similarly affected by changes in economic, industry or other conditions. We monitor the creditworthiness of all our counterparties. We generally require letters of credit for receivables from customers which are judged to have sub-standard credit, unless the credit risk can otherwise be mitigated. During the Current Quarter, the Prior Quarter and the Current Period, we recognized nominal amounts of bad debt expense related to potentially uncollectible receivables. During the Prior Period, we recognized $13 million of bad debt expense related to potentially uncollectible receivables.

 

3.

Contingencies and Commitments

Litigation

On February 25, 2009, a putative class action was filed in the U.S. District Court for the Southern District of New York against the company and certain of its officers and directors along with certain underwriters of the company’s July 2008 common stock offering. Following the appointment of a lead plaintiff and counsel, the plaintiff filed an amended complaint on September 11, 2009 alleging that the registration statement for the offering contained material misstatements and omissions and seeking damages under Sections 11, 12 and 15 of the Securities Act of 1933 of an unspecified amount and rescission. The action was transferred to the U.S. District Court for the Western District of Oklahoma on October 13, 2009. The defendants’ motion to dismiss was denied on September 2, 2010. A derivative action was also filed in the District Court of Oklahoma County, Oklahoma on March 10, 2009 against the company’s directors and certain of its officers alleging breaches of fiduciary duties relating to the disclosure matters alleged in the securities case. The derivative action is stayed pursuant to stipulation.

On March 26, 2009, a shareholder filed a petition in the District Court of Oklahoma County, Oklahoma seeking to compel inspection of company books and records relating to compensation of the company’s CEO. On August 20, 2009, the court denied the inspection demand, dismissed the petition and entered judgment in favor of Chesapeake. The shareholder is appealing the court’s ruling in the Court of Civil Appeals of the State of Oklahoma.

Three derivative actions were filed in the District Court of Oklahoma County, Oklahoma on April 28, May 7, and May 20, 2009 against the company’s directors alleging breaches of fiduciary duties relating to compensation of the company’s CEO and alleged insider trading, among other things, and seeking unspecified damages, equitable relief and disgorgement. These three derivative actions were consolidated and a Consolidated Derivative Shareholder Petition was filed on June 23, 2009. Chesapeake is named as a nominal defendant. Chesapeake’s motion to dismiss was granted on February 28, 2010 and plaintiffs were given leave to amend. Plaintiffs chose not to amend and on April 9, 2010, at plaintiffs’ request, the court entered an order certifying that the February 28, 2010 dismissal was a final, appealable order. Plaintiffs are appealing the dismissal in the Oklahoma Court of Civil Appeals.

We are currently unable to assess the probability of loss or estimate a range of potential loss associated with the foregoing cases. It is inherently difficult to predict the outcome of any litigation, and these proceedings are at an early stage.

Chesapeake is also involved in various other lawsuits and disputes incidental to its business operations, including commercial disputes, personal injury claims, claims for underpayment of royalties, property damage claims and contract actions. With regard to the latter, various mineral or leasehold owners have filed lawsuits against us seeking specific performance to require us to acquire their oil and natural gas interests and pay acreage bonus payments, damages based on breach of contract and/or, in certain cases, punitive damages based on alleged fraud.

 

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

The company has satisfactorily resolved most of these suits but a few are pending, either at the trial court or appellate level. The company believes that it has substantial defenses to the claims made in all these cases.

The company records an associated liability when a loss is probable and the amount is reasonably estimable. Although the outcome of litigation cannot be predicted with certainty, management is of the opinion that no pending or threatened lawsuit or dispute incidental to its business operations is likely to have a material adverse effect on the company’s consolidated financial position, results of operations or cash flows. The final resolution of such matters could exceed amounts accrued, however, and actual results could differ materially from management’s estimates.

Environmental Risk

Due to the nature of the natural gas and oil business, Chesapeake and its subsidiaries are exposed to possible environmental risks. Chesapeake has implemented various policies and procedures to avoid environmental contamination and risks from environmental contamination. Chesapeake conducts periodic reviews, on a company-wide basis, to identify changes in our environmental risk profile. These reviews evaluate whether there is a contingent liability, its amount, and the likelihood that the liability will be incurred. The amount of any potential liability is determined by considering, among other matters, incremental direct costs of any likely remediation and the proportionate cost of employees who are expected to devote a significant amount of time directly to any possible remediation effort. We manage our exposure to environmental liabilities on properties to be acquired by identifying existing problems and assessing the potential liability. Depending on the extent of an identified environmental problem, Chesapeake may exclude a property from the acquisition, require the seller to remediate the property to our satisfaction, or agree to assume liability for the remediation of the property. Chesapeake has historically not experienced any significant environmental liability, and is not aware of any potential material environmental issues or claims at September 30, 2010.

Rig Leases

In a series of transactions since 2006, our drilling subsidiaries have sold 85 drilling rigs and related equipment for $704 million and entered into a master lease agreement under which we agreed to lease the rigs from the buyer for initial terms of seven to ten years for lease payments of approximately $97 million annually. The lease obligations are guaranteed by Chesapeake and certain of its subsidiaries. These transactions were recorded as sales and operating leasebacks and any related gain or loss is being amortized to service operations expense over the lease term. Under the rig leases, we can exercise an early purchase option after five and one-half to seven years or on the expiration of the lease term for a purchase price equal to the then fair market value of the rigs. Additionally, we have the option to renew the rig lease for a negotiated renewal term at a periodic lease payment equal to the fair market rental value of the rigs as determined at the time of renewal. Commitments related to rig lease payments are not recorded in the accompanying condensed consolidated balance sheets. As of September 30, 2010, the minimum aggregate undiscounted future rig lease payments were approximately $478 million.

Compressor Leases

Through various transactions since 2007, our compression subsidiary has sold 2,234 compressors, a significant portion of its compressor fleet, for $517 million and entered into a master lease agreement. The term of the agreement varies by buyer ranging from four to ten years for aggregate lease payments of approximately $77 million annually. The lease obligations are guaranteed by Chesapeake and certain of its subsidiaries. These transactions were recorded as sales and operating leasebacks and any related gain or loss is being amortized to marketing, gathering and compression expenses over the lease term. Under the leases, we can exercise an early purchase option or we can purchase the compressors at expiration of the lease for the fair market value at the time. In addition, we have the option to renew the lease for negotiated new terms at the expiration of the lease. Commitments related to compressor lease payments are not recorded in the accompanying condensed consolidated balance sheets. As of September 30, 2010, the minimum aggregate undiscounted future compressor lease payments were approximately $441 million.

 

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

 

Transportation Contracts

Chesapeake has various firm pipeline transportation service agreements with expiration dates ranging from 2010 to 2099. These commitments are not recorded in the accompanying condensed consolidated balance sheets. Under the terms of these contracts, we are obligated to pay demand charges as set forth in the transporter’s Federal Energy Regulatory Commission (FERC) gas tariff. In exchange, the company receives rights to flow natural gas production through pipelines located in highly competitive markets. The aggregate undiscounted amounts of such required demand payments are presented below:

 

     September 30, 
2010
 
   

($ in millions)

 

2010

    $ 82   

2011

      378   

2012

      378   

2013

      364   

2014

      344   

2015 – 2099

      2,449   
         

Total

    $         3,995   
         

Drilling and Rig Purchase Contracts

Currently, Chesapeake has contracts with various drilling contractors to lease approximately 46 rigs with terms of four months to four years. These commitments are not recorded in the accompanying condensed consolidated balance sheets. As of September 30, 2010, the aggregate undiscounted drilling rig commitment was approximately $204 million.

In September 2010, Chesapeake entered into a contract to purchase 7 rigs for $85 million. As of September 30, 2010, we had made a $9 million deposit and have a remaining commitment of $76 million. The transaction is expected to close in December 2010.

Natural Gas and Oil Purchase Obligations

Our marketing segment regularly commits to purchase natural gas from other owners in our properties and such commitments typically are short-term in nature. We have also committed to purchase any natural gas and oil associated with certain volumetric production payment transactions. The purchase commitments are based on market prices at the time of production, and the purchased natural gas and oil is resold.

Minimum Volume Commitments

We are a party to a gas gathering agreement with a subsidiary of Chesapeake Midstream Partners, L.P. (see Note 9), pursuant to which we have committed to deliver specified minimum volumes of natural gas from our Barnett Shale production annually through December 31, 2018 and for the six-month period ending June 30, 2019. At the end of the term or annually, Chesapeake will be invoiced for any shortfalls in such volume commitments at the rate specified in the agreement. Volume commitments remaining as of September 30, 2010 were as follows:

 

           Bcf        

2010

     129   

2011

     313   

2012

     325   

2013

     338   

2014

     351   

After 2014

     1,686   
        

Total

             3,142   
        

In addition, Chesapeake has entered into commitments to deliver approximately 530 bcf through September 2021 to third-party midstream companies.

 

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

 

Net Acreage Maintenance Commitments

Under the terms of our joint development agreements with our joint venture partners, Statoil and Total (see Note 8), we are required to extend, renew or replace certain expiring joint leasehold, at our cost, to ensure that the net acreage is maintained in certain designated areas.

Other Commitments

As of September 30, 2010, we had made commitments to acquire additional leasehold in various transactions during the next twelve months for approximately $1.7 billion, including the acquisition of a significant additional position in the Appalachian Basin from privately-held Anschutz Corporation which is expected to close in November 2010.

 

4.

Net Income Per Share

Accounting guidance for earnings per share (EPS) requires presentation of “basic” and “diluted” earnings per share on the face of the statements of operations for all entities with complex capital structures as well as a reconciliation of the numerator and denominator of the basic and diluted EPS computations.

For the Current Quarter and the Current Period, no securities were antidilutive in the calculation of diluted EPS. The following securities and associated adjustments to net income comprised of dividends and losses on conversions/exchanges were not included in the calculation of diluted EPS for the Prior Quarter and the Prior Period, as the effect was antidilutive.

 

    Shares     Net Income
Adjustments
 
      (in millions)         ($ in millions)    

Three Months Ended September 30, 2009:

   

Common stock equivalent of our preferred stock outstanding:

   

5.00% cumulative convertible preferred stock (series 2005B)

    5                  $ 3           

4.50% cumulative convertible preferred stock

    6                  $ 3           

Nine Months Ended September 30, 2009:

   

Common stock equivalent of our preferred stock outstanding:

   

5.00% cumulative convertible preferred stock (series 2005B)

    5                  $ 8           

4.50% cumulative convertible preferred stock

    6                  $ 9           

Common stock equivalent of our preferred stock outstanding prior to conversion:

   

6.25% mandatory convertible preferred stock

    1                  $ 1           

Outstanding stock options

    1                  $ —           

Unvested restricted stock

    5                  $ —           

For the Prior Period, as a result of the net loss to Chesapeake common stockholders, there was no difference between basic weighted average shares outstanding, which are used in computing basic EPS, and diluted weighted average shares, which are used in computing EPS assuming dilution.

 

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

 

A reconciliation of basic EPS and diluted EPS for the Current Quarter, the Prior Quarter and the Current Period is as follows:

 

    Income
 (Numerator) 
    Weighted
Average
Shares
 (Denominator) 
     Per Share 
Amount
 
    (in millions, except per share data)  

Three Months Ended September 30, 2010:

     

Basic EPS

  $ 515        632      $ 0.81   
                       

Effect of Dilutive Securities:

     

Assumed conversion as of the beginning of the period of preferred shares outstanding during the period:

     

Common shares assumed issued for 5.75% cumulative convertible preferred stock

    21        56     

Common shares assumed issued for 5.75% cumulative convertible preferred stock (series A)

    16        40     

Common shares assumed issued for 5.00% cumulative convertible preferred stock (series 2005B)

    2        5     

Common shares assumed issued for 4.50% cumulative convertible preferred stock

    3        6     

Outstanding stock options

           1     

Unvested restricted stock

           4     
                 

Diluted EPS

  $ 557        744      $ 0.75   
                       

Three Months Ended September 30, 2009:

     

Basic EPS

  $ 186        619      $ 0.30   
                       

Effect of Dilutive Securities:

     

Outstanding stock options

           1     

Unvested restricted stock

           6     
                 

Diluted EPS

  $ 186        626      $ 0.30   
                       

Nine Months Ended September 30, 2010:

     

Basic EPS

  $ 1,482        631      $ 2.35   
                       

Effect of Dilutive Securities:

     

Assumed conversion as of the beginning of the period of preferred shares outstanding during the period:

     

Common shares assumed issued for 5.75% cumulative convertible preferred stock

    28        24     

Common shares assumed issued for 5.75% cumulative convertible preferred stock (series A)

    23        20     

Common shares assumed issued for 5.00% cumulative convertible preferred stock (series 2005B)

    8        5     

Common shares assumed issued for 4.50% cumulative convertible preferred stock

    9        6     

Outstanding stock options

           1     

Unvested restricted stock

           5     
                 

Diluted EPS

  $ 1,550        692      $ 2.24   
                       

 

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

 

5.

Stockholders’ Equity, Restricted Stock and Stock Options

Common Stock

The following is a summary of the changes in our common shares issued for the nine months ended September 30, 2010 and 2009:

 

       2010        2009  
       (in thousands)  

Shares issued at January 1

       648,549           607,953   

Restricted stock issuances (net of forfeitures)

       6,108           3,940   

Stock option exercises

       354           429   

Convertible note exchanges

       299           6,707   

Preferred stock conversions/exchanges

       21           1,422   

Common stock issued for the purchase of proved and unproved properties

                 24,823   
                     

Shares issued at September 30

           655,331               645,274   
                     

In the Current Period, we privately exchanged approximately $11 million in aggregate principal amount of our 2.25% Contingent Convertible Senior Notes due 2038 for an aggregate of 298,500 shares of our common stock valued at approximately $9 million. Through these transactions, we were able to retire this debt for common stock valued at approximately 80% of the face value of the notes. In connection with accounting guidance for debt with conversion and other options, we are required to account for the liability and equity components of our convertible debt instruments separately. Of the $11 million principal amount of convertible notes exchanged in the Current Period, $7 million was allocated to the debt component of the notes and the remaining $4 million was allocated to the equity conversion feature of the notes and was recorded as an adjustment to paid-in-capital. The difference between the debt component and value of the common stock exchanged in these transactions resulted in a $2 million loss (including a nominal amount of deferred charges associated with the exchanges).

In the Prior Period, we privately exchanged approximately $238 million in aggregate principal amount of our 2.25% Contingent Convertible Senior Notes due 2038 for an aggregate of 6,707,321 shares of our common stock valued at approximately $164 million. Through these transactions, we were able to retire this debt for common stock valued at approximately 70% of the face value of the notes. Of the $238 million principal amount of convertible notes exchanged in the Prior Period, $148 million was allocated to the debt component of the notes and the remaining $90 million was allocated to the equity conversion feature of the notes and was recorded as an adjustment to paid-in-capital. The difference between the debt component and value of the common stock exchanged in these transactions resulted in a $19 million loss (including $3 million of deferred charges associated with the exchanges that were written off).

In the Prior Period, pursuant to an acquisition shelf registration statement, we issued 24,822,832 shares of common stock valued at $429 million for the purchase of proved and unproved properties.

 

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

 

Preferred Shares

The following is a summary of the changes in our preferred shares outstanding for the nine months ended September 30, 2010 and 2009:

 

          5.75%       5.75%(A)       4.50%       5.00%
  (2005B)  
    5.00%
  (2005)  
      6.25%         4.125%    
        (in thousands)      

Shares outstanding at January 1, 2010

                    2,559        2,096        5                 

Preferred stock issuances

      1,500        1,100                                      

Conversion of preferred into common stock

                                  (5              
                                                         

Shares outstanding at September 30, 2010

      1,500        1,100        2,559        2,096                        
                                                         

Shares outstanding at January 1, 2009

                    2,559        2,096        5        144        3   

Conversion of preferred into common stock

                                         (144     (3
                                                         

Shares outstanding at September 30, 2009

                    2,559        2,096        5                 
                                                         

On May 17, 2010, we issued 600,000 shares of 5.75% Cumulative Convertible Non-Voting Preferred Stock, par value $0.01 per share and liquidation preference $1,000 per share, in a private placement for net proceeds of approximately $594 million. We also granted an option to such purchasers to place additional shares of the preferred stock. Upon the exercise of the placement option, we issued an additional 900,000 shares of 5.75% Cumulative Convertible Non-Voting Preferred Stock on June 18, 2010 for net proceeds of approximately $877 million.

On May 17, 2010, we issued 1,100,000 shares of 5.75% Cumulative Convertible Non-Voting Preferred Stock (Series A), par value $0.01 per share and liquidation preference $1,000 per share, in a private placement for net proceeds of approximately $1.091 billion.

On May 3, 2010, we converted all 5,000 shares of our outstanding 5.00% Cumulative Convertible Preferred Stock (Series 2005) into 20,774 shares of common stock pursuant to the company’s mandatory conversion rights.

On June 15, 2009, we converted all 143,768 shares of our outstanding 6.25% Mandatory Convertible Preferred Stock into 1,239,538 shares of common stock pursuant to the company's mandatory conversion rights.

On March 31, 2009, we converted all 3,033 shares of our outstanding 4.125% Cumulative Convertible Preferred Stock into 182,887 shares of common stock pursuant to the company’s mandatory conversion rights.

Dividends

Dividends declared on our common stock and preferred stock are reflected as adjustments to retained earnings to the extent a surplus of retained earnings will exist after giving effect to the dividends. To the extent retained earnings are insufficient to fund the distributions, such payments constitute a return of contributed capital rather than earnings and are accounted for as a reduction to paid-in capital.

 

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

 

Stock-Based Compensation

Chesapeake’s stock-based compensation programs consist of restricted stock issued to employees and non-employee directors. To the extent compensation cost relates to employees directly involved in natural gas and oil exploration and development activities, such amounts are capitalized to natural gas and oil properties. Amounts not capitalized are recognized as general and administrative expenses, production expenses, marketing, gathering and compression expenses, service operations expense or restructuring costs. We recorded the following stock-based compensation during the Current Quarter, the Prior Quarter, the Current Period and the Prior Period:

 

      Three Months Ended  
September 30,
      Nine Months Ended  
September 30,
 
    2010     2009     2010     2009  
    ($ in millions)  

Natural gas and oil properties

  $ 30      $ 27      $ 95      $ 85   

General and administrative expenses

    21        22        63        60   

Production expenses

    9        8        27        26   

Marketing, gathering and compression expenses

    5        4        13        12   

Service operations expense

    2        2        7        6   

Restructuring costs

                         9   
                               

Total

  $ 67      $ 63      $ 205      $ 198   
                               

Restricted Stock. Chesapeake regularly issues shares of restricted common stock to employees and to non-employee directors. The fair value of the awards issued is determined based on the fair market value of the shares on the date of grant. This value is amortized over the vesting period, which is generally four or five years from the date of grant for employees and three years for non-employee directors.

A summary of the changes in unvested shares of restricted stock for the nine months ended September 30, 2010 is presented below:

 

    Number of
Unvested
Restricted
Shares
      Weighted-Average  
Grant-Date
Fair Value
   
      (in thousands)            

Unvested shares as of January 1, 2010

    19,225      $ 31.89  

Granted

    8,901      $ 24.21  

Vested

    (5,332   $ 32.49  

Forfeited

    (885   $ 30.49  
           

Unvested shares as of September 30, 2010

    21,909      $ 28.68  
           

The aggregate intrinsic value of restricted stock vested during the Current Period was approximately $124 million based on the stock price at the time of vesting.

As of September 30, 2010, there was $425 million of total unrecognized compensation cost related to unvested restricted stock. The cost is expected to be recognized over a weighted average period of 2.4 years.

The vesting of certain restricted stock grants results in state and federal income tax benefits related to the difference between the market price of the common stock at the date of vesting and the date of grant. During the Current Quarter, the Prior Quarter, the Current Period and the Prior Period, we recognized a reduction in tax benefits related to restricted stock of $14 million, $36 million, $15 million and $48 million, respectively, which were recorded as adjustments to additional paid-in capital and deferred income taxes.

Stock Options. We granted stock options prior to 2006 under several stock compensation plans. Outstanding options expire ten years from the date of grant and vested over a four-year period. All stock options outstanding are fully vested and exercisable.

 

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(Unaudited)

 

 

The following table provides information related to stock option activity for the nine months ended September 30, 2010:

 

    Number of
Shares
Underlying
Options
    Weighted
Average
Exercise
Price
 Per Share 
    Weighted
Average
Contract

 Life in Years 
      Aggregate
Intrinsic
Value(a)
   
     (in thousands)                     ($ in millions)     

Outstanding at January 1, 2010

    2,283        $ 8.36        2.75     $        40  

Exercised

    (366     $ 6.15             

Expired

           $ —             
                 

Outstanding at September 30, 2010

    1,917        $ 8.78        2.22     $        27  
                 

Exercisable at September 30, 2010

    1,917        $ 8.78        2.22     $        27  
                 

 

(a)

The intrinsic value of a stock option is the amount by which the current market value or the market value upon exercise of the underlying stock exceeds the exercise price of the option.

During the Current Quarter, the Prior Quarter, the Current Period and the Prior Period we recognized excess tax benefits related to stock options of $1 million, $1 million, $2 million and $1 million which were recorded as adjustments to additional paid-in capital and deferred income taxes.

 

6.

Debt

Our total debt consisted of the following at September 30, 2010 and December 31, 2009:

 

    September 30,
2010
    December 31,
2009
 
    ($ in millions)  

7.5% senior notes due 2013

  $      $ 364   

7.625% senior notes due 2013

    500        500   

7.0% senior notes due 2014

           300   

7.5% senior notes due 2014

           300   

6.375% senior notes due 2015

           600   

9.5% senior notes due 2015

    1,425        1,425   

6.625% senior notes due 2016

           600   

6.875% senior notes due 2016

           670   

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

    816        860   

6.5% senior notes due 2017

    1,100        1,100   

6.25% senior notes due 2018

           600   

6.875% senior notes due 2018

    600          

7.25% senior notes due 2018

    800        800   

6.625% senior notes due 2020

    1,400          

6.875% senior notes due 2020

    500        500   

2.75% contingent convertible senior notes due 2035(b)

    451        451   

2.5% contingent convertible senior notes due 2037(b)

    1,378        1,378   

2.25% contingent convertible senior notes due 2038(b)

    752        763   

Corporate revolving bank credit facility

    2,237        1,892   

Midstream revolving bank credit facility

    250          

Midstream joint venture revolving bank credit facility(c)

           44   

Discount on senior notes(d)

    (800     (921

Interest rate derivatives(e)

    36        69   
               

Total notes payable and long-term debt

  $ 11,445      $ 12,295   
               

 

(a)

The principal amount shown is based on the dollar/euro exchange rate of $1.3601 to 1.00 and $1.4332 to 1.00 as of September 30, 2010 and December 31, 2009, respectively. See Note 2 for information on our related foreign currency derivatives.

 

(b)

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

 

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(Unaudited)

 

 

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 third quarter of 2010, 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 fourth quarter of 2010 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

  $          48.71  

   May 14, 2016

        2.5% due 2037

 

   May 15, 2017, 2022, 2027, 2032

  $          64.26  

   November 14, 2017  

        2.25% due 2038        

 

   December 15, 2018, 2023, 2028, 2033

  $        107.36  

   June 14, 2019

 

(c)

Effective January 1, 2010, our midstream joint venture was no longer consolidated in accordance with the new authoritative guidance. See Notes 1 and 9 for further details.

 

(d)

Included in this discount is $731 million at September 30, 2010 and $794 million at December 31, 2009 associated with the equity component of our contingent convertible senior notes.

 

(e)

See Note 2 for discussion related to these instruments.

Senior Notes

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. Chesapeake is a holding company and owns no operating assets and has no significant operations independent of its subsidiaries. Our senior note obligations are guaranteed by certain of our wholly owned subsidiaries. See Note 12 for condensed consolidating financial information regarding our guarantor and non-guarantor subsidiaries. We may redeem the senior notes, other than the contingent convertible senior notes, at any time at specified make-whole or redemption prices. Our senior notes are governed by indentures containing covenants that limit our ability and our subsidiaries’ ability to incur certain secured indebtedness; enter into sale/leaseback transactions; and consolidate, merge or transfer assets.

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

On June 21, 2010, we redeemed in whole for an aggregate redemption price of approximately $1.366 billion, plus accrued interest, approximately $364 million in principal amount of our outstanding 7.50% Senior Notes due 2013, $300 million in principal amount of our 7.50% Senior Notes due 2014 and approximately $670 million in principal amount of our 6.875% Senior Notes due 2016. Associated with the redemptions, we recognized a loss of $69 million in the Current Period.

On July 22, 2010, we redeemed in whole for a redemption price of approximately $619 million, plus accrued interest, all $600 million in principal amount of our 6.375% Senior Notes due 2015. Associated with the redemption, we recognized a loss of $19 million in the Current Quarter.

On August 3, 2010, we filed a shelf registration statement on Form S-3 with the SEC for the offering from time to time of debt securities.

 

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On August 17, 2010, we completed a public offering of $2.0 billion aggregate principal amount of senior notes for net proceeds of approximately $1.967 billion. The offering consisted of $600 million of 6.875% Senior Notes due 2018 and $1.4 billion of 6.625% Senior Notes due 2020. Both series were priced at par.

On August 30, 2010, we completed tender offers to purchase for cash $245 million of 7.00% Senior Notes due 2014, $567 million of 6.625% Senior Notes due 2016 and $582 million of 6.25% Senior Notes due 2018. On September 16, 2010, we redeemed the remaining $55 million of 7.00% Senior Notes due 2014, $33 million of 6.625% Senior Notes due 2016 and $18 million of 6.25% Senior Notes due 2018 based on the redemption provisions in the indentures. Associated with the tender offers and redemptions, we recognized a loss of $40 million in the Current Quarter.

During the Current Period, holders of our 2.25% Contingent Convertible Senior Notes due 2038 exchanged approximately $11 million in aggregate principal amount for an aggregate of 298,500 shares of our common stock in privately negotiated exchanges. Associated with these exchanges, we recognized a loss of $2 million in the Current Period.

No scheduled principal payments are required under our senior notes until 2013 when $500 million is due.

Bank Credit Facilities

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

 

   

Corporate
Credit Facility(a)

     

Midstream
Credit Facility(b)

    ($ in millions)

Borrowing capacity

  $        3,500     $        300

Maturity date

  November 2012     July 2015

Facility structure

    Senior secured revolving         Senior secured revolving  

Amount outstanding as of September 30, 2010

  $        2,237     $        250

Letters of credit outstanding as of September 30, 2010

  $            13     $          —

 

(a)

Borrowers are Chesapeake Exploration, L.L.C. and Chesapeake Appalachia, L.L.C.

 

(b)

Borrower is Chesapeake Midstream Operating, L.L.C., a wholly owned subsidiary of Chesapeake Midstream Development, L.P.

Our credit facilities do not contain material adverse change or adequate assurance covenants. Although the applicable interest rates under our corporate credit facility fluctuate slightly based on our long-term senior unsecured credit ratings, neither of our credit facilities contains 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.

Corporate Credit Facility

Our $3.5 billion syndicated revolving bank credit facility is used for general corporate purposes. Borrowings under the facility are secured by natural gas and oil proved reserves and bear interest at our option at either (i) the greater of the reference rate of Union Bank, N.A. or the federal funds effective rate plus 0.50%, both of which are subject to a margin that varies from 0.00% to 0.75% per annum according to our senior unsecured long-term debt ratings, or (ii) the London Interbank Offered Rate (LIBOR), plus a margin that varies from 1.50% to 2.25% per annum according to our senior unsecured long-term debt ratings. The collateral value and borrowing base are determined periodically. The unused portion of the facility is subject to a commitment fee of 0.50%. Interest is payable quarterly or, if LIBOR applies, it may be payable at more frequent intervals.

The credit facility agreement contains various covenants and restrictive provisions which limit our ability to incur additional indebtedness, make investments or loans and create liens and require us to maintain an indebtedness to total capitalization ratio and an indebtedness to EBITDA ratio, in each case as defined in the agreement. We were in compliance with all covenants under the agreement at September 30, 2010. 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 $50 million or more, would constitute an event of default under our senior note indentures, which could in turn result in the acceleration of a significant portion of our senior note indebtedness. The

 

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credit facility agreement also has cross default provisions that apply to other indebtedness of Chesapeake and its restricted subsidiaries with an outstanding principal amount in excess of $75 million.

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

Midstream Credit Facility

Our $300 million midstream syndicated revolving bank credit facility is used to fund capital expenditures to build natural gas gathering and other systems for our drilling program and for general corporate purposes associated with our midstream operations. Borrowings under the midstream credit facility are secured by all of the assets of the wholly owned subsidiaries (the restricted subsidiaries) of Chesapeake Midstream Development, L.P. (CMD), itself a wholly owned subsidiary of Chesapeake, and bear interest at our option at either (i) the greater of the reference rate of Wells Fargo Bank, National Association, the federal funds effective rate plus 0.50%, and the one-month LIBOR plus 1.00%, all of which are subject to a margin that varies from 1.75% to 2.25% per annum according to the most recent leverage ratio described below or (ii) the LIBOR plus a margin that varies from 2.75% to 3.25% per annum according to the most recent leverage ratio. The unused portion of the facility is subject to a commitment fee of 0.50% per annum according to the most recent leverage ratio. Interest is payable quarterly or, if LIBOR applies, it may be payable at more frequent intervals.

The midstream credit facility agreement contains various covenants and restrictive provisions which limit the ability of CMD and its restricted subsidiaries to incur additional indebtedness, make investments or loans and create liens. The agreement requires maintenance of a leverage ratio based on the ratio of indebtedness to EBITDA and an interest coverage ratio based on the ratio of EBITDA to interest expense, in each case as defined in the agreement. The leverage ratio increases during any three-quarter period, beginning in the quarter in which CMD makes a material disposition of assets to our master limited partnership midstream affiliate, Chesapeake Midstream Partners, L.P. We were in compliance with all covenants under the agreement at September 30, 2010. If CMD or its restricted subsidiaries should fail to perform their obligations under these and other covenants, the revolving credit commitment could be terminated and any outstanding borrowings under the facility could be declared immediately due and payable. The midstream credit facility agreement also has cross default provisions that apply to other indebtedness CMD and its restricted subsidiaries may have with an outstanding principal amount in excess of $15 million.

Other Financings

In 2009, we financed 113 real estate surface assets in the Barnett Shale area for approximately $145 million and entered into a 40-year master lease agreement under which we agreed to lease the sites for approximately $15 million to $27 million annually. This lease transaction was recorded as a financing lease and the cash received was recorded with an offsetting long-term liability on the condensed consolidated balance sheet. Chesapeake exercised its option to repurchase two of the assets in the Current Period. As of September 30, 2010, 111 assets were leased and the minimum aggregate undiscounted future lease payments were approximately $832 million.

In 2009, we financed our regional Barnett Shale headquarters building in Fort Worth, Texas for net proceeds of approximately $54 million with a five-year term loan which has a floating rate of prime plus 275 basis points. At our option, we may prepay in full without penalty beginning in year four. The payment obligation is guaranteed by Chesapeake.

 

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(Unaudited)

 

 

7.

Segment Information

In accordance with accounting guidance for disclosures about segments of an enterprise and related information, we have two reportable operating segments. Our exploration and production operational segment and natural gas and oil midstream segment are managed separately because of the nature of their products and services. The exploration and production segment is responsible for finding and producing natural gas and oil. The midstream segment is responsible for marketing, gathering and compression of natural gas and oil primarily from Chesapeake-operated wells. We also have drilling rig and trucking operations which are responsible for providing drilling rigs primarily used on Chesapeake-operated wells and trucking services utilized in the transportation of drilling rigs on both Chesapeake-operated wells and wells operated by third parties. Our drilling rig and trucking service operations are presented in “Other Operations” in the table below.

Management evaluates the performance of our segments based upon income (loss) before income taxes. Revenues from the midstream segment’s sale of natural gas and oil related to Chesapeake’s ownership interests are reflected as exploration and production revenues. Such amounts totaled $1.045 billion, $716 million, $2.978 billion and $2.009 billion for the Current Quarter, the Prior Quarter, the Current Period and the Prior Period. The following table presents selected financial information for Chesapeake’s operating segments.

 

    Exploration
and
    Production    
     Midstream      Other
    Operations     
      Intercompany  
Eliminations
     Consolidated 
Total
 
    ($ in millions)  

Three Months Ended September 30, 2010:

         

Revenues

  $ 1,639      $ 1,928      $ 187      $ (1,173   $ 2,581   

Intersegment revenues

           (1,045     (128     1,173          
                                       

Total revenues

  $ 1,639      $ 883      $ 59      $      $ 2,581   
                                       

Income (loss) before income taxes

  $ 822      $ 96      $ (7   $ (4   $ 907   
                                       

Three Months Ended September 30, 2009:

         

Revenues

  $ 1,187      $ 1,291      $ 69      $ (736   $ 1,811   

Intersegment revenues

           (716     (20     736          
                                       

Total revenues

  $ 1,187      $ 575      $ 49      $      $ 1,811   
                                       

Income (loss) before income taxes

  $ 431      $ (111   $ (19   $ 6      $ 307   
                                       

Nine Months Ended September 30, 2010:

         

Revenues

  $ 4,698      $ 5,498      $ 538      $ (3,343   $ 7,391   

Intersegment revenues

           (2,978     (365     3,343          
                                       

Total revenues

  $ 4,698      $ 2,520      $ 173      $      $ 7,391   
                                       

Income (loss) before income taxes

  $ 2,401      $ 152      $ (32   $ (1   $ 2,520   
                                       

Nine Months Ended September 30, 2009:

         

Revenues

  $ 3,681      $ 3,669      $ 338      $ (2,208   $ 5,480   

Intersegment revenues

           (2,009     (199     2,208          
                                       

Total revenues

  $ 3,681      $ 1,660      $ 139      $      $ 5,480   
                                       

Income (loss) before income taxes

  $ (8,354   $ (82   $ (53   $ (1   $ (8,490
                                       

As of September 30, 2010:

         

Total assets

  $ 30,945      $ 3,481      $ 721      $ (814   $ 34,333   

As of December 31, 2009:

         

Total assets

  $ 25,637      $ 4,323      $ 660      $ (706   $ 29,914   

 

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(Unaudited)

 

 

8.

Divestitures

Joint Ventures

In January 2010, Chesapeake and Total E&P USA, Inc., a wholly owned subsidiary of Total S.A., closed a $2.25 billion Barnett Shale joint venture transaction, whereby Total acquired a 25% interest in our upstream Barnett Shale assets. Total paid us approximately $800 million in cash at closing (plus $78 million of drilling and completion carries due from the effective date of the transaction to the closing date) and is obligated to pay a total of $1.45 billion over time by funding 60% of our share of future drilling and completion expenditures. We expect this drilling carry to be fully utilized by year-end 2013.

During the Current Period and Prior Period, our drilling and completion costs included the benefit of approximately $745 million and $959 million, respectively, in drilling and completion carries associated with our shale play joint ventures with Total, Statoil, BP America and Plains Exploration & Production Company as follows:

 

Shale

Play

 

Joint Venture

Partner

 

Joint Venture

Date

  Nine Months Ended
September  30,
 
              2010                     2009          
            ($ in millions)  

Barnett

  Total   January 2010   $ 349      $   

Marcellus

  Statoil   November 2008     396        85   

Fayetteville

  BP   September 2008            524   

Haynesville

  Plains   July 2008            350   
                   
      $ 745      $ 959   
                   

During the Current Period, as part of our joint venture agreements with Total, Statoil and Plains, we sold interests in additional leasehold in the Barnett, Marcellus and Haynesville shale plays for approximately $395 million.

For accounting purposes, cash proceeds from these joint venture transactions were reflected as a reduction of natural gas and oil properties with no gain or loss recognized.

Volumetric Production Payments

On February 5, 2010, we sold certain Chesapeake-operated long-lived producing assets in East Texas and the Texas Gulf Coast in our sixth volumetric production payment (VPP) transaction for net proceeds of approximately $180 million, or $3.95 per mcfe.

On June 14, 2010, we sold certain Chesapeake-operated long-lived producing assets in the Permian Basin in our seventh VPP transaction for proceeds of approximately $335 million, or $8.73 per mcfe.

On September 30, 2010, we sold certain Chesapeake-operated long-lived producing assets in the Barnett Shale in our eighth VPP transaction for proceeds of approximately $1.15 billion, or $2.93 per mcfe.

For accounting purposes, cash proceeds from these transactions were reflected as a reduction of natural gas and oil properties with no gain or loss recognized, and our proved reserves were reduced accordingly.

Other Divestitures

In the Current Period, we sold producing properties and gathering systems in Virginia and in the Permian Basin for proceeds of approximately $330 million.

 

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(Unaudited)

 

 

9.

Investments

At September 30, 2010, investments accounted for under the equity method totaled $1.160 billion and investments accounted for under the cost method totaled $29 million. Following is a summary of our investments:

 

                Carrying Value  
    Approximate %
Owned
    Accounting
Method
    September 30,
2010
    December 31,
2009
 
                ($ in millions)  

Chesapeake Midstream Partners, L.P.

    42%        Equity      $ 666      $   

Frac Tech Services, LLC

    26%        Equity        347        239   

Chaparral Energy, Inc.

    20%        Equity        137        103   

Gastar Exploration Ltd.

    14%        Cost        27        32   

Other(a)

    —           Cost/Equity        12        30   
                   
      $ 1,189      $ 404   
                   

 

(a)

In the Current Quarter, we recorded a $16 million impairment of certain other equity investments.

Chesapeake Midstream Partners, L.P. On September 30, 2009, we formed a joint venture with Global Infrastructure Partners (GIP), a New York-based private equity fund, to own and operate natural gas midstream assets. As part of the transaction, Chesapeake contributed certain natural gas gathering and processing assets to, and GIP purchased a 50% interest in, a new joint venture entity. The assets we contributed to the joint venture were substantially all of our midstream assets in the Barnett Shale and also the majority of our non-shale midstream assets in the Arkoma, Anadarko, Delaware and Permian Basins. During the fourth quarter of 2009, the joint venture was consolidated within our financial statements. Effective January 1, 2010, in accordance with new authoritative guidance for variable interest entities, we changed the accounting for our investment in the joint venture to the equity method. Adoption of this new guidance resulted in an after-tax cumulative effect charge to retained earnings of $142 million, which is reflected in our condensed consolidated statement of equity for the Current Period. This charge reflects the difference between the carrying value of our initial investment in the joint venture, which was recorded at carryover basis as an entity under common control, and the fair value of our equity in the joint venture as of the formation date. In May 2010, we received a $75 million cash distribution from the joint venture. The carrying value of our investment in the joint venture is less than our underlying equity in net assets by approximately $240 million as of September 30, 2010. This difference is being accreted over 20 years.

On August 3, 2010, Chesapeake Midstream Partners, L.P. (NYSE: CHKM), which we and GIP formed to own, operate, develop and acquire midstream assets, completed an initial public offering of 24,437,500 common units (including 3,187,500 common units issued pursuant to the exercise of the underwriters' over-allotment option on August 3, 2010) representing limited partner interests and received gross offering proceeds of approximately $513 million at an initial offering price of $21.00 per unit less approximately $38 million for underwriting discounts and commissions, structuring fees and offering expenses. Pursuant to the terms of our contribution agreement with GIP, CHKM distributed the approximate $62 million of net proceeds from the exercise of the over-allotment option to GIP on August 3, 2010. In connection with the closing of the offering, Chesapeake and GIP contributed the interests of the midstream joint venture's operating subsidiary to CHKM, and CHKM is continuing the business that had been conducted by the joint venture. Common units owned by public security holders represent 17.7% of all outstanding limited partner interests, and Chesapeake and GIP hold 42.3% and 40.0%, respectively, of all outstanding limited partner interests. The limited partners, collectively, have a 98.0% interest in CHKM and the general partner, which is owned and controlled 50/50 by Chesapeake and GIP, has a 2.0% interest in CHKM.

As a result of the initial public offering by CHKM, we recognized a $90 million gain on our investment in the Current Quarter. This gain represented our proportionate share of the excess of offering proceeds over the carrying value of our investment in CHKM.

Frac Tech Services, LLC. The carrying value of our investment in Frac Tech is in excess of our underlying equity in net assets by approximately $190 million as of September 30, 2010. This excess amount is attributed to certain intangibles associated with the specialty services provided by Frac Tech and is being amortized over the estimated life of the intangibles.

Chaparral Energy, Inc. The carrying value of our investment in Chaparral is in excess of our underlying equity in net assets by approximately $61 million as of September 30, 2010. This excess is attributed to the natural gas and oil reserves held by Chaparral and is being amortized over the estimated life of these reserves based on a unit of production rate.

 

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As a result of an additional equity offering by Chaparral to a third party, we recognized a $31 million gain on our investment in the Current Quarter. This gain represented our proportionate share of the excess of offering proceeds over the carrying value of our investment in Chaparral.

 

10.

Restructuring

In the Prior Period, we restructured our Charleston, West Virginia-based Eastern Division from a regional corporate headquarters to a regional field office consistent with the business model the company uses elsewhere in the country. As a result, we consolidated the management of our Eastern Division land, legal, accounting, information technology, geoscience and engineering departments into our corporate offices in Oklahoma City. The costs of the reorganization include termination benefits, consolidating or closing facilities and relocating employees. In addition, we had certain other workforce reductions that resulted in termination benefits. A summary of Chesapeake’s restructuring cost is presented below:

 

   

    Nine Months Ended      

    September 30, 2009      

    ($ in millions)    
 

Termination and relocation costs

  $              22     
 

Acceleration of restricted stock awards

    9     
 

Other associated costs

    3     
           
 

Total Restructuring Costs

  $ 34     
           

 

11.

Fair Value Measurements

Certain financial instruments are reported at fair value on the condensed consolidated balance sheets. Under fair value measurement accounting guidance, fair value is defined as the amount that would be received from the sale of an asset or paid for the transfer of a liability in an orderly transaction between market participants, i.e., an exit price. To estimate an exit price, a three-level hierarchy is used. The fair value hierarchy prioritizes the inputs, which refer broadly to assumptions market participants would use in pricing an asset or a liability, into three levels. Level 1 inputs are unadjusted quoted prices in active markets for identical assets and liabilities and have the highest priority. Level 2 inputs are inputs other than quoted prices within Level 1 that are observable for the asset or liability, either directly or indirectly. Level 3 inputs are unobservable inputs for the financial asset or liability and have the lowest priority. Chesapeake uses a market valuation approach based on available inputs and the following methods and assumptions to measure the fair values of its assets and liabilities, which may or may not be observable in the market.

Cash Equivalents. The fair value of cash equivalents is based on quoted market prices.

Investments. The fair value of Chesapeake’s investment in Gastar Exploration Ltd. (NYSE Amex: GST) common stock is based on a quoted market price.

Other Long-Term Assets and Liabilities. The fair value of other long-term assets and liabilities, consisting of obligations under our Deferred Compensation Plan, is based on quoted market prices.

Derivatives. The fair values of our commodity derivatives are based on a third-party pricing model which utilizes inputs that are either readily available in the public market, such as natural gas and oil forward curves and discount rates, or can be corroborated from active markets or broker quotes. These values are then compared to the values given by our counterparties for reasonableness. Since the commodity swaps do not have options and therefore no unobservable inputs, they are classified as Level 2. All other commodity derivatives have some level of unobservable input, such as volatility curves, and are therefore classified as Level 3. For interest rate and foreign currency derivatives, we use the fair value estimates provided by our respective counterparties, which are classified as Level 3 inputs. These values are reviewed internally for reasonableness using future interest rate curves and time to maturity. Derivatives are also subject to the risk that counterparties will be unable to meet their obligations. We factor in non-performance risk in the valuation of our derivatives using current published credit default swap rates. To date this has not had a material impact on the values of our derivatives.

Debt. The fair value of certain of our long-term debt is based on the face amount of that debt along with the value of related interest rate swaps.

 

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(Unaudited)

 

 

The following table provides fair value measurement information for financial assets (liabilities) measured at fair value on a recurring basis as of September 30, 2010:

 

    Quoted
    Prices in     
Active
Markets
(Level 1)
    Significant
Other
  Observable  
Inputs
(Level 2)
    Significant
 Unobservable 
Inputs
(Level 3)
    Total
    Fair Value     
 
    ($ in millions)  

Financial Assets (Liabilities):

       

Cash equivalents

  $ 609      $      $      $ 609   

Investments

    27                      27   

Other long-term assets

    42                      42   

Long-term debt

                  (816     (816

Other long-term liabilities

    (42                   (42

Derivatives:

       

Commodity assets

           1,387        255        1,642   

Commodity liabilities

                  (1,445     (1,445

Interest rate assets

                  29        29   

Interest rate liabilities

                  (68     (68

Foreign currency liabilities

                  (35     (35
                               

Total derivatives

           1,387        (1,264     123   
                               

 

Total

  $ 636      $ 1,387      $ (2,080   $ (57
                               

The following table provides fair value measurement information for financial assets (liabilities) measured at fair value on a recurring basis as of December 31, 2009:

 

    Quoted
    Prices in     
Active
Markets
(Level 1)
    Significant
Other
  Observable  
Inputs
(Level 2)
    Significant
 Unobservable 
Inputs
(Level 3)
    Total
    Fair Value     
 
    ($ in millions)  

Financial Assets (Liabilities):

       

Cash equivalents

  $ 307      $      $      $ 307   

Investments

    32                      32   

Other long-term assets

    34                      34   

Long-term debt

                  (1,398     (1,398

Other long-term liabilities

    (34                   (34

Derivatives:

       

Commodity assets

           693        143        836   

Commodity liabilities

           (1     (809     (810

Interest rate liabilities

                  (132     (132

Foreign currency assets

                  43        43   
                               

Total derivatives

           692        (755     (63
                               

 

Total

  $ 339      $ 692      $ (2,153   $ (1,122
                               

 

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(Unaudited)

 

 

A summary of the changes in Chesapeake’s assets (liabilities) classified as Level 3 measurements during the Current Period and the Prior Period is presented below:

 

    Derivatives        
      Commodity           Interest    
Rate
    Foreign
    Currency     
            Debt          
    ($ in millions)  

Balance of Level 3 as of January 1, 2010

  $ (666   $ (132   $ 43      $ (1,398

Total gains (losses) (realized/unrealized):

       

  Included in earnings (realized)(a)

    305        (6              

  Included in earnings or change in net assets (unrealized)(a)

    (669     85        (44     32   

  Included in other comprehensive income (loss)

    (18            (34       

Purchases, issuances and settlements

    (142     14               550 (b) 

Transfers in and out of Level 3

                           
                               

Balance of Level 3 as of September 30, 2010

  $ (1,190   $ (39   $ (35   $ (816
                               

Balance of Level 3 as of January 1, 2009

  $ 431      $ (63   $ (76   $ (1,470

Total gains (losses) (realized/unrealized):

       

  Included in earnings (realized)(a)

    778        20               (128

  Included in earnings or change in net assets (unrealized)(a)

    (380     106        42          

  Included in other comprehensive income (loss)

    45               78          

Purchases, issuances and settlements

    (835     (154            (450 )(b) 

Transfers in and out of Level 3

                           
                               

Balance of Level 3 as of September 30, 2009

  $ 39      $ (91   $ 44      $ (2,048
                               

 

(a)

Amounts related to commodity derivatives are included in Natural Gas and Oil Sales, and amounts related to interest rate and foreign currency derivatives and debt are included in Interest Expense.

 

(b)

Amount represents a(n) (increase)/decrease in debt recorded at fair value as a result of new or terminated interest rate swaps.

Fair Value of Other Financial Instruments

The following disclosure of the estimated fair value of financial instruments is made in accordance with accounting guidance for financial instruments. We have determined the estimated fair values by using available market information and valuation methodologies. Considerable judgment is required in interpreting market data to develop the estimates of fair value. The use of different market assumptions or valuation methodologies may have a material effect on the estimated fair value amounts.

The carrying values of financial instruments comprising current assets and current liabilities approximate fair values due to the short-term maturities of these instruments. We estimate the fair value of our long-term debt and our convertible preferred stock primarily using quoted market prices. Fair value is compared to the carrying value, excluding the impact of interest rate derivatives, in the table below.

 

    September 30, 2010     December 31, 2009  
        Carrying    
Amount
        Estimated    
Fair Value
        Carrying    
Amount
        Estimated    
Fair Value
 
    ($ in millions)  

Long-term debt

  $ 11,409      $ 12,295      $ 12,226      $ 12,824   

Convertible preferred stock

  $ 3,065      $ 2,994      $ 466      $ 401   

 

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

 

12.

Condensed Consolidating Financial Information

Chesapeake Energy Corporation is a holding company and owns no operating assets and has no significant operations independent of its subsidiaries. Our obligations under our outstanding senior notes and contingent convertible notes listed in Note 6 are fully and unconditionally guaranteed, jointly and severally, by certain of our wholly owned subsidiaries on a senior unsecured basis. Our midstream subsidiary, CMD, is not a guarantor and is subject to covenants in the midstream revolving credit facility referred to in Note 6 that restricts it from paying dividends or distributions or making loans to Chesapeake.

Set forth below are condensed consolidating financial statements for Chesapeake Energy Corporation (parent) on a stand-alone, unconsolidated basis, and its combined guarantor and combined non-guarantor subsidiaries as of September 30, 2010 and December 31, 2009 and for the three and nine months ended September 30, 2010 and 2009. The financial information may not necessarily be indicative of results of operations, cash flows or financial position had the subsidiaries operated as independent entities.

CONDENSED CONSOLIDATING BALANCE SHEET

AS OF SEPTEMBER 30, 2010

 

    Parent     Guarantor
  Subsidiaries  
      Non-Guarantor  
Subsidiaries
        Eliminations           Consolidated    
    ($ in millions)  

CURRENT ASSETS:

         

Cash and cash equivalents

  $      $ 587      $ 22      $      $ 609   

Other

    3        2,549        139        (27     2,664   
                                       

Total Current Assets

    3        3,136        161        (27     3,273   
                                       

PROPERTY AND EQUIPMENT:

         

Natural gas and oil properties, at cost based on full-cost accounting

           24,649        216               24,865   

Other property and equipment, net

           3,029        1,586               4,615   
                                       

Total Property and Equipment

           27,678        1,802               29,480   
                                       

Other assets

    193        715        672               1,580   

Investments in subsidiaries and intercompany advance

    1,356        121               (1,477       
                                       

TOTAL ASSETS

  $             1,552      $ 31,650      $ 2,635      $ (1,504   $ 34,333   
                                       

CURRENT LIABILITIES:

         

Current liabilities

  $ 226      $ 3,816      $ 110      $ (29   $ 4,123   

Intercompany payable (receivable) from parent

    (23,340     21,214        2,145        (19       
                                       

Total Current Liabilities

    (23,114     25,030        2,255        (48     4,123   
                                       

LONG-TERM LIABILITIES:

         

Long-term debt, net

    8,958        2,237        250               11,445   

Deferred income tax liabilities

    392        1,418        8        21        1,839   

Other liabilities

    43        1,609        1               1,653   
                                       

Total Long-Term Liabilities

    9,393        5,264        259        21        14,937   
                                       

EQUITY:

         

Chesapeake stockholders’ equity

    15,273        1,356        121        (1,477     15,273   

Noncontrolling interest

                                  
                                       

Total Equity

    15,273        1,356        121        (1,477     15,273   
                                       

TOTAL LIABILITIES AND EQUITY

  $ 1,552      $ 31,650      $ 2,635      $ (1,504   $ 34,333   
                                       

 

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

 

CONDENSED CONSOLIDATING BALANCE SHEET

AS OF DECEMBER 31, 2009

 

    Parent     Guarantor
  Subsidiaries  
      Non-Guarantor  
Subsidiaries
        Eliminations           Consolidated    
    ($ in millions)  

CURRENT ASSETS:

         

Cash and cash equivalents

  $      $ 293      $ 14      $      $ 307   

Other

    27        2,031        166        (85     2,139   
                                       

Total Current Assets

    27        2,324        180        (85     2,446   
                                       

PROPERTY AND EQUIPMENT:

         

Natural gas and oil properties, at cost based on full-cost accounting

           20,788        4               20,792   

Other property and equipment, net

           2,903        3,015               5,918   
                                       

Total Property and Equipment

           23,691        3,019               26,710   
                                       

Other assets

    197        540        21               758   

Investments in subsidiaries and intercompany advance

    3,029        222               (3,251       
                                       

TOTAL ASSETS

  $             3,253      $ 26,777      $ 3,220      $ (3,336   $ 29,914   
                                       

CURRENT LIABILITIES:

         

Current liabilities

  $ 277      $ 2,261      $ 235      $ (85   $ 2,688   

Intercompany payable (receivable) from parent

    (19,388     17,508        1,793        87          
                                       

Total Current Liabilities

    (19,111     19,769        2,028        2        2,688   
                                       

LONG-TERM LIABILITIES:

         

Long-term debt, net

    10,359        1,892        44               12,295   

Deferred income tax liabilities

    393        727        26        (87     1,059   

Other liabilities

    168        1,360        3               1,531   
                                       

Total Long-Term Liabilities

    10,920        3,979        73        (87     14,885   
                                       

EQUITY:

         

Chesapeake stockholders’ equity

    11,444        3,029        222        (3,251     11,444   

Noncontrolling interest

                  897               897   
                                       

Total Equity

    11,444        3,029        1,119        (3,251     12,341   
                                       

TOTAL LIABILITIES AND EQUITY

  $ 3,253      $ 26,777      $ 3,220      $ (3,336   $ 29,914   
                                       

 

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

 

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

THREE MONTHS ENDED SEPTEMBER 30, 2010

 

    Parent     Guarantor
  Subsidiaries  
      Non-Guarantor  
Subsidiaries
        Eliminations           Consolidated    
    ($ in millions)  

REVENUES:

         

Natural gas and oil sales

  $      $ 1,639      $      $      $ 1,639   

Marketing, gathering and compression sales

           856        69        (42     883   

Service operations revenue

           59                      59   
                                       

Total Revenues

           2,554        69        (42     2,581   
                                       

OPERATING COSTS:

         

Production expenses

           231                      231   

Production taxes

           34                      34   

General and administrative expenses

    2        113        10               125   

Marketing, gathering and compression expenses

           838        37        (24     851   

Service operations expense

           52                      52   

Natural gas and oil depreciation, depletion and amortization

           378                      378   

Depreciation and amortization of other assets

           43        13               56   

Impairment or loss on sale of property and equipment

           3        34               37   
                                       

Total Operating Costs

    2        1,692        94        (24     1,764   
                                       

INCOME (LOSS) FROM OPERATIONS

    (2     862        (25     (18     817   
                                       

OTHER INCOME (EXPENSE):

         

Interest (expense) income

    (153     (16     (1     167        (3

Loss on redemptions or exchanges of Chesapeake debt

    (59                          (59

Impairment of investments

           (16                   (16

Other income (expense)

    167        52        116        (167     168   

Equity in net earnings of subsidiary

    587        44               (631       
                                       

Total Other Income (Expense)

    542        64        115        (631     90   
                                       

INCOME (LOSS) BEFORE INCOME TAXES

    540        926        90        (649     907   

INCOME TAX EXPENSE (BENEFIT)

    (18     339        35        (7     349   
                                       

NET INCOME (LOSS)

    558        587        55        (642     558   

Net income (loss) attributable to noncontrolling interest

                                  
                                       

NET INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE

  $             558      $ 587      $ 55      $ (642   $ 558   
                                       

 

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

 

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

THREE MONTHS ENDED SEPTEMBER 30, 2009

 

            Parent             Guarantor
  Subsidiaries  
     Non-Guarantor 
Subsidiaries
      Eliminations         Consolidated    
    ($ in millions)  

REVENUES:

         

Natural gas and oil sales

  $      $ 1,187      $      $      $ 1,187   

Marketing, gathering and compression sales

           504        126        (55     575   

Service operations revenue

           49                      49   
                                       

Total Revenues

           1,740        126        (55     1,811   
                                       

 

OPERATING COSTS:

         

Production expenses

           218                      218   

Production taxes

           25                      25   

General and administrative expenses

           86        9               95   

Marketing, gathering and compression expenses

           497        54        (5     546   

Service operations expense

           49                      49   

Natural gas and oil depreciation, depletion and amortization

           295                      295   

Depreciation and amortization of other assets

    1        36        25               62   

Loss on sale of other property and equipment

                  124               124   
                                       

Total Operating Costs

    1        1,206        212        (5     1,414   
                                       

INCOME (LOSS) FROM OPERATIONS

    (1     534        (86     (50     397   
                                       

 

OTHER INCOME (EXPENSE):

         

Interest (expense) income

    (161     (57            175        (43

Loss on redemptions or exchanges of Chesapeake debt

    (17                          (17

Other income (expense)

    175        (24     (6     (175     (30

Equity in net earnings of subsidiary

    194        (89            (105       
                                       

Total Other Income (Expense)

    191        (170     (6     (105     (90
                                       

 

INCOME (LOSS) BEFORE INCOME TAXES

    190        364        (92     (155     307   

INCOME TAX EXPENSE (BENEFIT)

    (2     170        (34     (19     115   
                                       

NET INCOME (LOSS)

    192        194        (58     (136     192   

Net income (loss) attributable to noncontrolling interest

                                  
                                       

NET INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE

  $ 192      $ 194      $ (58   $ (136   $ 192   
                                       

 

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

 

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

NINE MONTHS ENDED SEPTEMBER 30, 2010

 

            Parent             Guarantor
  Subsidiaries  
     Non-Guarantor 
Subsidiaries
      Eliminations         Consolidated    
    ($ in millions)  

REVENUES:

         

Natural gas and oil sales

  $      $ 4,698      $      $      $ 4,698   

Marketing, gathering and compression sales

           2,437        179        (96     2,520   

Service operations revenue

           173                      173   
                                       

Total Revenues

           7,308        179        (96     7,391   
                                       

 

OPERATING COSTS:

         

Production expenses

           652                      652   

Production taxes

           119                      119   

General and administrative expenses

    2        315        23               340   

Marketing, gathering and compression expenses

           2,383        90        (44     2,429   

Service operations expense

           154                      154   

Natural gas and oil depreciation, depletion and amortization

           1,025                      1,025   

Depreciation and amortization of other assets

           124        35               159   

Impairment or loss on sale of property and equipment

           3        34               37   
                                       

Total Operating Costs

    2        4,775        182        (44     4,915   
                                       

 

INCOME (LOSS) FROM OPERATIONS

    (2     2,533        (3     (52     2,476   
                                       

 

OTHER INCOME (EXPENSE):

         

Interest (expense) income

    (451     (107     (3     549        (12

Loss on redemptions or exchanges of Chesapeake debt

    (130                          (130

Impairment of investments

           (16                   (16

Other income (expense)

    549        52        150        (549     202   

Equity in net earnings of subsidiary

    1,571        57               (1,628       
                                       

Total Other Income (Expense)

    1,539        (14     147        (1,628     44   
                                       

 

INCOME (LOSS) BEFORE INCOME TAXES

    1,537        2,519        144        (1,680     2,520   

INCOME TAX EXPENSE (BENEFIT)

    (13     948        55        (20     970   
                                       

NET INCOME (LOSS)

    1,550        1,571        89        (1,660     1,550   

Net income (loss) attributable to noncontrolling interest

                                  
                                       

NET INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE

  $ 1,550      $ 1,571      $ 89      $ (1,660   $ 1,550   
                                       

 

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

 

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

NINE MONTHS ENDED SEPTEMBER 30, 2009

 

             Parent             Guarantor
  Subsidiaries  
     Non-Guarantor 
Subsidiaries
      Eliminations         Consolidated    
     ($ in millions)  

REVENUES:

          

Natural gas and oil sales

   $      $ 3,681      $      $      $ 3,681   

Marketing, gathering and compression sales

            1,461        354        (155     1,660   

Service operations revenue

            139                      139   
                                        

Total Revenues

            5,281        354        (155     5,480   
                                        

 

OPERATING COSTS:

          

Production expenses

            670                      670   

Production taxes

            71                      71   

General and administrative expenses

            239        20               259   

Marketing, gathering and compression expenses

            1,436        148        (15     1,569   

Service operations expense

            136                      136   

Natural gas and oil depreciation, depletion and amortization

            1,037                      1,037   

Depreciation and amortization of other assets

            110        67               177   

Impairment of natural gas and oil properties

            9,600                      9,600   

Impairment or loss on sale of other property and equipment

            35        124               159   

Restructuring costs

            34                      34   
                                        

Total Operating Costs

            13,368        359        (15     13,712   
                                        

INCOME (LOSS) FROM OPERATIONS

            (8,087     (5     (140     (8,232
                                        

 

OTHER INCOME (EXPENSE):

          

Interest (expense) income

     (447     (112     (5     512        (52

Loss on redemptions or exchanges of Chesapeake debt

     (19                          (19

Impairment of investments

            (148     (14            (162

Other income (expense)

     512        (21     (4     (512     (25

Equity in net earnings of subsidiary

     (5,335     (105            5,440          
                                        

Total Other Income (Expense)

     (5,289     (386     (23     5,440        (258
                                        

 

INCOME (LOSS) BEFORE INCOME TAXES

     (5,289     (8,473     (28     5,300        (8,490

INCOME TAX EXPENSE (BENEFIT)

     17        (3,138     (11     (52     (3,184
                                        

NET INCOME (LOSS)

     (5,306     (5,335     (17     5,352        (5,306

Net income (loss) attributable to noncontrolling interest

                                   
                                        

NET INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE

   $ (5,306   $ (5,335   $ (17   $ 5,352      $ (5,306
                                        

 

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

 

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

NINE MONTHS ENDED SEPTEMBER 30, 2010

 

            Parent             Guarantor
  Subsidiaries  
     Non-Guarantor 
Subsidiaries
      Eliminations         Consolidated    
    ($ in millions)  

CASH FLOWS FROM OPERATING ACTIVITIES

  $      $ 3,774      $ 197      $      $ 3,971   

 

CASH FLOWS FROM INVESTING ACTIVITIES:

         

Additions to natural gas and oil properties

           (7,723     (212            (7,935

Additions to other property and equipment

           (412     (556            (968

Proceeds from divestitures of natural gas and oil properties

           3,107                      3,107   

Other investing activities

                  131               131   
                                       

Cash used in investing activities

           (5,028     (637            (5,665
                                       

 

CASH FLOWS FROM FINANCING ACTIVITIES:

         

Proceeds from credit facilities borrowings

           10,076        382               10,458   

Payments on credit facilities borrowings

           (9,736     (127            (9,863

Proceeds from preferred stock, net of offering costs

    2,562                             2,562   

Proceeds from issuance of senior notes, net of offering costs

    1,967                             1,967   

Cash paid to redeem Chesapeake debt

    (3,434                          (3,434

Other financing activities

    (243     567        (18            306   

Intercompany advances, net

    (852     641        211                 
                                       

Cash provided by (used in) financing activities

           1,548        448               1,996   
                                       

 

Net increase (decrease) in cash and cash equivalents

           294        8               302   

Cash and cash equivalents, beginning of period

           293        14               307   
                                       

Cash and cash equivalents, end of period

  $      $ 587      $ 22      $      $ 609   
                                       

 

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

 

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

NINE MONTHS ENDED SEPTEMBER 30, 2009

 

            Parent             Guarantor
  Subsidiaries  
     Non-Guarantor 
Subsidiaries
      Eliminations         Consolidated    
    ($ in millions)  

CASH FLOWS FROM OPERATING ACTIVITIES

  $      $ 3,075      $ 56      $      $ 3,131   

 

CASH FLOWS FROM INVESTING ACTIVITIES:

         

Additions to natural gas and oil properties

           (4,138                   (4,138

Additions to other property and equipment

           (661     (701            (1,362

Proceeds from divestitures of natural gas and oil properties

           1,729                      1,729   

Other investing activities

           78        39               117   
                                       

Cash used in investing activities

           (2,992     (662            (3,654
                                       

 

CASH FLOWS FROM FINANCING ACTIVITIES:

         

Proceeds from credit facilities borrowings

           4,894        669               5,563   

Payments on credit facilities borrowings

           (6,749     (1,117            (7,866

Proceeds from issuance of senior notes, net of offering costs

    1,346                             1,346   

Proceeds from sales of noncontrolling interest in midstream joint venture

                  588               588   

Other financing activities

    (153     (167     (17            (337

Intercompany advances, net

    (1,193     554        639                 
                                       

Cash provided by (used in) financing activities

           (1,468     762               (706
                                       

 

Net increase (decrease) in cash and cash equivalents

           (1,385     156               (1,229

Cash and cash equivalents, beginning of period

           1,749                      1,749   
                                       

Cash and cash equivalents, end of period

  $      $ 364      $ 156      $      $ 520   
                                       

 

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

 

13.

Recently Issued and Proposed Accounting Standards

The Financial Accounting Standards Board (FASB) recently issued the following standards which we reviewed to determine the potential impact on our financial statements upon adoption.

In February 2010, the FASB amended its guidance on subsequent events to remove the requirement for SEC filers to disclose the date through which an entity has evaluated subsequent events. The guidance was effective upon issuance. We adopted this guidance in the Current Period.

The FASB also issued new guidance requiring additional disclosures about fair value measurements, adding a new requirement to disclose transfers in and out of Levels 1 and 2 measurements and gross presentation of activity within a Level 3 roll forward. The guidance also clarified existing disclosure requirements regarding the level of disaggregation of fair value measurements and disclosures regarding inputs and valuation techniques. We adopted this guidance in the Current Period. Adoption had no impact on our financial position or results of operations. Required disclosures for the reconciliation of purchases, sales, issuance and settlements of financial instruments valued with a Level 3 method are effective beginning on January 1, 2011, and we do not expect the implementation to have a material impact on our financial position or results of operations. See Note 11 for discussion regarding fair value measurements.

 

14.

Subsequent Events

On October 10, 2010, we entered into an agreement whereby a wholly owned U.S. subsidiary of CNOOC Limited (CNOOC) agreed to purchase a 33.3% undivided interest in 600,000 net oil and natural gas leasehold acres we hold in the Eagle Ford Shale in South Texas. The consideration for the sale will be approximately $1.08 billion in cash at closing. In addition, CNOOC has agreed to fund 75% of our share of drilling and completion costs in the Eagle Ford Shale project until an additional $1.08 billion has been paid, which we expect to occur by year-end 2012. Closing of the transaction is anticipated in the fourth quarter of 2010.

 

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ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Overview

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 three and nine months ended September 30, 2010 (the “Current Quarter” and the “Current Period”, respectively) and the three and nine months ended September 30, 2009 (the “Prior Quarter” and the “Prior Period”, respectively):

 

      Three Months Ended  
September 30,
      Nine Months Ended  
September 30,
 
    2010     2009     2010     2009  

Net Production:

       

Natural gas (bcf)

    252.8        210.3        689.6        610.3   

Oil (mmbbl)

    4.5        3.0        12.8        9.1   

Natural gas equivalent (bcfe)

    280.0        228.5        766.6        664.6   

 

Natural Gas and Oil Sales ($ in millions):

       

Natural gas sales

  $ 828      $ 596      $ 2,504      $ 1,819   

Natural gas derivatives – realized gains (losses)

    487        675        1,418        1,771   

Natural gas derivatives – unrealized gains (losses)

    315        (275     534        (398
                               

Total natural gas sales

    1,630        996        4,456        3,192   
                               

 

Oil sales

    246        189        739        461   

Oil derivatives – realized gains (losses)

    25        12        66        31   

Oil derivatives – unrealized gains (losses)

    (262     (10     (563     (3
                               

Total oil sales

    9        191        242        489   
                               

 

Total natural gas and oil sales

  $ 1,639      $ 1,187      $ 4,698      $ 3,681   
                               

 

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

       

Natural gas ($ per mcf)

  $ 3.28      $ 2.84      $ 3.63      $ 2.98   

Oil ($ per bbl)

  $ 54.25      $ 62.47      $ 57.57      $ 50.97   

Natural gas equivalent ($ per mcfe)

  $ 3.84      $ 3.44      $ 4.23      $ 3.43   

 

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

       

Natural gas ($ per mcf)

  $ 5.20      $ 6.04      $ 5.69      $ 5.88   

Oil ($ per bbl)

  $ 59.81      $ 66.42      $ 62.75      $ 54.37   

Natural gas equivalent ($ per mcfe)

  $ 5.67      $ 6.44      $ 6.17      $ 6.14   

 

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

       

Marketing, gathering and compression

  $ 32      $ 29      $ 91      $ 91   

Service operations

  $ 7      $      $ 19      $ 3   

 

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

       

Marketing, gathering and compression

  $ 0.12      $ 0.13      $ 0.12      $ 0.14   

Service operations

  $ 0.03      $      $ 0.03      $   

 

Expenses ($ per mcfe):

       

Production expenses

  $ 0.83      $ 0.96      $ 0.85      $ 1.01   

Production taxes

  $ 0.12      $ 0.11      $ 0.16      $ 0.11   

General and administrative expenses

  $ 0.45      $ 0.42      $ 0.44      $ 0.39   

Natural gas and oil depreciation, depletion and amortization

  $ 1.35      $ 1.29      $ 1.34      $ 1.56   

Depreciation and amortization of other assets

  $ 0.20      $ 0.27      $ 0.21      $ 0.27   

Interest expense(b)

  $      $ 0.28      $ 0.11      $ 0.24   

 

Interest Expense ($ in millions):

       

Interest expense(c)

  $ 3      $ 70      $ 93      $ 177   

Interest rate derivatives – realized (gains) losses

    (2     (7     (6     (19

Interest rate derivatives – unrealized (gains) losses

    2        (20     (75     (106
                               

Total interest expense

  $ 3      $ 43      $ 12      $ 52   
                               

 

Net Wells Drilled

    281        224        794        700   

Net Producing Wells as of the End of the Period

    22,445        22,749        22,445        22,749   

 

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(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.

 

(c)

Net of amounts capitalized.

We are the second largest producer of natural gas and a Top 20 producer of oil and natural gas liquids in the U.S. We own interests in approximately 45,100 producing natural gas and oil wells that are currently producing approximately 2.8 bcfe per day, 88% of which is natural gas. Our strategy is focused on discovering and developing unconventional natural gas and oil fields onshore in the U.S., primarily in our “Big 6” shale plays: the Barnett Shale in the Fort Worth Basin of north-central Texas, the Haynesville and Bossier Shales in the Ark-La-Tex area of northwestern Louisiana and East Texas, the Fayetteville Shale in the Arkoma Basin of central Arkansas, the Marcellus Shale in the northern Appalachian Basin of West Virginia, Pennsylvania and New York and the Eagle Ford Shale in South Texas. We also have substantial operations in the liquids-rich plays of the Granite Wash in western Oklahoma and the Texas Panhandle regions, the Niobrara Shale and Frontier Sand plays of the Powder River and DJ Basins of Wyoming and Colorado, as well as various other liquids-rich 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 vertically integrated our operations and own substantial midstream, compression, drilling and oilfield service assets.

We announced earlier this year that we are extending our strategy to apply the horizontal drilling expertise we have gained in our natural gas plays to unconventional oil reservoirs. Our goal is to reach a balanced mix of natural gas and liquids revenue as quickly as possible through organic drilling, rather than through acquisitions. This transition is already apparent in the mix of natural gas and oil and natural gas liquids wells we are drilling. In 2010, we expect that approximately 31% of our drilling and completion capital expenditures will be allocated to liquids-rich plays, compared to 10% in 2009, and we are projecting that these expenditures will reach 65% in 2012. Our production of oil and natural gas liquids has been increasing in 2010 as we develop our new unconventional oil plays, particularly in the Granite Wash, Tonkawa, Cleveland and Mississippian plays of the Anadarko Basin; the Avalon, Bone Spring and Wolfcamp plays of the Permian Basin; and the Eagle Ford and Niobrara Shales. The company now owns approximately 3.1 million net leasehold acres in unconventional liquids-rich plays.

Chesapeake began 2010 with estimated proved reserves of 14.254 tcfe and ended the Current Period with 16.223 tcfe, an increase of 1.969 tcfe, or 14%. During the Current Period, we replaced 767 bcfe of production with an internally estimated 2.736 tcfe of new proved reserves, for a reserve replacement rate of 357%. The Current Period’s proved reserve movement included 3.355 tcfe of extensions, 611 bcfe of positive performance revisions and 219 bcfe of positive revisions resulting from an increase in the twelve-month trailing average natural gas and oil prices between December 31, 2009 and September 30, 2010. During the Current Period, we acquired 50 bcfe of estimated proved reserves and divested 1.499 tcfe of estimated proved reserves.

During the Current Period, Chesapeake continued the industry’s most active drilling program, drilling 1,041 gross operated wells (676 net wells with an average working interest of 65%) and participating in another 911 gross wells operated by other companies (118 net wells with an average working interest of 13%). The company’s drilling success rate was 99% for company-operated wells and 98% for non-operated wells. Also during the Current Period, we invested $3.308 billion in operated wells (using an average of 127 operated rigs) and $545 million in non-operated wells (using an average of 111 non-operated rigs) for total drilling, completing and equipping costs of $3.853 billion (net of carries).

Our total Current Quarter production was 280.0 bcfe, comprised of 252.8 bcf of natural gas (90% on a natural gas equivalent basis) and 4.5 mmbbls of oil and natural gas liquids (10% on a natural gas equivalent basis). Daily production for the Current Quarter averaged 3.043 bcfe, an increase of 560 mmcfe, or 23%, over the 2.483 bcfe produced per day in the Prior Quarter.

Our total Current Period production was 766.6 bcfe, comprised of 689.6 bcf of natural gas (90% on a natural gas equivalent basis) and 12.8 mmbbls of oil and natural gas liquids (10% on a natural gas equivalent basis). Daily production for the Current Period averaged 2.808 bcfe, an increase of 373 mmcfe, or 15%, over the 2.435 bcfe produced per day in the Prior Period.

Since 2000, Chesapeake has built the largest combined inventories of onshore leasehold (13.8 million net acres) and 3-D seismic (27.4 million acres) in the U.S. and the largest inventory of U.S. natural gas shale play leasehold (2.8 million net acres). We now own the largest inventory of leasehold in two of the Top 3 new unconventional liquids-rich plays – the Eagle Ford Shale and the Niobrara Shale. We are currently using 140 operated drilling rigs to further develop our inventory of approximately 40,000 net drillsites. Based on the level of drilling activity we have planned, we anticipate reporting full-year production growth of approximately 13% in 2010 and 18% in 2011.

 

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Business Strategy

In May 2010, we announced a strategic and financial plan designed to increase shareholder value, reduce long-term debt and achieve investment grade metrics for our debt securities. Since then, we have implemented multiple parts of the plan as noted below.

Debt Reduction

During the Current Period, we issued in private placements 2.6 million shares of two series of our 5.75% Cumulative Non-Voting Convertible Preferred Stock resulting in net proceeds to us of approximately $2.562 billion. We used the net proceeds of these preferred stock offerings to redeem in whole $1.934 billion in principal amount of four series of our outstanding senior notes. Additionally, through tender offers followed by redemptions, we purchased $1.5 billion aggregate principal amount of three additional series of senior notes. We funded the purchase of the notes tendered and redeemed with proceeds from a $2.0 billion public offering of two series of senior notes. Upon the completion of the redemptions and tender offers in the Current Quarter, we retired all series of our outstanding senior notes that were issued under our more restrictive indentures. Excess funds from our offerings were used to repay borrowings outstanding under our corporate revolving bank credit facility.

Increased Focus on Liquids

In recognition of the significant and persistent value gap that has developed between natural gas and oil prices, Chesapeake has accelerated its transition to a more liquids-rich asset base. We have redirected a significant portion of our technological, geo-scientific, leasehold acquisition and drilling expertise to identifying, securing and commercializing unconventional liquids-rich plays. This planned transition will result in a more balanced portfolio between natural gas and liquids, and we expect to increase our liquids production by 80% and 60% in 2011 and 2012, respectively.

During the Current Period, we invested heavily in new leasehold acquisitions in various liquids-rich plays, including the Anadarko Basin’s Granite Wash, Cleveland, Tonkawa and Mississippian plays; the Permian Basin’s Wolfcamp, Bone Spring and Avalon plays; the Eagle Ford Shale in South Texas; the Niobrara Shale in the Powder River and DJ Basins; the Frontier Sand in the Powder River Basin; and various other new plays the company is not yet ready to discuss because we could lose our competitive advantage in those areas. After this aggressive effort to capture leasehold in a large number of highly competitive liquids-rich unconventional plays, we expect to become a significant seller of leasehold through planned joint venture transactions.

Asset Sales

In January 2010, Chesapeake completed its fourth joint venture in its Big 6 shale plays. In this joint venture transaction in the Barnett Shale, Total E&P USA, Inc., a wholly owned subsidiary of Total S.A. (Total), paid $800 million in cash at closing (plus $78 million of drilling and completion carries due from the effective date of the transaction to the closing date) and agreed to pay a total of $1.45 billion in drilling and completion carries over time by funding 60% of our share of future drilling and completion expenditures. The following table provides information about our remaining joint venture drilling and completion carries as of September 30, 2010:

 

                Shale                 
Play
           Joint Venture        
Partner
           Joint Venture        
Date
           Carries        
Remaining
 
               ($ in millions)  
Marcellus    Statoil    November 2008    $ 1,566   
Barnett    Total    January 2010      1,023   
              
         $ 2,589   
              

The drilling and completion carries in our joint ventures create a significant cost advantage for us that will allow us to continue to lower finding costs. During the Current Period and Prior Period, our drilling and completion costs included the benefit of approximately $745 million and $959 million, respectively, of joint venture drilling and completion carries. Our drilling and completion costs for the remainder of 2010 and in 2011, 2012 and 2013 will continue to be partially offset by the use of our remaining drilling and completion carries associated with our joint ventures in the Barnett and Marcellus Shales.

In October 2010, we entered into an industry cooperation agreement whereby a wholly owned subsidiary of CNOOC Limited (CNOOC) agreed to purchase a 33.3% undivided interest in 600,000 net natural gas and oil leasehold acres we hold in the Eagle Ford Shale in South Texas. The consideration for the sale will be approximately $1.08 billion in cash at closing. In addition, CNOOC has agreed to fund 75% of our share of drilling and completion costs in the Eagle Ford Shale project until an additional $1.08 billion has been paid, which we expect to occur by year-end 2012. Closing of the transaction is anticipated in the fourth quarter of 2010.

We completed three volumetric production payments (VPPs) in the Current Period, bringing our total of such transactions to eight. The company’s sixth VPP was completed in February 2010 for proceeds of approximately $180 million, or $3.95 per mcfe. In June 2010, we completed our seventh VPP for proceeds of approximately $335 million, or $8.73 per mcfe. Most recently, in September 2010, we completed our eighth VPP for proceeds of approximately $1.15 billion, or $2.93 per mcfe.

In the Current Period, we sold producing properties and gathering systems in Virginia and in the Permian Basin for proceeds of approximately $330 million. During the Current Period, as part of our joint venture arrangements with

 

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Total, Statoil and Plains, we sold an interest in additional leasehold in the Barnett, Marcellus and Haynesville Shale plays for proceeds of approximately $395 million that had an estimated cost basis of $195 million. The cash proceeds from these transactions are reflected as a reduction of natural gas and oil properties with no gain or loss recognized.

Initial Public Offering of Chesapeake Midstream Partners, L.P.

On August 3, 2010, Chesapeake Midstream Partners, L.P. (NYSE: CHKM), which we and Global Infrastructure Partners (GIP) formed to own, operate, develop and acquire midstream assets, completed an initial public offering of 24,437,500 common units (including 3,187,500 common units issued pursuant to the exercise of the underwriters’ over-allotment option on August 3, 2010) representing limited partner interests and received gross offering proceeds of approximately $513 million at an initial offering price of $21.00 per unit less approximately $38 million for underwriting discounts and commissions, structuring fees and offering expenses. Pursuant to the terms of our contribution agreement with GIP, CHKM distributed the approximate $62 million of net proceeds from the exercise of the over-allotment option to GIP on August 3, 2010. In connection with the closing of the offering, Chesapeake and GIP contributed the interests of the midstream joint venture’s operating subsidiary to CHKM, and CHKM is continuing the business that had been conducted by the joint venture. Common units owned by public security holders represent 17.7% of all outstanding limited partner interests, and Chesapeake and GIP hold 42.3% and 40.0%, respectively, of all outstanding limited partner interests. The limited partners, collectively, have a 98.0% interest in CHKM and the general partner, which is owned and controlled 50/50 by Chesapeake and GIP, has a 2.0% interest in CHKM.

On October 26, 2010, CHKM declared its first distribution for the period from the date of the closing of its initial public offering on August 3, 2010 through September 30, 2010. It corresponds to a full quarterly distribution of $0.3375 per unit, or $1.35 per unit on an annualized basis. At this distribution level, Chesapeake would receive quarterly distributions of approximately $20 million in respect of its limited partner and general partner interests. In the future, we plan to enter into “drop down” transactions with CHKM for some of the assets owned by our wholly owned midstream subsidiary, Chesapeake Midstream Development, L.P., whose gas gathering operations are located primarily in the Haynesville, Fayetteville, Marcellus and Eagle Ford Shales.

Budgeted Capital Expenditures

Our exploration, development and acquisition activities require us to make substantial capital expenditures. Our current budgeted drilling and completion capital expenditures, net of drilling and completion carries, are $4.8 - $5.0 billion in 2010, 2011 and 2012. We are also continuing to build an industry-leading unconventional liquids portfolio through new play identification systems and subsequent leasing programs. As of September 30, 2010, we had made commitments to acquire additional leasehold in various transactions during the next twelve months for approximately $1.7 billion, including the acquisition of a significant additional position in the Appalachian Basin from privately-held Anschutz Corporation. In this transaction, which is scheduled to close in November 2010, we have agreed to acquire approximately 500,000 net acres of Appalachian Basin leasehold and option rights for approximately $850 million. Approximately 25% of these assets will be immediately marketed for resale after closing while the remainder of the assets will be combined with our leasehold in a play in which the company expects to execute a new industry joint venture in the first half of 2011. As with all of Chesapeake’s leasehold acquisitions in new plays, the company’s goal remains to acquire an industry-leading leasehold position in a new play and then bring in a minority industry partner to help de-risk the play and to provide reimbursement of all or most of Chesapeake’s leasehold costs in the new play.

Management believes that our planned leasehold and development joint ventures and various asset monetization programs benefit the company in several ways, including the creation of significant net asset value, improvement of our asset base through increasing the percentage of our assets that are oil and natural gas liquids, the reduction of financial risk, the reduction of our DD&A rate and the increase in our profitability per unit of production, thereby increasing our returns on capital and advancing future value creation to the present.

During the fourth quarter of 2010 and throughout 2011, the company will focus on recapturing a significant portion of new leasehold expenditures through joint ventures in several of our new liquids-rich plays. Additionally, we anticipate closing two additional VPP transactions, certain midstream asset sales and various other smaller planned sales. In total, Chesapeake is targeting to receive proceeds of approximately $1.3 - $1.5 billion in the fourth quarter of 2010 and approximately $3.0 - $3.5 billion in 2011 from asset sales. Each of the foregoing proposed sales, joint ventures and other transactions is subject to changes in market conditions and other factors, and there can be no assurance that we will complete any or all of these transactions on a timely basis or at all.

We plan to fund our 2010 and 2011 budgeted exploration and development capital expenditures, together with other capital expenditure requirements, from a combination of cash flow from operations, credit facility borrowings and asset monetizations.

In anticipation of the maturity of our existing credit facility in November 2012, Chesapeake is in the process of syndicating a new $4.0 billion senior secured revolving bank credit facility. The new facility will replace the company’s existing $3.5 billion facility in its entirety and have a term of five years. The syndication of the new facility is anticipated to be completed in November 2010.

Liquidity and Capital Resources

Sources and Uses of Funds

Cash flow from operations is a significant source of liquidity used to fund capital expenditures, pay dividends and repay debt. Cash provided by operating activities was $3.971 billion in the Current Period compared to $3.131 billion in the Prior Period. Changes in cash flow from operations are largely due to the same factors that affect our net income, excluding non-cash items such as impairments of assets, 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 and oil prices and to provide more predictable future cash flow from operations, we currently have hedged through swaps 53% and 28% of our expected remaining natural gas and oil production in 2010 at an average price of $7.66 per mcf and $89.94 per bbl, respectively. Additionally, we have hedged through swaps 60% and 3% of our expected natural gas and oil production in 2011 at an average price of $6.44 per mcf and $104.75 per bbl, respectively. Our natural gas and oil hedges as of September 30, 2010 are detailed in Item 3 of Part I 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.

 

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Our $3.5 billion corporate revolving bank credit facility, our $300 million midstream revolving bank credit facility and cash and cash equivalents are other sources of liquidity. We use the credit facilities and cash on hand to fund daily operating activities and capital expenditures as needed. We borrowed $10.458 billion and repaid $9.863 billion in the Current Period, and we borrowed $5.563 billion and repaid $7.866 billion in the Prior Period from our revolving credit facilities. A significant portion of our natural gas and oil properties is currently unencumbered and therefore available to be pledged as additional collateral under our corporate revolving bank credit facility if needed based on our periodic borrowing base and collateral redeterminations. Accordingly, we believe our borrowing capacity under this facility will not be reduced as a result of any such future periodic redeterminations. Our midstream facility is secured by substantially all of our wholly owned midstream assets and is not subject to periodic borrowing base redeterminations.

On May 17, 2010, we issued 600,000 shares of 5.75% Cumulative Convertible Non-Voting Preferred Stock, par value $0.01 per share and liquidation preference $1,000 per share, in a private placement for net proceeds of approximately $594 million. We issued an additional 900,000 shares of 5.75% Cumulative Convertible Non-Voting Preferred Stock on June 18, 2010 for net proceeds of approximately $877 million.

On May 17, 2010, we issued 1,100,000 shares of 5.75% Cumulative Convertible Non-Voting Preferred Stock (Series A), par value $0.01 per share and liquidation preference $1,000 per share, in a private placement for net proceeds of approximately $1.091 billion.

On August 17, 2010, we completed a public offering of $2.0 billion aggregate principal amount of senior notes. The offering consisted of $600 million of 6.875% Senior Notes due 2018 and $1.4 billion of 6.625% Senior Notes due 2020. Both series were priced at par. Net proceeds received were $1.967 billion.

In the Current Period and Prior Period, we received $436 million and $19 million, respectively, for settlements of derivatives which were classified as cash flows from financing activities.

In the Current Period, we received a $75 million cash distribution from our midstream joint venture which was accounted for as a return on investment and reflected as cash flows from operating activities.

On February 2, 2009, we completed a public offering of $1.0 billion aggregate principal amount of senior notes due 2015, which have a stated coupon rate of 9.5% per annum. The senior notes were priced at 95.071% of par to yield 10.625%. On February 17, 2009, we completed an offering of an additional $425 million aggregate principal amount of the 9.5% Senior Notes due 2015. The additional senior notes were priced at 97.75% of par plus accrued interest from February 2 to February 17, 2009 to yield 10.0% per annum. Net proceeds of $1.346 billion from these two offerings were used to repay outstanding indebtedness under our corporate revolving bank credit facility, which we reborrow from time to time to fund drilling and leasehold acquisition initiatives and for general corporate purposes.

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

We paid dividends on our common stock of $142 million and $135 million in the Current Period and the Prior Period, respectively. We paid dividends on our preferred stock of $49 million in the Current Period and $18 million in the Prior Period.

On June 21, 2010, we redeemed in whole for an aggregate redemption price of approximately $1.366 billion, plus accrued interest, approximately $364 million in principal amount of our outstanding 7.50% Senior Notes due 2013, $300 million in principal amount of our 7.50% Senior Notes due 2014 and approximately $670 million in principal amount of our 6.875% Senior Notes due 2016. Associated with these redemptions, we recognized a loss of $69 million in the Current Period.

On July 22, 2010, we redeemed in whole for a redemption price of approximately $619 million, plus accrued interest, $600 million in principal amount of our 6.375% Senior Notes due 2015. Associated with the redemption, we recognized a loss of $19 million in the Current Period.

On August 30, 2010, we completed tender offers to purchase for cash $245 million of 7.00% Senior Notes due 2014, $567 million of 6.625% Senior Notes due 2016 and $582 million of 6.25% Senior Notes due 2018. On September 16, 2010, we redeemed the remaining $55 million of 7.00% Senior Notes due 2014, $33 million of 6.625% Senior Notes due 2016 and $18 million of 6.25% Senior Notes due 2018 based on the redemption provisions in the indentures. Associated with the tender offers and redemptions, we recognized a loss of $40 million in the Current Period.

 

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Credit Risk

A significant portion of our credit risk is concentrated in derivative instruments that 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 we attempt to limit our exposure to non-performance by any single counterparty. During the more than 15 years we have engaged in hedging activities, we have experienced a counterparty default only once (Lehman Brothers in September 2008), and the total loss recorded in that instance was immaterial. On September 30, 2010, our commodity and interest rate derivative instruments were spread among 14 counterparties. Our multi-counterparty secured hedging facility includes 13 of our counterparties which are required to secure their natural gas and oil hedging obligations in excess of defined thresholds. We now use this facility for all of our commodity hedging.

Our accounts receivable are primarily from purchasers of natural gas and oil ($675 million at September 30, 2010) and exploration and production companies which own interests in properties we operate ($635 million at September 30, 2010). This industry concentration has the potential to impact our overall exposure to credit risk, either positively or negatively, in that our customers and joint working interest owners may be similarly affected by changes in economic, industry or other conditions. We generally require letters of credit or parent guarantees for receivables from parties which are judged to have sub-standard credit, unless the credit risk can otherwise be mitigated. During the Current Quarter, the Prior Quarter and the Current Period, we recognized nominal amounts of bad debt expense related to potentially uncollectible receivables. During the Prior Period, we recognized $13 million of bad debt expense related to potentially uncollectible receivables.

Investing Activities

Cash used in investing activities increased to $5.665 billion during the Current Period, compared to $3.654 billion during the Prior Period. The majority of our $2.011 billion increase in investing activities was the result of our increased acquisition of unproved properties and exploration and development activities. The following table shows our cash used in (provided by) investing activities during these periods:

 

     Nine Months Ended
September 30,
 
               2010                   2009      
     ($ in millions)  

Natural Gas and Oil Investing Activities:

    

Acquisitions of natural gas and oil proved properties

   $ 139      $ 17   

Acquisition of leasehold and unproved properties

     3,575        890   

Exploration and development of natural gas and oil properties

     3,576        2,647   

Geological and geophysical costs(a)

     142        143   

Interest capitalized on unproved properties

     503        441   

Proceeds from divestitures of proved and unproved properties

     (3,107     (1,729

Deposits for acquisitions

     95          
                

Total natural gas and oil investing activities

     4,923        2,409   
                

Other Investing Activities:

    

Additions to other property and equipment

     968        1,362   

Additions to investments

     113        40   

Proceeds from sales of other assets

     (328     (157

Other

     (11       
                

Total other investing activities

     742        1,245   
                

Total cash used in investing activities

   $       5,665      $       3,654   
                

 

(a)

Including related capitalized interest.

In the Prior Period, pursuant to an acquisition shelf registration statement, we issued 24,822,832 shares of common stock valued at $429 million for the purchase of proved and unproved properties.

 

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Bank Credit Facilities

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

 

    

Corporate
        Credit Facility(a)         

      

Midstream
        Credit Facility(b)        

     ($ in millions)

Borrowing capacity

   $        3,500      $        300

Maturity date

   November 2012      July 2015

Facility structure

   Senior secured revolving      Senior secured revolving

Amount outstanding as of September 30, 2010

   $        2,237      $        250

Letters of credit outstanding as of September 30, 2010

   $             13      $          —

 

(a)

Borrowers are Chesapeake Exploration, L.L.C. and Chesapeake Appalachia, L.L.C.

 

(b)

Borrower is Chesapeake Midstream Operating, L.L.C., a wholly owned subsidiary of Chesapeake Midstream Development, L.P.

Our credit facilities do not contain material adverse change or adequate assurance covenants. Although the applicable interest rates under our corporate credit facility fluctuate slightly based on our long-term senior unsecured credit ratings, neither of our credit facilities contains 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.

Corporate Credit Facility

Our $3.5 billion syndicated revolving bank credit facility is used for general corporate purposes. Borrowings under the facility are secured by natural gas and oil proved reserves and bear interest at our option at either (i) the greater of the reference rate of Union Bank, N.A., or the federal funds effective rate plus 0.50%, both of which are subject to a margin that varies from 0.00% to 0.75% per annum according to our senior unsecured long-term debt ratings, or (ii) the London Interbank Offered Rate (LIBOR), plus a margin that varies from 1.50% to 2.25% per annum according to our senior unsecured long-term debt ratings. The collateral value and borrowing base are redetermined periodically. The unused portion of the facility is subject to a commitment fee of 0.50%. Interest is payable quarterly or, if LIBOR applies, it may be payable at more frequent intervals.

The credit facility agreement contains various covenants and restrictive provisions which limit our ability to incur additional indebtedness, make investments or loans and create liens and require us to maintain an indebtedness to total capitalization ratio and an indebtedness to EBITDA ratio, in each case as defined in the agreement. We were in compliance with all covenants under the agreement at September 30, 2010. 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 $50 million or more, would constitute an event of default under our senior note indentures, which could in turn result in the acceleration of a significant portion of our senior note indebtedness. The credit facility agreement also has cross default provisions that apply to other indebtedness of Chesapeake and its restricted subsidiaries with an outstanding principal amount in excess of $75 million.

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

Midstream Credit Facility

Our $300 million midstream syndicated revolving bank credit facility is used to fund capital expenditures to build natural gas gathering and other systems for our drilling program and for general corporate purposes associated with our midstream operations. Borrowings under the midstream credit facility are secured by all of the assets of the wholly owned subsidiaries (the restricted subsidiaries) of Chesapeake Midstream Development, L.P. (CMD), itself a wholly owned subsidiary of Chesapeake, and bear interest at our option at either (i) the greater of the reference rate of Wells Fargo Bank, National Association, the federal funds effective rate plus 0.50%, and the one-month LIBOR plus 1.00%, all of which are subject to a margin that varies from 1.75% to 2.25% per annum according to the most recent leverage ratio described below or (ii) the LIBOR plus a margin that varies from 2.75% to 3.25% per annum according to the most recent leverage ratio. The unused portion of the facility is subject to a commitment fee of 0.50% per annum according to the most recent leverage ratio. Interest is payable quarterly or, if LIBOR applies, it may be payable at more frequent intervals.

 

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The midstream credit facility agreement contains various covenants and restrictive provisions which limit the ability of CMD and its restricted subsidiaries to incur additional indebtedness, make investments or loans and create liens. The agreement requires maintenance of a leverage ratio based on the ratio of indebtedness to EBITDA and an interest coverage ratio based on the ratio of EBITDA to interest expense, in each case as defined in the agreement. The leverage ratio increases during any three-quarter period, beginning in the quarter in which CMD makes a material disposition of assets to our master limited partnership midstream affiliate, Chesapeake Midstream Partners, L.P. We were in compliance with all covenants under the agreement at September 30, 2010. If CMD or its restricted subsidiaries should fail to perform their obligations under these and other covenants, the revolving credit commitment could be terminated and any outstanding borrowings under the facility could be declared immediately due and payable. The midstream credit facility agreement also has cross default provisions that apply to other indebtedness of CMD and its restricted subsidiaries may have with an outstanding principal amount in excess of $15 million.

Hedging Facility

We have a multi-counterparty hedge facility with 13 counterparties that have committed to provide approximately 5.6 tcfe of trading capacity and an aggregate mark-to-market capacity of $15.0 billion under the terms of the facility. As of September 30, 2010, we had hedged a total of 2.3 tcfe under the facility. The multi-counterparty facility allows us to enter into cash-settled natural gas and oil price and basis hedges with the counterparties. Our obligations under the multi-counterparty facility are secured by natural gas and oil proved reserves, the value of which must cover the fair value of the transactions outstanding under the facility by at least 1.65 times, and guarantees by our subsidiaries that also guarantee our corporate revolving bank credit facility and indentures. The counterparties’ obligations under the facility must be secured by cash or short-term U.S. Treasury instruments to the extent that any mark-to-market amounts they owe to Chesapeake exceed defined thresholds. The maximum volume-based trading capacity under the facility is governed by the expected production of the pledged reserve collateral, and volume-based trading limits are applied separately to price and basis hedges. In addition, there are volume-based sub-limits for natural gas and oil hedges. Chesapeake has significant flexibility with regard to releases and/or substitutions of pledged reserves, provided that certain collateral coverage and other requirements are met. The facility does not have a maturity date. Counterparties to the agreement have the right to cease trading with the company on a prospective basis as long as obligations associated with any existing trades in the facility continue to be satisfied in accordance with the terms of the agreement.

Senior Note Obligations

In addition to outstanding borrowings under our revolving bank credit facilities discussed above, as of September 30, 2010, senior notes represented approximately $9.0 billion of our total debt and consisted of the following ($ in millions):

 

7.625% senior notes due 2013

   $ 500   

9.5% senior notes due 2015

     1,425   

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

     816   

6.5% senior notes due 2017

     1,100   

6.875% senior notes due 2018

     600   

7.25% senior notes due 2018

     800   

6.625% senior notes due 2020

     1,400   

6.875% senior notes due 2020

     500   

2.75% contingent convertible senior notes due 2035(b)

     451   

2.5% contingent convertible senior notes due 2037(b)

     1,378   

2.25% contingent convertible senior notes due 2038(b)

     752   

Discount on senior notes(c)

     (800

Interest rate derivatives(d)

     36   
        
   $                 8,958   
        

 

(a)

The principal amount shown is based on the dollar/euro exchange rate of $1.3601 to 1.00 as of September 30, 2010. See Note 2 of our condensed consolidated financial statements included in this report for information on our related foreign currency derivatives.

 

(b)

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 third quarter of 2010, 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 fourth quarter of 2010 under this provision. The

 

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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     $          48.71              May 14, 2016

   2.5% due 2037

     May 15, 2017, 2022, 2027, 2032     $          64.26              November 14, 2017

   2.25% due 2038

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

 

(c)

Included in this discount is $731 million at September 30, 2010 associated with the equity component of our contingent convertible senior notes.

 

(d)

See Note 2 of our condensed consolidated financial statements included in this report for discussion related to these instruments.

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. Our senior note obligations are guaranteed by certain of our wholly owned subsidiaries. See Note 12 of the financial statements included in this report for condensed consolidating financial information regarding our guarantor and non-guarantor subsidiaries. We may redeem the senior notes, other than the contingent convertible senior notes, at any time at specified make-whole or redemption prices. Our senior notes are governed by indentures containing covenants that limit our ability and our subsidiaries’ ability to incur certain secured indebtedness; enter into sale/leaseback transactions; and consolidate, merge or transfer assets.

Other Contractual Obligations

Chesapeake has various financial obligations which are not recorded as liabilities in its condensed consolidated balance sheet at September 30, 2010. These include commitments related to drilling rig and compressor leases, transportation and drilling contracts, natural gas and oil purchase obligations, minimum volume commitments, net acreage maintenance commitments, and leasehold purchase commitments. These commitments are discussed in Note 3 of our condensed consolidated financial statements included in this report.

Results of Operations – Three Months Ended September 30, 2010 vs. September 30, 2009

General. For the Current Quarter, Chesapeake had net income of $558 million, or $0.75 per diluted common share, on total revenues of $2.581 billion. This compares to net income of $192 million, or $0.30 per diluted common share, on total revenues of $1.811 billion during the Prior Quarter.

Natural Gas and Oil Sales. During the Current Quarter, natural gas and oil sales were $1.639 billion compared to $1.187 billion in the Prior Quarter. In the Current Quarter, Chesapeake produced 280.0 bcfe at a weighted average price of $5.67 per mcfe, compared to 228.5 bcfe produced in the Prior Quarter at a weighted average price of $6.44 per mcfe (weighted average prices exclude the effect of unrealized gains or (losses) on natural gas and oil derivatives of $53 million and ($285) million in the Current Quarter and the Prior Quarter, respectively). In the Current Quarter, the decrease in prices resulted in a decrease in revenue of $216 million and increased production resulted in a $331 million increase, for a total increase in revenues of $115 million (excluding unrealized gains or losses on natural gas and oil derivatives). The increase in production from the Prior Quarter to the Current Quarter was generated by our successful drilling results.

For the Current Quarter, we realized an average price per mcf of natural gas of $5.20, compared to $6.04 in the Prior Quarter (weighted average prices exclude the effect of unrealized gains or losses on derivatives). Oil prices realized per barrel (excluding unrealized gains or (losses) on derivatives) were $59.81 and $66.42 in the Current Quarter and Prior Quarter, respectively. Realized gains or losses from our natural gas and oil derivatives resulted in a net increase in natural gas and oil revenues of $512 million, or $1.83 per mcfe, in the Current Quarter and a net increase of $687 million, or $3.00 per mcfe, in the Prior Quarter.

 

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Changes in natural gas and oil prices have a significant impact on our natural gas and oil revenues and cash flows. Assuming the Current Quarter production levels, a change of $0.10 per mcf of natural gas sold would have resulted in an increase or decrease in revenues and cash flow of approximately $25 million, and a change of $1.00 per barrel of oil sold would have resulted in an increase or decrease in revenues and cash flow of approximately $5 million and $4 million, respectively, without considering the effect of derivative activities.

The following tables show our production and price received by region for the Current Quarter and the Prior Quarter:

 

    Three Months Ended
September 30,  2010
 
          Natural Gas           Oil/NGLs     Total  
        (Bcf)          ($/Mcf)(a)       (Mmbbl)       ($/Bbl)(a)          (Bcfe)             %          ($/Mcfe)(a)   

Big 6 Shales:

             

   Haynesville Shale

    68.3          3.64            —            —            68.3          24%         3.64       

   Barnett Shale

    50.9          2.33            0.2            23.94            52.1          19            2.37       

   Fayetteville Shale

    36.1          3.07            —            —            36.1          13            3.07       

   Marcellus Shale

    15.7          3.68            —            —            15.7          6            3.68       

   Eagle Ford Shale

    0.3          4.55            0.1            74.23            0.9          —            9.48       

   Bossier Shale

    —          —            —            —            —          —            —       

Other:

             

   Mid-Continent

    58.4          3.45            3.4            52.42            79.0          28            4.84       

   Permian and Delaware Basins

    10.6          3.84            0.6            70.39            14.2          5            5.98       

   South Texas/Gulf Coast/
  Ark-La-Tex

    7.0          4.00            0.1            61.38            7.6          3            4.27       

   Other Appalachian Basin

    5.5          3.22            0.1            45.03            6.1          2            3.63       
                                     

Total(b)

    252.8          3.28            4.5            54.25            280.0          100%         3.84       
                                     
    Three Months Ended
September 30,  2009
 
          Natural Gas            Oil/NGLs     Total  
        (Bcf)           ($/Mcf)(a)       (Mmbbl)       ($/Bbl)(a)          (Bcfe)             %          ($/Mcfe)(a)   

Big 6 Shales:

             

   Haynesville Shale

    24.0          2.57            —            —            24.0          11%         2.57       

   Barnett Shale

    58.6          1.93            —            —            58.6          25            1.93       

   Fayetteville Shale

    23.1          2.49            —            —            23.1          10            2.49       

   Marcellus Shale

    5.0          3.36            —            —            5.0          2            3.36       

   Eagle Ford Shale

    —          —            —            —            —          —            —       

   Bossier Shale

    —          —            —            —            —          —            —       

Other:

             

   Mid-Continent

    67.5          3.53            2.0            62.03            79.5          35            4.57       

   Permian and Delaware Basins

    13.5          3.22            0.8            64.90            18.2          8            5.14       

   South Texas/Gulf Coast/
  Ark-La-Tex

    12.5          3.72            0.1            59.28            13.7          6            4.14       

   Other Appalachian Basin

    6.1          3.14            0.1            55.01            6.4          3            3.43       
                                     

Total(b)

    210.3          2.84            3.0            62.47            228.5          100%         3.44       
                                     

 

(a)

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

 

(b)

Current Quarter production reflects the sale of a 25% joint venture interest in the company’s Barnett Shale assets on January 25, 2010 (15.8 bcfe), the company’s sixth volumetric production payment transaction on February 5, 2010 (2.0 bcfe), the company’s seventh volumetric production payment transaction on June 14, 2010 (0.5 bcfe) and the sale of producing properties in Virginia and in the Permian Basin in the second quarter of 2010 (1.8 bcfe).

Our average daily production of 3.043 bcfe for the Current Quarter consisted of 2.748 bcf of natural gas and 49,272 barrels of oil and natural gas liquids (NGLs). Our Current Quarter production of 280.0 bcfe was comprised of 252.8 bcf (90% on a natural gas equivalent basis) and 4.5 million barrels of oil and NGLs

 

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(10% on a natural gas equivalent basis). Our year-over-year growth rate of natural gas production was 20% and our year-over-year growth rate of oil and NGL (liquids) production was 50%. Our percentage of revenue from liquids in the Current Quarter was 17% of realized natural gas and oil revenue compared to 14% in the Prior Quarter.

Marketing, Gathering and Compression Sales and Operating Expenses. Marketing, gathering and compression sales and operating expenses consist of third-party revenue and operating expenses related to our midstream operations. Marketing, gathering and compression activities are performed by Chesapeake substantially for owners in Chesapeake-operated wells. Chesapeake realized $883 million in marketing, gathering and compression sales in the Current Quarter, with corresponding marketing, gathering and compression expenses of $851 million, for a net margin before depreciation of $32 million. This compares to sales of $575 million, expenses of $546 million and a net margin before depreciation of $29 million in the Prior Quarter. In the Current Quarter, Chesapeake realized an increase in marketing, gathering and compression sales and operating expenses primarily due to an increase in third-party marketing, gathering and compression volumes. This increase was offset by a decrease in revenues, expenses and margin related to certain of our midstream assets that were contributed to our midstream joint venture on September 30, 2009 and subsequently deconsolidated on January 1, 2010.

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 $59 million in service operations revenue in the Current Quarter with corresponding service operations expense of $52 million, for a net margin before depreciation of $7 million. This compares to revenue of $49 million, expenses of $49 million and a net loss before depreciation of a nominal amount in the Prior Quarter.

Production Expenses. Production expenses, which include lifting costs and ad valorem taxes, were $231 million in the Current Quarter and $218 million in the Prior Quarter. On a unit-of-production basis, production expenses were $0.83 per mcfe in the Current Quarter compared to $0.96 per mcfe in the Prior Quarter. The decrease per mcfe in the Current Quarter was primarily the result of completing new high volume wells with lower per unit production expenses.

Production Taxes. Production taxes were $34 million in the Current Quarter compared to $25 million in the Prior Quarter. On a unit-of-production basis, production taxes were $0.12 per mcfe in the Current Quarter compared to $0.11 per mcfe in the Prior Quarter. The $9 million increase in production taxes in the Current Quarter is due to an increase in the average realized sales price of natural gas and oil of $0.40 per mcfe (excluding gains or losses on derivatives) and an increase in production of 52 bcfe. In general, production taxes are calculated using value-based formulas that produce higher per unit costs when natural gas and oil prices are higher.

General and Administrative Expenses. General and administrative expenses, including stock-based compensation but excluding internal costs capitalized to our natural gas and oil properties and other property, plant and equipment, were $125 million in the Current Quarter and $95 million in the Prior Quarter. The increase in the Current Quarter was the result of the company’s continued growth. General and administrative expenses were $0.45 and $0.42 per mcfe for the Current Quarter and Prior Quarter, respectively.

Included in general and administrative expenses is stock-based compensation of $21 million for the Current Quarter and $22 million for the Prior Quarter. Our stock-based compensation for employees and non-employee directors is in the form of restricted stock and helps offset the fact that we do not have a pension plan. Employee stock-based compensation 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 5 of our condensed consolidated financial statements included in Part I 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 exploration and development activities and do not include any costs related to production, general corporate overhead or similar activities. In addition, we capitalize internal costs that can be identified with the construction of certain of our property, plant and equipment. We capitalized $98 million and $91 million of internal costs in the Current Quarter and the Prior Quarter, respectively, directly related to our natural gas and oil property acquisition, exploration and development efforts and the construction of our property, plant and equipment.

Natural Gas and Oil Depreciation, Depletion and Amortization. Depreciation, depletion and amortization of natural gas and oil properties was $378 million and $295 million during the Current Quarter and the Prior Quarter, respectively. The $83 million increase is primarily the result of a 22% increase in production from the Prior Quarter compared to the Current Quarter. 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 $1.35 and $1.29 in the Current Quarter and in the Prior Quarter, respectively.

Depreciation and Amortization of Other Assets. Depreciation and amortization of other assets was $56 million in the Current Quarter and $62 million in the Prior Quarter. Depreciation and amortization of other assets was $0.20 and $0.27 per mcfe for the Current Quarter and the Prior Quarter, respectively. The decrease in the Current Quarter

 

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is primarily due to certain of our midstream assets that were contributed to our midstream joint venture on September 30, 2009 and subsequently deconsolidated on January 1, 2010, offset by additional depreciation expense associated with assets acquired over the past year. Property and equipment costs are depreciated on a straight-line basis. Buildings are depreciated over 10 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 twenty years. To the extent company-owned drilling rigs and equipment are used to drill our wells, a substantial portion of the depreciation is capitalized in natural gas and oil properties as exploration and development costs.

Impairment or Loss on Sale of Other Property and Equipment. In the Current Quarter, we recorded a $37 million charge associated with the impairment or loss on sale of other property, plant and equipment. Of this amount, $18 million was related to various sales of other property plant and equipment including the sale of pipe, gas gathering systems and other miscellaneous assets, and an additional $19 million impairment was recorded related to the obsolescence of certain pipe inventory.

In the Prior Quarter, we recorded a $124 million loss associated with the impairment or loss on sale of other property, plant and equipment. An $82 million impairment was related to certain gathering systems contributed to our midstream joint venture, as well as a $4 million impairment of debt issuance costs associated with the portion of our $460 million midstream revolving bank credit facility that was reduced to $250 million. Also, in the Prior Quarter, we recorded a $38 million loss on the sale of two gathering systems.

Interest Expense. Interest expense decreased to $3 million in the Current Quarter compared to $43 million in the Prior Quarter as follows:

 

    Three Months Ended
September 30,
 
    2010     2009  
    ($ in millions)  

Interest expense on senior notes

  $ 167      $ 195   

Interest expense on credit facilities

    18        18   

Capitalized interest

    (185     (153

Realized (gain) loss on interest rate derivatives

    (2     (7

Unrealized (gain) loss on interest rate derivatives

    2        (20

Amortization of loan discount and other

    3        10   
               

Total interest expense

  $ 3      $ 43   
               

Average long-term borrowings on senior notes

  $           9,632      $         11,372   
               

Interest expense, excluding unrealized gains or losses on interest rate derivatives and net of amounts capitalized, was a nominal amount per mcfe in the Current Quarter compared to $0.28 per mcfe in the Prior Quarter. The decrease in interest expense per mcfe is due primarily to increased production, a decrease in our senior notes outstanding and an increase in capitalized interest. Capitalized interest increased $32 million as a result of a significant increase in unevaluated properties, the base on which interest is capitalized, in the Current Quarter compared to the Prior Quarter.

Loss on Redemptions or Exchanges of Chesapeake Debt. During the Current Quarter, we redeemed in whole for a redemption price of approximately $619 million, plus accrued interest, all $600 million in principal amount of our 6.375% Senior Notes due 2015. We recognized a loss of $19 million in the Current Quarter associated with the redemption.

Also during the Current Quarter, we completed tender offers to purchase for cash $245 million of 7.00% Senior Notes due 2014, $567 million of 6.625% Senior Notes due 2016 and $582 million of 6.25% Senior Notes due 2018. Following the completion of these tender offers, we redeemed the remaining $55 million of 7.00% Senior Notes due 2014, $33 million of 6.625% Senior Notes due 2016 and $18 million of 6.25% Senior Notes due 2018 based on the redemption provisions in the indentures. Associated with the tender offers and redemptions, we recognized a loss of $40 million in the Current Quarter.

In the Prior Quarter, we privately exchanged approximately $153 million in aggregate principal amount of our 2.25% Contingent Convertible Senior Notes due 2038 for an aggregate of 4,176,671 shares of our common stock valued at approximately $110 million. Through these transactions, we were able to retire this debt for common stock valued at approximately 72% of the face value of the notes. In connection with accounting guidance for debt with conversion and other options, we are required to account for the liability and equity components of our convertible debt instruments separately. Of the $153 million principal amount of convertible notes exchanged in the Prior Quarter, $96 million was allocated to the debt component of the notes and the remaining $57 million was allocated to the equity conversion feature of the notes and was recorded as an adjustment to paid-in-capital. The difference

 

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between the debt component and value of the common stock exchanged in these transactions resulted in a $17 million loss (including $3 million of deferred charges associated with the exchanges).

Impairment of Investments. In the Current Quarter, we recorded impairments of $16 million related to certain other equity investments.

Other Income (Expense). Other income (expense) was $168 million and ($30) million in the Current Quarter and Prior Quarter, respectively. The Current Quarter included a $121 million gain related to the initial public offering by CHKM and a private offering of common stock by Chaparral Energy, Inc., which represented our proportionate share of the excess of offering proceeds over our carrying value. The Current Quarter also included $30 million of income related to our equity in net income of certain of our investments, $4 million of interest income and $13 million of miscellaneous income. The Prior Quarter consisted of a $24 million loss related to our equity in net losses of certain of our investments, $1 million of interest income and $7 million of miscellaneous expense.

Income Tax Expense (Benefit). Chesapeake recorded income tax expense of $349 million in the Current Quarter compared to $115 million in the Prior Quarter. Of the $234 million increase in income tax expense recorded in the Current Quarter, $225 million was the result of the increase in net income before income taxes and $9 million was due to an increase in the effective tax rate. Our effective income tax rate was 38.5% in the Current Quarter and 37.5% in the Prior Quarter. Our effective tax rate fluctuates as a result of the impact of state income taxes and permanent differences.

Results of Operations – Nine Months Ended September 30, 2010 vs. September 30, 2009

General. For the Current Period, Chesapeake had net income of $1.550 billion, or $2.24 per diluted common share, on total revenues of $7.391 billion. This compares to a net loss of $5.306 billion, or $8.78 per diluted common share, on total revenues of $5.480 billion during the Prior Period. The Prior Period loss was due to a non-cash impairment of natural gas and oil properties of approximately $6.0 billion, net of tax, as a result of a 36% decrease in NYMEX natural gas prices from $5.71 per mcf at December 31, 2008 to $3.63 per mcf at March 31, 2009.

Natural Gas and Oil Sales. During the Current Period, natural gas and oil sales were $4.698 billion compared to $3.681 billion in the Prior Period. In the Current Period, Chesapeake produced 766.6 bcfe at a weighted average price of $6.17 per mcfe, compared to 664.6 bcfe produced in the Prior Period at a weighted average price of $6.14 per mcfe (weighted average prices exclude the effect of unrealized losses on natural gas and oil derivatives of ($29) million in the Current Period and ($401) million in the Prior Period, respectively). In the Current Period, the increase in prices resulted in an increase in revenue of $18 million and increased production resulted in a $627 million increase, for a total increase in revenues of $645 million (excluding unrealized gains or losses on natural gas and oil derivatives). The increase in production from the Prior Period to the Current Period was primarily generated by our successful drilling results.

For the Current Period, we realized an average price per mcf of natural gas of $5.69, compared to $5.88 in the Prior Period (weighted average prices exclude the effect of unrealized gains or losses on derivatives). Oil prices realized per barrel (excluding unrealized gains or losses on derivatives) were $62.75 and $54.37 in the Current Period and Prior Period, respectively. Realized gains or losses from our natural gas and oil derivatives resulted in a net increase in natural gas and oil revenues of $1.484 billion, or $1.94 per mcfe, in the Current Period and a net increase of $1.802 billion, or $2.71 per mcfe, in the Prior Period.

Changes in natural gas and oil prices have a significant impact on our natural gas and oil revenues and cash flows. Assuming the Current Period production levels, a change of $0.10 per mcf of natural gas sold would have resulted in an increase or decrease in revenues and cash flow of approximately $69 million and $67 million, respectively, and a change of $1.00 per barrel of oil sold would have resulted in an increase or decrease in revenues and cash flow of approximately $13 million and $12 million, respectively, without considering the effect of derivative activities.

 

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The following tables show our production and price received by region for the Current Period and the Prior Period:

 

    Nine Months Ended
September 30, 2010
 
    Natural Gas     Oil/NGLs     Total  
        (Bcf)          ($/Mcf)(a)        (Mmbbl)         ($/Bbl)(a)           (Bcfe)             %          ($/Mcfe)(a)   

Big 6 Shales:

             

   Haynesville Shale

    159.2          3.75            —          —            159.2            21%         3.75       

   Barnett Shale

    148.0          2.60            0.5          29.21            151.0            20            2.64       

   Fayetteville Shale

    100.8          3.35            —          —            100.8            13            3.35       

   Marcellus Shale

    34.2          4.20            —          —            34.2            5            4.20       

   Eagle Ford Shale

    0.6          4.85            0.2          72.32            1.8            —            9.41       

   Bossier Shale

    —          —            —          —            —            —            —       

Other:

             

   Mid-Continent

    172.2          4.26            9.6          55.08            230.0            30            5.49       

   Permian and Delaware Basins

    34.7          4.28            2.1          73.52            47.3            6            6.40       

   South Texas/Gulf Coast/
  Ark-La-Tex

    22.4          4.27            0.2          71.29            23.6            3            4.67       

   Other Appalachian Basin

    17.5          3.49            0.2          54.81            18.7            2            3.82       
                                     

Total(b)

    689.6          3.63            12.8          57.57            766.6            100%         4.23       
                                     
    Nine Months Ended
September 30, 2009
 
    Natural Gas     Oil/NGLs     Total  
    (Bcf)     ($/Mcf)(a)     (Mmbbl)     ($/Bbl)(a)     (Bcfe)     %     ($/Mcfe)(a)  

Big 6 Shales:

             

   Haynesville Shale

    50.6          3.03            0.1          46.00            51.2            8%         3.09       

   Barnett Shale

    175.2          2.07            —          —            175.2            26            2.07       

   Fayetteville Shale

    61.8          2.90            —          —            61.8            9            2.90       

   Marcellus Shale

    14.7          4.50            —          —            14.7            2            4.50       

   Eagle Ford Shale

    —          —            —          —            —            —            —       

   Bossier Shale

    —          —            —          —            —            —            —       

Other:

             

   Mid-Continent

    196.2          3.45            5.9          50.69            231.6            35            4.22       

   Permian and Delaware Basins

    43.2          3.21            2.3          52.33            57.0            9            4.54       

   South Texas/Gulf Coast/
  Ark-La-Tex

    52.2          3.68            0.6          49.75            55.8            8            3.96       

   Other Appalachian Basin

    16.4          2.96            0.2          49.67            17.3            3            3.23       
                                     

Total(b)

    610.3          2.98            9.1          50.97            664.6            100%         3.43       
                                     

 

 

(a)

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

 

(b)

Current Period production reflects the sale of a 25% joint venture interest in the company’s Barnett Shale assets on January 25, 2010 (29.8 bcfe), the company’s sixth volumetric production payment transaction on February 5, 2010 (3.3 bcfe), the company’s seventh volumetric production payment transaction on June 14, 2010 (0.5 bcfe) and the sale of producing properties in Virginia and in the Permian Basin in the Current Period (1.8 bcfe).

Our average daily production of 2.808 bcfe for the Current Period consisted of 2.526 bcf of natural gas and 47,007 bbls of oil and NGLs. Our Current Period production of 766.6 bcfe was comprised of 689.6 bcf (90% on a natural gas equivalent basis) and 12.8 mmbbls (10% on a natural gas equivalent basis). Our year-over-year growth rate of natural gas production was 13% and our year-over-year growth rate of oil and NGL (liquids) production was 42%. Our percentage of revenue from liquids in the Current Period was 17% of realized natural gas and oil revenue compared to 12% in the Prior Period.

Marketing, Gathering and Compression Sales and Operating Expenses. Marketing, gathering and compression sales and operating expenses consist of third-party revenue and operating expenses related to our midstream operations. Marketing, gathering and compression activities are performed by Chesapeake substantially for owners in Chesapeake-operated wells. Chesapeake realized $2.520 billion in marketing, gathering and compression sales

 

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in the Current Period, with corresponding marketing, gathering and compression expenses of $2.429 billion, for a net margin before depreciation of $91 million. This compares to sales of $1.660 billion, expenses of $1.569 billion and a net margin before depreciation of $91 million in the Prior Period. In the Current Period, Chesapeake realized an increase in marketing, gathering and compression sales and operating expenses primarily due to an increase in third-party marketing, gathering and compression volumes. This increase was offset by a decrease in revenues, expenses and margin related to certain of our midstream assets that were contributed to our midstream joint venture on September 30, 2009 and subsequently deconsolidated on January 1, 2010.

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 the Current Period with corresponding service operations expense of $154 million, for a net margin before depreciation of $19 million. This compares to revenue of $139 million, expenses of $136 million and a net margin before depreciation of $3 million in the Prior Period.

Production Expenses. Production expenses, which include lifting costs and ad valorem taxes, were $652 million in the Current Period compared to $670 million in the Prior Period. On a unit-of-production basis, production expenses were $0.85 per mcfe in the Current Period compared to $1.01 per mcfe in the Prior Period. The decrease in the Current Period was primarily the result of completing new high volume wells with lower per unit production costs.

Production Taxes. Production taxes were $119 million in the Current Period compared to $71 million in the Prior Period. On a unit-of-production basis, production taxes were $0.16 per mcfe in the Current Period compared to $0.11 per mcfe in the Prior Period. The $48 million increase in production taxes in the Current Period is primarily due to an increase in the average realized sales price of natural gas and oil of $0.80 per mcfe (excluding gains or losses on derivatives) and an increase in production of 102 bcfe. In general, production taxes are calculated using value-based formulas that produce higher per unit costs when natural gas and oil prices are higher.

General and Administrative Expenses. General and administrative expenses, including stock-based compensation but excluding internal costs capitalized to our natural gas and oil properties and other property, plant and equipment, were $340 million in the Current Period and $259 million in the Prior Period. The increase in the Current Period was the result of the company’s continued growth. General and administrative expenses were $0.44 and $0.39 per mcfe for the Current Period and Prior Period, respectively.

Included in general and administrative expenses is stock-based compensation of $63 million for the Current Period and $60 million for the Prior Period. Our stock-based compensation for employees and non-employee directors is in the form of restricted stock and helps offset the fact that we do not have a pension plan. Employee stock-based compensation 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 5 of our condensed consolidated financial statements included in Part I 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 exploration and development activities and do not include any costs related to production, general corporate overhead or similar activities. In addition, we capitalize internal costs that can be identified with the construction of certain of our property, plant and equipment. We capitalized $287 million and $282 million of internal costs in the Current Period and the Prior Period, respectively, directly related to our natural gas and oil property acquisition, exploration and development efforts and the construction of our property, plant and equipment.

Natural Gas and Oil Depreciation, Depletion and Amortization. Depreciation, depletion and amortization of natural gas and oil properties was $1.025 billion and $1.037 billion during the Current Period and the Prior Period, 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 $1.34 and $1.56 in the Current Period and in the Prior Period, respectively. The $0.22 decrease in the average DD&A rate is due primarily to the reduction of our natural gas and oil full-cost pool resulting from divestitures in 2009 and 2010, the utilization of joint venture drilling carries in 2009 and 2010 and the impairment of natural gas and oil properties in 2008 and 2009.

Depreciation and Amortization of Other Assets. Depreciation and amortization of other assets was $159 million in the Current Period and $177 million in the Prior Period. Depreciation and amortization of other assets was $0.21 and $0.27 per mcfe for the Current Period and the Prior Period, respectively. The decrease in the Current Period is primarily due to certain of our midstream assets that were contributed to our midstream joint venture on September 30, 2009 and subsequently deconsolidated on January 1, 2010, offset by additional depreciation expense associated with assets acquired over the past year. Property and equipment costs are depreciated on a straight-line basis. Buildings are depreciated over 10 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 twenty years. To the extent company-owned drilling rigs and equipment are

 

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used to drill our wells, a substantial portion of the depreciation is capitalized in natural gas and oil properties as exploration and development costs.

Impairment of Natural Gas and Oil Properties. Due to lower commodity prices in the first quarter of 2009, we reported a non-cash impairment charge on our natural gas and oil properties of $9.6 billion in the Prior Period. 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.

Impairment or Loss on Sale of Other Property and Equipment. In the Current Period, we recorded a $37 million charge associated with the impairment or loss on sale of other property, plant and equipment. An $18 million loss was related to various sales of other property, plant and equipment including the sale of pipe, gas gathering systems and other miscellaneous assets, and an additional $19 million impairment was recorded related to the obsolescence of certain pipe inventory.

In the Prior Period, we recorded a $159 million loss associated with the impairment or loss on sale of other property, plant and equipment. An $82 million impairment was related to certain gathering systems contributed to our midstream joint venture, as well as a $4 million impairment of debt issuance costs associated with the portion of our $460 million midstream revolving bank credit facility that was reduced to $250 million. Also in the Prior Period, we recognized a $22 million charge in the Prior Period for a deposit on canceled contracts that were not refunded. Additionally, we recorded a $38 million loss on the sale of two gathering systems. Finally, we recognized $13 million of bad debt expense related to potentially uncollectible receivables.

Restructuring Costs. In the Prior Period, we recorded $34 million of restructuring and relocation costs in our Eastern Division and certain other workforce reduction costs. We reorganized our Charleston, West Virginia-based Eastern Division from a regional corporate headquarters to a regional field office consistent with the business model we use elsewhere in the country. As a result, we consolidated the management of our Eastern Division land, legal, accounting, information technology, geoscience and engineering departments into our corporate offices in Oklahoma City. The costs of the restructuring include termination benefits, consolidating or closing facilities and relocating employees. The discussion of restructuring costs in Note 10 of our condensed consolidated financial statements included in Part I of this report provides additional detail on the accounting for and reporting of these costs.

Interest Expense. Interest expense decreased to $12 million in the Current Period from $52 million in the Prior Period as follows:

 

    Nine Months Ended
September 30,
 
    2010     2009  
    ($ in millions)  

Interest expense on senior notes

  $ 550      $ 572   

Interest expense on credit facilities

    42        47   

Capitalized interest

    (525     (467

Realized (gain) loss on interest rate derivatives

    (6     (19

Unrealized (gain) loss on interest rate derivatives

    (75     (106

Amortization of loan discount and other

    26        25   
               

Total interest expense

  $ 12      $ 52   
               

Average long-term borrowings on senior notes

  $         10,538      $         11,172   
               

Interest expense, excluding unrealized gains or losses on interest rate derivatives and net of amounts capitalized, was $0.11 per mcfe in the Current Period compared to $0.24 per mcfe in the Prior Period. The decrease in interest expense per mcfe is due primarily to increased production, a decrease in our senior notes outstanding and an increase in capitalized interest. Capitalized interest increased $58 million as a result of a significant increase in unevaluated properties, the base on which interest is capitalized, in the Current Period compared to the Prior Period.

Loss on Redemptions or Exchanges of Chesapeake Debt. During the Current Period, we redeemed in whole for an aggregate redemption price of approximately $1.366 billion, plus accrued interest, approximately $364 million in principal amount of our outstanding 7.50% Senior Notes due 2013, $300 million in principal amount of our 7.50% Senior Notes due 2014 and approximately $670 million in principal amount of our 6.875% Senior Notes due 2016. Associated with the redemptions, we recognized a loss of $69 million in the Current Period. Also during the Current Period, we redeemed in whole for a redemption price of approximately $619 million, plus accrued interest, all $600

 

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million in principal amount of our 6.375% Senior Notes due 2015. We recognized a loss of $19 million in the Current Period associated with the redemption.

Additionally during the Current Period, we completed tender offers to purchase for cash $245 million of 7.00% Senior Notes due 2014, $567 million of 6.625% Senior Notes due 2016 and $582 million of 6.25% Senior Notes due 2018. Following the completion of these tender offers, we redeemed the remaining $55 million of 7.00% Senior Notes due 2014, $33 million of 6.625% Senior Notes due 2016 and $18 million of 6.25% Senior Notes due 2018 based on the redemption provisions in the indentures. Associated with the tender offers and redemptions, we recognized a loss of $40 million in the Current Period.

Finally, in the Current Period, we privately exchanged approximately $11 million in aggregate principal amount of our 2.25% Contingent Convertible Senior Notes due 2038 for an aggregate of 298,500 shares of our common stock valued at approximately $9 million. Through these transactions, we were able to retire this debt for common stock valued at approximately 80% of the face value of the notes. Of the $11 million principal amount of convertible notes exchanged in the Current Period, $7 million was allocated to the debt component of the notes and the remaining $4 million was allocated to the equity conversion feature of the notes and was recorded as an adjustment to paid-in-capital. The difference between the debt component and value of the common stock exchanged in these transactions resulted in the $2 million loss (including a nominal amount of deferred charges associated with the exchanges).

In the Prior Period, we privately exchanged approximately $238 million in aggregate principal amount of our 2.25% Contingent Convertible Senior Notes due 2038 for an aggregate of 6,707,321 shares of our common stock valued at approximately $164 million. Through these transactions, we were able to retire this debt for common stock valued at approximately 70% of the face value of the notes. Of the $238 million principal amount of convertible notes exchanged in the Prior Period, $148 million was allocated to the debt component and the remaining $90 million was allocated to the equity conversion feature and was recorded as an adjustment to paid-in capital. The difference between the debt component and value of the common stock exchanged in these transactions resulted in a $19 million loss (including $3 million of deferred charges associated with the exchanges).

Impairment of Investments. In the Current Period, we recorded a $16 million impairment of certain other equity investments. In the Prior Period, we recorded a $162 million impairment of certain investments. Each of our investees was 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 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: Gastar Exploration Ltd., $70 million; Chaparral Energy, Inc., $51 million; DHS Drilling Company, $19 million; Ventura Refining and Transmission LLC, $13 million; and Mountain Drilling Company, $9 million.

Other Income (Expense). Other income (expense) was $202 million and ($25) million in the Current Period and Prior Period, respectively. The Current Period included a $121 million gain related to the initial public offering by CHKM and a private offering of common stock by Chaparral Energy, Inc., which represented our proportionate share of the excess of offering proceeds over our carrying value. The Current Period also included $69 million of income related to our equity in net income of certain of our investments, $7 million of interest income and $5 million of miscellaneous income. The Prior Period consisted of a $32 million loss related to our equity in net losses of certain of our investments, $6 million of interest income and $1 million of miscellaneous expense.

Income Tax Expense (Benefit). Chesapeake recorded income tax expense of $970 million in the Current Period, compared to an income tax benefit of $3.184 billion in the Prior Period. Of the $4.154 billion increase in income tax expense recorded in the Current Period, $4.129 billion was the result of the increase in net income before income taxes and $25 million was due to an increase in the effective tax rate. Our effective income tax rate was 38.5% in the Current Period and 37.5% in the Prior Period. Our effective tax rate fluctuates as a result of the impact of state income taxes and permanent differences.

Critical Accounting Policies

We consider accounting policies related to hedging, natural gas and oil properties and income taxes to be critical policies. These policies are summarized in Management’s Discussion and Analysis of Financial Condition and Results of Operations in our annual report on Form 10-K for the year ended December 31, 2009 (2009 Form 10-K).

 

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Recently Issued and Proposed Accounting Standards

The Financial Accounting Standards Board (FASB) recently issued the following standards which were reviewed by Chesapeake to determine the potential impact on our financial statements upon adoption.

In February 2010, the FASB amended its guidance on subsequent events to remove the requirement for SEC filers to disclose the date through which an entity has evaluated subsequent events. The guidance was effective upon issuance. We adopted this guidance in the Current Period.

The FASB also issued new guidance requiring additional disclosures about fair value measurements, adding a new requirement to disclose transfers in and out of Levels 1 and 2 measurements and gross presentation of activity within a Level 3 roll forward. The guidance also clarified existing disclosure requirements regarding the level of disaggregation of fair value measurements and disclosures regarding inputs and valuation techniques. We adopted this guidance in the Current Period. Adoption had no impact on our financial position or results of operations. Required disclosures for the reconciliation of purchases, sales, issuance and settlements of financial instruments valued with a Level 3 method are effective beginning on January 1, 2011 and we do not expect the implementation to have a material impact on our financial position or results of operations. See Note 11 for discussion regarding fair value measurements.

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.

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 our 2009 Form 10-K. They include:

 

   

the volatility of natural gas and oil prices;

 

   

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

 

   

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 amount and timing of development expenditures;

 

   

inability to generate profits or achieve targeted results in our development and exploratory drilling and well operations;

 

   

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;

 

   

a reduced ability to borrow or raise additional capital as a result of lower natural gas and oil prices;

 

   

drilling and operating risks, including potential environmental liabilities;

 

   

changes in legislation and regulation adversely affecting our industry and our business;

 

   

general economic conditions negatively impacting us and our business counterparties;

 

   

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

 

   

losses possible from pending or future litigation.

 

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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 3. Quantitative and Qualitative Disclosures About Market Risk

Natural Gas and Oil Hedging Activities

Our results of operations and cash flows are impacted by changes in market prices for natural gas and oil. To mitigate a portion of the exposure to adverse market changes, we have entered into various derivative instruments. 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 our risk management objectives.

Our general strategy for attempting to mitigate exposure to adverse natural gas and oil price changes is to hedge into strengthening natural gas and oil futures markets when prices allow us to generate high cash margins and when we view prices to be in the upper range of our predicted most likely future price range. Information we consider in forming an opinion about future prices includes general economic conditions, industrial output levels and expectations, producer breakeven cost structures, liquefied natural gas import trends, natural gas and oil storage inventory levels, industry decline rates for base production and weather trends.

We use a wide range of derivative instruments to achieve our risk management objectives, including swaps, various collar arrangements and options (puts or calls). All of these are described in more detail below. We typically use swaps or collars for a large portion of the natural gas and oil volume we hedge. Swaps are used when the price level is acceptable and collars are used when the downside protection from the bought put is meaningful and the cap on upside from the sold call is at a satisfactory level. We also sell calls, taking advantage of market volatility for a portion of our projected production volumes when the strike price levels and the premiums are attractive to us. Typically, we sell call options when we would be satisfied to sell our production at the price being capped by the call strike or believe it to be more likely than not that the future natural gas or oil price will stay below the call strike price plus the premium we will receive.

We determine the volume we may potentially hedge by reviewing the company’s estimated future production levels, which are derived from extensive examination of existing producing reserve estimates and estimates of likely production (risked) from new drilling. Production forecasts are updated at least monthly and adjusted if necessary to actual results and activity levels. We do not hedge more volumes than we expect to produce, and if production estimates are lowered for future periods and hedges are already executed for some volume above the new production forecasts, the hedges are reversed. The actual fixed hedge price on our derivative instruments is derived from bidding and the reference NYMEX price, as reflected in current NYMEX trading. The pricing dates of our derivative contracts follow NYMEX futures. All of our derivative instruments are net settled based on the difference between the fixed price payment and the floating-price payment, resulting in a net amount due to or from the counterparty.

Hedging positions, including swaps, collars and options, are adjusted in response to changes in prices and market conditions as part of an ongoing dynamic process. We review our hedging positions continuously and if future market conditions change and prices have fallen to levels we believe could jeopardize the effectiveness of a position, we will mitigate such risk by either doing a cash settlement with our counterparty, restructuring the position, or by entering into a new swap that effectively reverses the current position (a counter-swap). The factors we consider in closing or restructuring a position before the settlement date are identical to those we reviewed when deciding to enter into the original hedge position.

In 2009, we restructured many of our trades that included knockout features as commodity prices decreased. The knockouts were typically restructured into straight swaps or collars based on strip prices at the time of the restructure. In the latter half of 2009 and in 2010, we took advantage of attractive strip prices in 2012 through 2016 and sold natural gas and oil call options to our counterparties in exchange for 2010 and 2011 natural gas swaps with strike prices above the then current market price. This effectively allowed us to sell out-year volatility through call options at terms acceptable to us in exchange for straight natural gas swaps with strike prices well in excess of the then current market price for natural gas. In the Current Quarter we took advantage of the lower strip prices by restructuring a portion of our call options. We restructured certain natural gas and oil calls by lowering the strike price on call options sold for 2012 through 2015 and used the value to buy back call options for the same periods. This reduced our collateral requirements under our hedging facility and increased our capacity to hedge additional volumes.

 

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As of September 30, 2010, our natural gas and oil derivative instruments were comprised of the following:

 

   

Swaps: Chesapeake receives a fixed price and pays a floating market price to the counterparty for the hedged commodity.

 

   

Collars: These instruments 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 put and the call strike price, no payments are due from either party.

 

   

Call options: Chesapeake sells call options in exchange for a premium from the counterparty. At the time of settlement, if the market price exceeds the fixed price of the call option, Chesapeake pays the counterparty such excess and if the market price settles below the fixed price of the call option, no payment is due from either party.

 

   

Put options: Chesapeake receives a premium from the counterparty in exchange for the sale of a put option. At the time of settlement, if the market price falls below the fixed price of the put option, Chesapeake pays the counterparty such shortfall, and if the market price settles above the fixed price of the put option, no payment is due from either party.

 

   

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.

 

   

Basis protection swaps: These instruments are arrangements that guarantee a price differential to NYMEX for natural gas from a specified delivery point. For non-Appalachian Basin 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.

In accordance with accounting guidance for derivatives and hedging, 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 condensed consolidated balance sheets. Cash settlements of our derivative arrangements are generally classified as operating cash flows unless the derivative contains a significant financing element at contract inception, in which case, all cash settlements are classified as financing cash flows in the accompanying condensed consolidated statements of cash flows.

 

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As of September 30, 2010, we had the following open natural gas and oil derivative instruments designed to hedge a portion of our natural gas and oil production for periods after September 30, 2010:

 

          Weighted Average Price     Cash Flow     Fair  
      Volume         Fixed           Put           Call        Differential      Hedge         Value      
Natural Gas:   (bbtu)          

(per mmbtu)

                ($ in millions)  

Swaps:

             

  Q4 2010

    69,588      $ 7.54      $      $      $        Yes      $ 250   

  Q1 2011

    34,922        6.49                             Yes        77   

  Q2 2011

    30,030        6.15                             Yes        56   

  Q3 2011

    30,360        6.15                             Yes        52   

  Q4 2011

    30,360        6.15                             Yes        41   

Other Swaps(a):

             

  Q4 2010

    45,720        7.84                             No        178   

  Q1 2011

    90,660        7.30                             No        197   

  Q2 2011

    88,050        7.20                             No        181   

  Q3 2011

    89,100        7.21                             No        172   

  Q4 2011

    89,100        7.24                             No        148   

  2012

    18,300        6.50                             No        26   

Other Collars:

             

  Q4 2010

    3,680               7.60        11.75               No        13   

  Q1 2011

    1,800               7.70        11.50               No        6   

  Q2 2011

    1,820               7.70        11.50               No        6   

  Q3 2011

    1,840               7.70        11.50               No        6   

  Q4 2011

    1,840               7.70        11.50               No        6   

Call Options:

             

  Q4 2010

    22,570                      10.08               No          

  Q1 2011

    5,175                      8.00               No          

  Q2 2011

    5,233                      8.00               No          

  Q3 2011

    5,290                      8.00               No          

  Q4 2011

    5,290                      8.00               No          

  2012

    161,077                      6.54               No        (42

  2013

    478,191                      6.88               No        (154

  2014 – 2020

    650,793                      7.49          No        (285

Put Options:

             

  Q4 2010

    (7,360            5.13                      No        (9

  Q1 2011

    (9,000            5.75                      No        (14

  Q2 2011

    (9,100            5.75                      No        (14

  Q3 2011

    (16,560            5.42                      No        (20

  Q4 2011

    (16,560            5.48                      No        (18

Knockout Swaps:

             

  Q4 2010

    4,880        8.74        6.56                      No          

  Q1 2011

    9,900        10.14        6.43                      No        1   

  Q2 2011

    4,550        9.62        6.05                      No        1   

  Q3 2011

    4,600        9.65        6.25                      No        1   

  Q4 2011

    4,600        9.73        6.25                      No        2   

Basis Protection Swaps

  

           

(Non-Appalachian Basin):

  

           

  Q2 2011

    19,147                             (0.82     No        (10

  Q3 2011

    19,397                             (0.82     No        (9

  Q4 2011

    6,545                             (0.82     No        (3

  2012

    43,212                             (0.85     No        (21

  2013 – 2019

    14,749                             (1.03     No        (10

 

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          Weighted Average Price     Cash Flow     Fair  
      Volume         Fixed           Put           Call        Differential      Hedge         Value      
Natural Gas:   (bbtu)          

(per mmbtu)

                ($ in millions)  

Basis Protection Swaps

  

           

(Appalachian Basin):

  

           

  Q4 2010

    2,732      $      $      $      $ 0.26        No      $   

  Q1 2011

    11,674                             0.14        No        (1

  Q2 2011

    12,186                             0.14        No          

  Q3 2011

    12,403                             0.14        No        1   

  Q4 2011

    12,323                             0.14        No        1   

  2012

    14                             0.19        No          

  2013 – 2022

    120                             0.10        No          
                   
   
Total Natural Gas
  
    812   
                   
          Weighted Average Price     Cash Flow     Fair  
      Volume         Fixed           Put           Call        Differential      Hedge         Value      
Oil:   (mbbl)          

(per bbl)

                ($ in millions)  

Swaps:

             

  Q4 2010

    460      $ 85.86             $      $        Yes      $ 2   

Other Swaps(b):

  

           

  Q4 2010

    644        91.12                             No        6   

  Q1 2011

    810        91.17                             No        (2

  Q2 2011

    819        91.17                             No        (2

  Q3 2011

    828        91.17                             No        (2

  Q4 2011

    828        91.17                             No        (3

  2012

    1,830        100.00                             No        (11

  2013

    1,825        100.00                             No        (16

Call Options:

  

           

  Q4 2010

    368                      101.25               No          

  Q1 2011(c)

    2,250                      74.81               No        (17

  Q2 2011(c)

    2,275                      74.81               No        (21

  Q3 2011(c)

    2,300                      74.81               No        (25

  Q4 2011(c)

    2,300                      74.81               No        (28

  2012(c)

    9,150                      74.81               No        (131

  2013 – 2015

    23,616                      87.82               No        (400

Knock-Out Swaps:

  

           

  Q4 2010

    1,196        90.25        60.00                      No        11   

  Q1 2011

    270        104.75        60.00                      No        5   

  Q2 2011

    273        104.75        60.00                      No        4   

  Q3 2011

    276        104.75        60.00                      No        4   

  Q4 2011

    276        104.75        60.00                      No        3   

  2012

    732        109.50        60.00                      No        8   
                   
   
Total Oil
  
    (615
                   

Total Natural Gas and Oil

  

  $ 197   
                   

 

(a)

Included in Natural Gas Other Swaps are options to extend existing swaps for an additional 12 months. The volume of such extendables in 2011 is 69,350 bbtu at a weighted average fixed swap price of $8.74/mmbtu.

 

(b)

Included in Oil Other Swaps are options to extend existing swaps for an additional 12 months. The volume of such extendables in 2011 is 3,285 mbbl at a weighted average fixed price of $91.17/bbl and in 2012 – 2013 is 3,655 mbbl at a weighted average fixed price of $100.00/bbl.

 

(c)

Included in Oil Call Options are natural gas liquid call options in the amount of 5,000 bbls per day at $39.06/bbl for 2011 and $38.01/bbl for 2012.

 

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In addition to the open derivative positions disclosed above, at September 30, 2010, we had $269 million of hedging gains related to option premiums and terminated trades that will be recorded within natural gas and oil sales as realized gains (losses) as they are transferred from either accumulated other comprehensive income or unrealized gains (losses).

 

     September 30, 2010  
     ($ in millions)  

Q4 2010

   $ 109   

Q1 2011

     66   

Q2 2011

     81   

Q3 2011

     78   

Q4 2011

     66   

2012

     36   

2013

     (47

2014 – 2022

     (120
        

Total

   $ 269   
        

We have determined 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. Future risk related to counterparties not being able to meet their obligations has been mitigated under our secured hedging facility which requires counterparties to post collateral if their obligations to Chesapeake are in excess of defined thresholds. 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.

The table below reconciles the Current Period change in fair value of our natural gas and oil derivatives. Of the $197 million fair value asset, as of September 30, 2010, $1.087 billion relates to contracts maturing in the next 12 months, of which we expect to transfer approximately $188 million (net of income taxes) from accumulated other comprehensive income to net income (loss), and ($890) million relates to contracts maturing after 12 months. All transactions hedged as of September 30, 2010 are expected to mature by December 31, 2022.

 

     2010  
     ($ in millions)  

Fair value of contracts outstanding, as of January 1

   $ 21   

Change in fair value of contracts

     1,378   

Fair value of contracts when entered into

     (303

Contracts realized or otherwise settled

     (1,229

Fair value of contracts when closed

     330   
        

Fair value of contracts outstanding, as of September 30

   $ 197   
        

The change in natural gas and oil prices during the Current Period increased the value of our derivative assets by $1.378 billion. This gain is recorded in natural gas and oil sales or in accumulated other comprehensive income. We entered into new contracts which had premiums of $303 million, and a liability was recorded. We settled contracts, reducing our assets by $1.229 billion, and we closed out contracts, increasing our assets by $330 million. The realized gain will be recorded in natural gas and oil sales in the month of related production.

Pursuant to accounting guidance for derivatives and hedging, certain derivatives qualify for designation as cash flow hedges. Following these provisions, changes in the fair value of 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 accumulated other comprehensive income until the hedged item is recognized in earnings as the physical transactions being hedged occur. Any change in fair value resulting from ineffectiveness is currently recognized in natural gas and oil sales as unrealized gains (losses). Changes in the fair value of non-qualifying derivatives that occur prior to their maturity (i.e., temporary fluctuations in value) are reported currently in the condensed consolidated statements of operations as unrealized gains (losses) within natural gas and oil sales. Realized gains (losses) are included in natural gas and oil sales in the month of related production.

The components of natural gas and oil sales for the Current Quarter, the Prior Quarter, the Current Period and the Prior Period are presented below.

 

         Three Months Ended    
September 30,
        Nine Months Ended    
September 30,
 
     2010     2009     2010     2009  
     ($ in millions)  

Natural gas and oil sales

   $ 1,074      $ 785      $ 3,243      $ 2,280   

Realized gains (losses) on natural gas and oil derivatives

     512        687        1,484        1,802   

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

     48        (278     (9     (484

Unrealized gains (losses) on ineffectiveness of cash flow hedges

     5        (7     (20     83   
                                

Total natural gas and oil sales

   $ 1,639      $ 1,187      $ 4,698      $ 3,681   
                                

 

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Interest Rate Risk

The table below presents principal cash flows and related weighted average interest rates by expected maturity dates.

 

     Years of Maturity        
       2010          2011          2012         2013         2014          Thereafter         Total    
     ($ in millions)  

Liabilities:

                 

   Long-term debt – fixed rate(a)

   $       $       $      $ 500      $       $ 9,222      $ 9,722   

   Average interest rate

                            7.63             6.05     6.13

   Long-term debt – variable rate

           $       $ 2,237      $      $       $ 250      $ 2,487   

   Average interest rate

                     2.65                    3.01     2.68

 

(a)

This amount does not include the discount included in long-term debt of ($800) million and interest rate derivatives of $36 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 facilities. All of our other long-term indebtedness is fixed rate and, therefore, does not expose us to the risk of fluctuations in earnings or cash flow due to changes in market interest rates. However, changes in interest rates do affect the fair value of our fixed-rate debt.

Interest Rate Derivatives

To mitigate our exposure to volatility in interest rates related to our senior notes and credit facilities, we enter into interest rate derivatives. As of September 30, 2010, our interest rate derivative instruments were comprised of the following types of instruments:

 

   

Swaps: Chesapeake enters into fixed-to-floating interest rate swaps (we receive a fixed interest rate and pay a floating market rate) to mitigate our exposure to changes in the fair value of our senior notes. We enter into floating-to-fixed interest rate swaps (we receive a floating market rate and a pay fixed interest rate) to manage our interest rate exposure related to our bank credit facility borrowings.

 

   

Call options: Occasionally we sell call options for a premium when we think it is more likely that the option will expire unexercised. The option allows the counterparty to terminate an open swap at a specific date.

 

   

Swaptions: Occasionally we sell an option to a counterparty for a premium which allows the counterparty to enter into a swap with us on a specific date.

As of September 30, 2010, the following interest rate derivatives were outstanding:

 

     Notional
Amount
     Weighted Average Rate         Fair Value  
Hedge
     Net
Premiums
     Fair
       Value      
 
            Fixed         

Floating(a)

           
     ($ in millions)                            ($ in millions)  

Fixed to Floating:

                  

   Swaps

                  

      Mature 2020

   $ 250         6.88%       3 mL plus 287 bp       No       $ —         $ 29   

   Call Options

                  

      Expire Q4 2010

   $ 250         6.88%       3 mL plus 287 bp       No         7           (26

   Swaption

                  

      Expire Q4 2010

   $ 250         6.50%       3 mL plus 270 bp       No         4             

Floating to Fixed:

                  

   Swaps

                  

      Mature 2014

   $ 1,050         2.19%       1– 6 mL       No         —           (42
                              
                $ 11         $ (39
                              

 

(a)

Month LIBOR has been abbreviated “mL” and basis points has been abbreviated “bp”.

In the Current Period, we closed interest rate derivatives which were designated as fair value hedges for losses totaling $20 million. These losses are currently reported as an adjustment to our senior note liability, and will be amortized as an increase to realized interest expense over the remaining ten-year term of the related senior notes.

 

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For interest rate derivative instruments designated as fair value hedges changes in fair value are recorded on the condensed 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 non-qualifying derivatives that occur prior to their maturity (i.e., temporary fluctuations in value) are reported currently in the condensed consolidated statements of operations as unrealized (gains) losses within interest expense.

Gains or losses from interest rate derivative transactions are reflected as adjustments to interest expense on the condensed consolidated statements of operations. The components of interest expense for the Current Period and the Prior Period are presented below.

 

     Three Months Ended
September 30,
    Nine Months Ended
September 30,
 
     2010     2009     2010     2009  
     ($ in millions)  

Interest expense on senior notes

   $ 167      $ 195      $ 550      $ 572   

Interest expense on credit facilities

     18        18        42        47   

Capitalized interest

     (185     (153     (525     (467

Realized (gains) losses on interest rate derivatives

     (2     (7     (6     (19

Unrealized (gains) losses on interest rate derivatives

     2        (20     (75     (106

Amortization of loan discount and other

     3        10        26        25   
                                

    Total interest expense

   $ 3      $ 43      $ 12      $ 52   
                                

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 pay Chesapeake 19 million and Chesapeake pays the counterparties $30 million, which yields 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 swap qualifies as a cash flow hedge. The fair value of the cross currency swap is recorded on the condensed consolidated balance sheet as a liability of $35 million at September 30, 2010. The euro-denominated debt in notes payable has been adjusted to $816 million at September 30, 2010 using an exchange rate of $1.3601 to 1.00.

 

ITEM 4. Controls and Procedures

We maintain disclosure controls and procedures designed to ensure that information required to be disclosed by Chesapeake in reports filed or submitted by it under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission rules and forms, and that such information is accumulated and communicated to management, including our principal executive and principal financial officers, as appropriate, to allow timely decisions regarding required disclosure. At the end of the period covered by this report, we carried out an evaluation, under the supervision and with the participation of Chesapeake management, including Chesapeake’s Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of Chesapeake’s disclosure controls and procedures pursuant to Securities Exchange Act Rule 13a-15(b). Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of September 30, 2010.

No changes in Chesapeake’s internal control over financial reporting occurred during the Current Quarter that have materially affected, or are reasonably likely to materially affect, Chesapeake’s internal control over financial reporting.

 

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PART II. OTHER INFORMATION

 

ITEM 1. Legal Proceedings

We refer you to “Litigation” in Note 3 of the notes to the condensed consolidated financial statements included in Part I, Item 1 of this Form 10-Q.

 

ITEM 1A. Risk Factors

Our business has many risks. Factors that could materially adversely affect our business, financial condition, operating results or liquidity and the trading price of our common stock, preferred stock or senior notes are described under “Risk Factors” in Item 1A of our 2009 Form 10-K and our Prospectus Supplement filed with the Securities and Exchange Commission on August 10, 2010. This information should be considered carefully, together with other information in this report and other reports and materials we file with the SEC.

 

ITEM 2. Unregistered Sales of Equity Securities and Use of Proceeds

The following table presents information about repurchases of our common stock during the three months ended September 30, 2010:

 

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)
 

July 1, 2010 through July 31, 2010

     894,149       $ 21.05                   

August 1, 2010 through August 31, 2010

     8,193       $ 20.80                   

September 1, 2010 through September 30, 2010

     13,555       $ 22.30                   
                             

 Total

     915,897       $ 21.38                   
                             

 

(a)

Includes the deemed surrender to the company of 12,285 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 903,612 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 company contributions.

 

ITEM 3. Defaults Upon Senior Securities

Not applicable.

 

ITEM 4. (Removed and Reserved)

 

 

ITEM 5. Other Information

        On November 5, 2010, the board of directors appointed Domenic J. Dell’Osso, Jr., 34, as Executive Vice President and Chief Financial Officer of the company. Mr. Dell’Osso previously served as Vice President – Finance of the company and Chief Financial Officer of the company’s wholly owned midstream subsidiary Chesapeake Midstream Development, L.P. from August 2008 to November 2010. Prior to joining the company, Mr. Dell’Osso was an energy investment banker with Jefferies & Co. from April 2006 to August 2008, and Banc of America Securities from April 2004 to April 2006. Mr. Dell’Osso graduated from Boston College in 1998 and from the University of Texas at Austin in 2003.

        In connection with his appointment, Mr. Dell’Osso entered into an employment agreement with the company, which is effective November 5, 2010 and will continue until September 30, 2012 in the absence of prior termination by the company or Mr. Dell’Osso.

        The employment agreement provides for Mr. Dell’Osso to receive a Base Salary (as defined therein), cash bonus, equity compensation and certain other benefits. Subject to the limitations set forth therein, Mr. Dell’Osso will receive (a) an annual Base Salary at the initial annual rate of not less than $450,000, which amount will increase to not less than $500,000 during the calendar year 2011 and not less than $600,000 during the calendar year 2012; (b) a special bonus of $100,000 on November 12, 2010, bonus compensation of not less than $500,000 during calendar year 2011 and bonus compensation of not less than $700,000 during calendar year 2012; and (c) an award of 20,000 shares of restricted stock of the company effective November 5, 2010, a minimum grant of $1,250,000 of restricted stock of the company during calendar year 2011 and a minimum grant of $2,400,000 of restricted stock of the company during calendar year 2012. The employment agreement also establishes a minimum stock ownership guideline for Mr. Dell’Osso of 25,000 shares of the common stock of the company effective at all times after December 31, 2011 and prior to termination of the employment agreement.

        The company may terminate the employment agreement with Mr. Dell’Osso at any time without cause; however, upon such termination he is entitled, subject to his execution of a severance agreement, to (a) receive 52 weeks of his Base Salary in a lump sum payment; and (b) immediate vesting of all equity compensation awarded pursuant to the employment agreement and any supplemental matching contributions made pursuant to the company’s Amended and Restated Deferred Compensation Plan.

        The employment agreement further provides that if, during the term of the agreement, there is a Change of Control (as defined therein) of the company, Mr. Dell’Osso will be entitled to a severance payment in an amount equal to 200% of the sum of (a) his then Base Salary as of the date of the Change of Control; and (b) the actual cash bonuses paid to Mr. Dell’Osso under the employment agreement or its predecessor during the preceding 12 calendar months. Additionally, all equity compensation granted to Mr. Dell’Osso under the employment agreement will be immediately vested.

        The forgoing description is qualified in its entirety by reference to the employment agreement, a copy of which is filed herewith as Exhibit 10.2 and incorporated herein by reference.

        In connection with his appointment, Mr. Dell’Osso is also eligible to receive certain other compensation in the form of personal benefits and perquisites, which is provided to all executive officers of the company. The description of such compensatory arrangements (excluding the accounting services described) under the caption “Other Compensation Arrangements” in the company’s definitive proxy statement, filed with the SEC on April 30, 2010, is incorporated by reference herein.

        The company will also enter into a standard indemnity agreement with Mr. Dell’Osso, a form of which was filed with the SEC on February 29, 2008 as Exhibit 10.3 to the company’s 2007 Annual Report on Form 10-K. Pursuant to this agreement, subject to the exceptions and limitations provided therein, the company will indemnify Mr. Dell’Osso for obligations he might incur in his capacity as an officer, as authorized by the company’s restated certificate of incorporation.

 

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ITEM 6. Exhibits

The following exhibits are filed as a part of this report:

 

          Incorporated by Reference            

Exhibit
Number

  

Exhibit Description

     Form       

    SEC File    
Number

     Exhibit       

Filing Date

   Filed
Herewith
   Furnished
Herewith
 

3.1.1

  

Chesapeake’s Restated Certificate of Incorporation, as amended.

     10-Q       001-13726      3.1.1       08/10/2009      

3.1.2

  

Certificate of Designation of 5% Cumulative Convertible Preferred Stock (Series 2005B).

     10-Q       001-13726      3.1.4       11/10/2008      

3.1.3

  

Certificate of Designation of 4.5% Cumulative Convertible Preferred Stock.

     10-Q       001-13726      3.1.6       08/11/2008      

3.1.4

  

Certificate of Designation of 5.75% Cumulative Non-Voting Convertible Preferred Stock (Series A).

     8-K       001-13726      3.2       05/20/2010      

3.1.5

  

Certificate of Designation of 5.75% Cumulative Non-Voting Convertible Preferred Stock, as amended.

     10-Q       001-13726      3.1.5       08/09/2010      

3.2

  

Chesapeake’s Amended and Restated Bylaws.

     8-K       001-13726      3.1       11/17/2008      

4.1

  

Indenture, dated as of August 2, 2010, by and among Chesapeake, as Issuer, the subsidiaries signatory thereto, as Subsidiary Guarantors, and the Bank of New York Mellon Trust Company, N.A., as Trustee.

     S-3       001-13726      4.1       08/03/2010      

4.1.1

  

First Supplemental Indenture dated as of August 17, 2010, by and among Chesapeake, as Issuer, the subsidiaries signatory thereto, as Subsidiary Guarantors, and the Bank of New York Mellon Trust Company, N.A., as Trustee, with respect to 6.875% Senior Notes due 2018.

     8-A       001-13726      4.2       9/24/2010      

4.1.1.1

  

Form of 6.875% Senior Note due 2018.

     8-A       001-13726      4.4       9/24/2010      

4.1.2

  

Second Supplemental Indenture, dated as of August 17, 2010, by and among Chesapeake, as Issuer, the subsidiaries signatory thereto, as Subsidiary Guarantors, and the Bank of New York Mellon Trust Company, N.A., as Trustee, with respect to 6.625% Senior Notes due 2020.

     8-A       001-13726      4.3       9/24/2010      

4.1.2.1

  

Form of 6.625% Senior Note due 2020.

     8-A       001-13726      4.5       9/24/2010      

10.2

  

Employment Agreement, dated as of November 5, 2010, between Domenic J. Dell’Osso, Jr., and Chesapeake Energy Corporation.

               X   

12

  

Ratios of Earnings to Fixed Charges and Combined Fixed Charges and Preferred Dividends.

               X   

31.1

  

Aubrey K. McClendon, Chairman and Chief Executive Officer, Certification pursuant to Section 302 of the Sarbanes-Oxley Act of

               X   

 

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Table of Contents
          Incorporated by Reference              

Exhibit
Number

  

Exhibit Description

     Form       

    SEC File    
Number

     Exhibit       

Filing Date

   Filed
Herewith
     Furnished
Herewith
 
  

2002.

                 

31.2

  

Domenic J. Dell’Osso, Jr., Executive Vice President and Chief Financial Officer, Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

                 X      

32.1

  

Aubrey K. McClendon, Chairman and Chief Executive Officer, Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

                    X   

32.2

  

Domenic J. Dell’Osso, Jr., Executive Vice President and Chief Financial Officer, Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

                    X   

101.INS

  

XBRL Instance Document.

                    X   

101.SCH

  

XBRL Taxonomy Extension Schema Document.

                    X   

101.CAL

  

XBRL Taxonomy Extension Calculation Linkbase Document.

                    X   

101.DEF

  

XBRL Taxonomy Extension Definition Linkbase Document.

                    X   

101.LAB

  

XBRL Taxonomy Extension Labels Linkbase Document.

                    X   

101.PRE

  

XBRL Taxonomy Extension Presentation Linkbase Document.

                    X   

 

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SIGNATURES

Pursuant to the requirement of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

 

 

 

CHESAPEAKE ENERGY CORPORATION

 

Date: November 9, 2010

 

By:

   

/s/ AUBREY K. MCCLENDON

 
     

Aubrey K. McClendon

Chairman of the Board and

Chief Executive Officer

 

Date: November 9, 2010

 

By:

   

/s/ DOMENIC J. DELL’OSSO, JR.

 
     

Domenic J. Dell’Osso, Jr.

Executive Vice President and

Chief Financial Officer

 

 

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INDEX TO EXHIBITS

 

         

Incorporated by Reference

         

Exhibit
Number  

  

Exhibit Description

  

  Form  

  

  SEC File  
  Number  

  

  Exhibit  

  

Filing Date

  

Filed
Herewith

  

Furnished

Herewith

3.1.1

  

Chesapeake’s Restated Certificate of Incorporation, as amended.

   10-Q    001-13726    3.1.1    08/10/2009      

3.1.2

  

Certificate of Designation of 5% Cumulative Convertible Preferred Stock (Series 2005B).

   10-Q    001-13726    3.1.4    11/10/2008      

3.1.3

  

Certificate of Designation of 4.5% Cumulative Convertible Preferred Stock.

   10-Q    001-13726    3.1.6    08/11/2008      

3.1.4

  

Certificate of Designation of 5.75% Cumulative Non-Voting Convertible Preferred Stock (Series A).

   8-K    001-13726    3.2    05/20/2010      

3.1.5

  

Certificate of Designation of 5.75% Cumulative Non-Voting Convertible Preferred Stock, as amended.

   10-Q    001-13726    3.1.5    08/09/2010      

3.2

  

Chesapeake’s Amended and Restated Bylaws.

   8-K    001-13726    3.1    11/17/2008      

4.1

  

Indenture, dated as of August 2, 2010, by and among Chesapeake, as Issuer, the subsidiaries signatory thereto, as Subsidiary Guarantors, and the Bank of New York Mellon Trust Company, N.A., as Trustee.

   S-3    001-13726    4.1    08/03/2010      

4.1.1

  

First Supplemental Indenture dated as of August 17, 2010, by and among Chesapeake, as Issuer, the subsidiaries signatory thereto, as Subsidiary Guarantors, and the Bank of New York Mellon Trust Company, N.A., as Trustee, with respect to 6.875% Senior Notes due 2018.

   8-A    001-13726    4.2    9/24/2010      

4.1.1.1

  

Form of 6.875% Senior Note due 2018.

   8-A    001-13726    4.4    9/24/2010      

4.1.2

  

Second Supplemental Indenture, dated as of August 17, 2010, by and among Chesapeake, as Issuer, the subsidiaries signatory thereto, as Subsidiary Guarantors, and the Bank of New York Mellon Trust Company, N.A., as Trustee, with respect to 6.625% Senior Notes due 2020.

   8-A    001-13726    4.3    9/24/2010      

4.1.2.1

  

Form of 6.625% Senior Note due 2020.

   8-A    001-13726    4.5    9/24/2010      

10.2

  

Employment Agreement, dated as of November 5, 2010, between Domenic J. Dell’Osso, Jr., and Chesapeake Energy Corporation.

               X   

12

  

Ratios of Earnings to Fixed Charges and Combined Fixed Charges and Preferred Dividends.

               X   

31.1

  

Aubrey K. McClendon, Chairman and Chief Executive Officer, Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

               X   

 

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Table of Contents
         

Incorporated by Reference

         

Exhibit
Number  

  

Exhibit Description

  

  Form  

  

  SEC File  
  Number  

  

  Exhibit  

  

Filing Date

  

Filed
Herewith

  

Furnished

Herewith

31.2

  

Domenic J. Dell'Osso, Jr., Executive Vice President and Chief Financial Officer, Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

               X   

32.1

  

Aubrey K. McClendon, Chairman and Chief Executive Officer, Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

                  X

32.2

  

Domenic J. Dell'Osso, Jr., Executive Vice President and Chief Financial Officer, Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

                  X

101.INS

  

XBRL Instance Document.

                  X

101.SCH

  

XBRL Taxonomy Extension Schema Document.

                  X

101.CAL

  

XBRL Taxonomy Extension Calculation Linkbase Document.

                  X

101.DEF

  

XBRL Taxonomy Extension Definition Linkbase Document.

                  X

101.LAB

  

XBRL Taxonomy Extension Labels Linkbase Document.

                  X

101.PRE

  

XBRL Taxonomy Extension Presentation Linkbase Document.

                  X

 

71