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, 2006

 

¨ 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 is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act.

Large accelerated filer  x    Accelerated filer  ¨    Non-accelerated filer  ¨

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, 2006, there were 436,865,417 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, 2006

 

          Page

PART I.

  
Financial Information   

Item 1.

  

Condensed Consolidated Financial Statements (Unaudited):

  
  

Condensed Consolidated Balance Sheets as of September 30, 2006 and December 31, 2005

   3
  

Condensed Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2006 and 2005

   5
  

Condensed Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2006 and 2005

   6
  

Condensed Consolidated Statements of Stockholders’ Equity for the Nine Months Ended September 30, 2006 and 2005

   8
  

Condensed Consolidated Statements of Comprehensive Income for the Three and Nine Months Ended September 30, 2006 and 2005

   9
  

Notes to Condensed Consolidated Financial Statements

   10

Item 2.

  

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

   32

Item 3.

  

Quantitative and Qualitative Disclosures About Market Risk

   51

Item 4.

  

Controls and Procedures

   58
PART II.   
Other Information   

Item 1.

  

Legal Proceedings

   59

Item 1A.

  

Risk Factors

   59

Item 2.

  

Unregistered Sales of Equity Securities and Use of Proceeds

   59

Item 3.

  

Defaults Upon Senior Securities

   59

Item 4.

  

Submission of Matters to a Vote of Security Holders

   60

Item 5.

  

Other Information

   60

Item 6.

  

Exhibits

   60


Table of Contents

PART I. FINANCIAL INFORMATION

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

 

    

September 30,

2006

   

December 31,

2005

 
     ($ in thousands)  
ASSETS     

CURRENT ASSETS:

    

Cash and cash equivalents

   $ 716     $ 60,027  

Accounts receivable

     735,005       791,194  

Deferred income taxes

     —         234,592  

Short-term derivative instruments

     1,097,578       10,503  

Inventory and other

     78,996       87,081  
                

Total Current Assets

     1,912,295       1,183,397  
                

PROPERTY AND EQUIPMENT:

    

Oil and natural gas properties, at cost based on full-cost accounting:

    

Evaluated oil and natural gas properties

     20,191,783       15,880,919  

Unevaluated properties

     3,440,181       1,739,095  

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

     (4,913,749 )     (3,945,703 )
                

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

     18,718,215       13,674,311  

Other property and equipment:

    

Natural gas gathering systems

     457,321       333,365  

Drilling rigs

     301,611       116,133  

Buildings and land

     381,751       233,467  

Natural gas compressors

     108,847       73,043  

Other

     205,781       110,208  

Less: accumulated depreciation and amortization of other property and equipment

     (172,563 )     (128,640 )
                

Total Property and Equipment

     20,000,963       14,411,887  
                

OTHER ASSETS:

    

Investments

     686,343       297,443  

Long-term derivative instruments

     604,796       78,860  

Other assets

     190,524       146,875  
                

Total Other Assets

     1,481,663       523,178  
                

TOTAL ASSETS

   $ 23,394,921     $ 16,118,462  
                

 

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Table of Contents

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS—(Continued)

(Unaudited)

 

    

September 30,

2006

   

December 31,

2005

 
     ($ in thousands)  
LIABILITIES AND STOCKHOLDERS’ EQUITY     

CURRENT LIABILITIES:

    

Accounts payable

   $ 754,996     $ 516,792  

Short-term derivative instruments

     81,438       577,681  

Other accrued liabilities

     398,611       364,501  

Deferred income taxes

     369,410       —    

Revenues and royalties due others

     305,422       394,693  

Accrued interest

     94,395       110,421  
                

Total Current Liabilities

     2,004,272       1,964,088  
                

LONG-TERM LIABILITIES:

    

Long-term debt, net

     7,861,108       5,489,742  

Deferred income tax liability

     2,903,688       1,804,978  

Asset retirement obligation

     179,149       156,593  

Long-term derivative instruments

     181,941       479,996  

Revenues and royalties due others

     22,962       22,585  

Other liabilities

     48,981       26,157  
                

Total Long-Term Liabilities

     11,197,829       7,980,051  
                

CONTINGENCIES AND COMMITMENTS (Note 3)

    

STOCKHOLDERS’ EQUITY:

    

Preferred Stock, $.01 par value, 20,000,000 shares authorized:

    

6.00% cumulative convertible preferred stock, 0 and 99,310 shares issued and outstanding as of September 30, 2006 and December 31, 2005, respectively, entitled in liquidation to $0 and $4,965,500

     —         4,966  

5.00% cumulative convertible preferred stock (series 2003), 38,625 and 1,025,946 shares issued and outstanding as of September 30, 2006 and December 31, 2005, respectively, entitled in liquidation to $3,862,500 and $102,594,600

     3,863       102,595  

4.125% cumulative convertible preferred stock, 3,065 and 89,060 shares issued and outstanding as of September 30, 2006 and December 31, 2005, respectively, entitled in liquidation to $3,065,000 and $89,060,000

     3,065       89,060  

5.00% cumulative convertible preferred stock (series 2005), 4,600,000 shares issued and outstanding as of September 30, 2006 and December 31, 2005, entitled in liquidation to $460,000,000

     460,000       460,000  

4.50% cumulative convertible preferred stock, 3,450,000 shares issued and outstanding as of September 30, 2006 and December 31, 2005, entitled in liquidation to $345,000,000

     345,000       345,000  

5.00% cumulative convertible preferred stock (series 2005B), 5,750,000 shares issued and outstanding as of September 30, 2006 and December 31, 2005, entitled in liquidation to $575,000,000

     575,000       575,000  

6.25% mandatory convertible preferred stock, 2,300,000 and 0 shares issued and outstanding as of September 30, 2006 and December 31, 2005, respectively, entitled in liquidation to $575,000,000 and $0

     575,000       —    

Common Stock, $.01 par value, 750,000,000 and 500,000,000 shares authorized, 437,859,397 and 375,510,521 shares issued at September 30, 2006 and December 31, 2005, respectively

     4,379       3,755  

Paid-in capital

     4,899,634       3,803,312  

Retained earnings

     2,495,215       1,100,841  

Accumulated other comprehensive income (loss), net of tax of ($518,564,000) and $112,071,000, respectively

     862,241       (194,972 )

Unearned compensation

     —         (89,242 )

Less: treasury stock, at cost; 1,306,528 and 5,320,816 common shares as of September 30, 2006 and December 31, 2005, respectively

     (30,577 )     (25,992 )
                

Total Stockholders’ Equity

     10,192,820       6,174,323  
                

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY

   $ 23,394,921     $ 16,118,462  
                

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

 

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Table of Contents

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

 

     Three Months Ended
September 30,
    Nine Months Ended
September 30,
 
     2006     2005     2006     2005  
     ($ in thousands, except per share data)  

REVENUES:

        

Oil and natural gas sales

   $ 1,493,226     $ 720,928     $ 4,190,430     $ 2,032,271  

Oil and natural gas marketing sales

     398,114       361,915       1,170,091       882,040  

Service operations revenue

     38,071       —         97,473       —    
                                

Total Revenues

     1,929,411       1,082,843       5,457,994       2,914,311  
                                

OPERATING COSTS:

        

Production expenses

     124,045       80,765       364,134       222,660  

Production taxes

     40,562       53,102       129,858       136,313  

General and administrative expenses

     37,382       15,785       99,728       39,640  

Oil and natural gas marketing expenses

     384,473       353,510       1,131,521       860,789  

Service operations expense

     18,821       —         48,925       —    

Oil and natural gas depreciation, depletion and amortization

     343,723       231,145       976,839       621,484  

Depreciation and amortization of other assets

     27,016       12,902       74,051       34,791  

Employee retirement expense

     —         —         54,753       —    
                                

Total Operating Costs

     976,022       747,209       2,879,809       1,915,677  
                                

INCOME FROM OPERATIONS

     953,389       335,634       2,578,185       998,634  
                                

OTHER INCOME (EXPENSE):

        

Interest and other income

     5,132       2,428       19,742       7,790  

Interest expense

     (74,112 )     (58,593 )     (220,226 )     (155,623 )

Gain on sale of investment

     —         —         117,396       —    

Loss on repurchases or exchanges of Chesapeake senior notes

     —         (747 )     —         (70,047 )
                                

Total Other Income (Expense)

     (68,980 )     (56,912 )     (83,088 )     (217,880 )
                                

INCOME BEFORE INCOME TAXES

     884,409       278,722       2,495,097       780,754  

INCOME TAX EXPENSE:

        

Current

     —         —         —         —    

Deferred

     336,074       101,734       963,136       284,977  
                                

Total Income Tax Expense

     336,074       101,734       963,136       284,977  
                                

NET INCOME

     548,335       176,988       1,531,961       495,777  

PREFERRED STOCK DIVIDENDS

     (25,753 )     (10,204 )     (62,793 )     (25,526 )

LOSS ON CONVERSION/EXCHANGE OF PREFERRED STOCK

     —         (17,725 )     (10,556 )     (22,468 )
                                

NET INCOME AVAILABLE TO COMMON SHAREHOLDERS

   $ 522,582     $ 149,059     $ 1,458,612     $ 447,783  
                                

EARNINGS PER COMMON SHARE:

        

Basic

   $ 1.25     $ 0.46     $ 3.75     $ 1.42  

Assuming dilution

   $ 1.13     $ 0.43     $ 3.40     $ 1.32  

CASH DIVIDEND DECLARED PER COMMON SHARE

   $ 0.060     $ 0.050     $ 0.170     $ 0.145  

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

        

Basic

     417,569       322,101       389,136       314,425  

Assuming dilution

     483,273       367,639       450,680       352,210  

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

 

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Table of Contents

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

 

     Nine Months Ended
September 30,
 
     2006     2005  
     ($ in thousands)  

CASH FLOWS FROM OPERATING ACTIVITIES:

    

NET INCOME

   $ 1,531,961     $ 495,777  

ADJUSTMENTS TO RECONCILE NET INCOME TO CASH PROVIDED BY OPERATING ACTIVITIES:

    

Depreciation, depletion and amortization

     1,041,246       649,907  

Unrealized (gains) losses on derivatives

     (453,347 )     135,175  

Deferred income taxes

     963,136       284,977  

Amortization of loan costs and bond discount

     14,952       10,576  

Realized (gains) losses on financing derivatives

     (96,377 )     —    

Stock-based compensation

     78,200       10,172  

Gain on sale of investment in Pioneer Drilling Company

     (117,396 )     —    

Income from equity investments

     (9,187 )     (2,171 )

Loss on repurchases or exchanges of Chesapeake senior notes

     —         70,047  

Premiums paid for repurchasing of senior notes

     —         (61,023 )

Other

     (3,556 )     (503 )

Change in assets and liabilities

     32,787       (15,589 )
                

Cash provided by operating activities

     2,982,419       1,577,345  
                

CASH FLOWS FROM INVESTING ACTIVITIES:

    

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

     (3,089,710 )     (1,932,934 )

Exploration and development of oil and natural gas properties

     (2,583,841 )     (1,488,145 )

Additions to buildings and other fixed assets

     (406,752 )     (156,978 )

Additions to drilling rig equipment

     (340,814 )     (42,056 )

Proceeds from sale of investment in Pioneer Drilling Company

     158,890       —    

Proceeds from sale of drilling rigs and equipment

     187,500       —    

Additions to investments

     (537,703 )     (37,273 )

Acquisition of trucking company, net of cash acquired

     (45,166 )     —    

Deposits for acquisitions

     (12,070 )     —    

Other

     1,661       2,342  
                

Cash used in investing activities

     (6,668,005 )     (3,655,044 )
                

CASH FLOWS FROM FINANCING ACTIVITIES:

    

Proceeds from long-term borrowings

     7,058,000       3,561,000  

Payments on long-term borrowings

     (5,666,000 )     (3,620,000 )

Proceeds from issuance of senior notes, net of offering costs

     969,193       1,765,383  

Proceeds from issuance of common stock, net of offering costs

     803,720       289,391  

Proceeds from issuance of preferred stock, net of offering costs

     557,627       782,368  

Purchases or exchanges of Chesapeake senior notes

     —         (556,407 )

Common stock dividends

     (61,829 )     (45,771 )

Preferred stock dividends

     (62,541 )     (17,315 )

Financing costs of credit facility

     (5,079 )     (4,672 )

Purchases of treasury shares

     (86,185 )     (4,000 )

Derivative settlements

     (68,361 )     —    

Net increase in outstanding payments in excess of cash balance

     43,250       33,751  

Cash received from exercise of stock options and warrants

     71,254       19,940  

Excess tax benefit from stock-based compensation

     85,649       —    

Other financing costs

     (12,423 )     (5,763 )
                

Cash provided by financing activities

     3,626,275       2,197,905  
                

Net increase (decrease) in cash and cash equivalents

     (59,311 )     120,206  

Cash and cash equivalents, beginning of period

     60,027       6,896  
                

Cash and cash equivalents, end of period

   $ 716     $ 127,102  
                

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

 

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Table of Contents

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS—(Continued)

(Unaudited)

 

     Nine Months Ended
September 30,
     2006    2005
     ($ in thousands)

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION OF CASH PAYMENTS FOR:

     

Interest, net of capitalized interest

   $ 245,190    $ 162,218

Income taxes, net of refunds received

   $ —      $ —  

SUPPLEMENTAL SCHEDULE OF NON-CASH INVESTING AND FINANCING ACTIVITIES:

In September 2006, we acquired 32% of the outstanding common stock of Chaparral Energy, Inc. for $240 million in cash and 1,375,989 newly issued shares of our common stock valued at $40 million. Chaparral is a privately-held independent oil and natural gas company headquartered in Oklahoma City, Oklahoma, with estimated proved reserves of approximately 618 bcfe and daily production of approximately 83 mmcfe.

For the nine months ended September 30, 2006 and 2005, holders of our 6.0% cumulative convertible preferred stock converted 99,310 and 1,835 shares, respectively, into 482,694 and 8,918 shares, respectively, of common stock.

For the nine months ended September 30, 2006 and 2005, holders of our 4.125% cumulative convertible preferred stock exchanged 2,750 and 178,675 shares, respectively, for 172,594 and 11,441,008 shares, respectively, of common stock in privately negotiated exchanges.

For the nine months ended September 30, 2006 and 2005, holders of our 5.0% (Series 2003) cumulative convertible preferred stock exchanged 183,273 and 697,724 shares, respectively, for 1,140,223 and 4,354,439 shares, respectively, of common stock in privately negotiated exchanges.

During the nine months ended September 30, 2006, we completed tender offers for our 4.125% and 5.0% (Series 2003) cumulative convertible preferred stock, issuing 5.2 million shares of our common stock in exchange for 83,245 shares of the 4.125% preferred stock, which represented 96.4% or $83.2 million of the aggregate liquidation value of the shares outstanding, and 5.0 million shares of our common stock in exchange for 804,048 shares of the 5.0% (Series 2003) preferred stock, which represented 95.4% or $80.4 million of the aggregate liquidation value of the shares outstanding. No cash was received or paid in connection with these transactions.

As of September 30, 2006 and 2005, dividends payable on our common and preferred stock were $51.1 million and $28.7 million, respectively.

For the nine months ended September 30, 2006 and 2005, oil and natural gas properties were adjusted by $177.7 million and $253.2 million, respectively, for net income tax liabilities related to acquisitions.

For the nine months ended September 30, 2006 and 2005, $72.6 million and $22.4 million, respectively, of accrued exploration and development costs were recorded as additions to oil and natural gas properties.

We recorded non-cash asset additions to net oil and natural gas properties of $13.7 million and $8.0 million for the nine months ended September 30, 2006 and 2005, respectively, for asset retirement obligations.

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

 

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Table of Contents

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

(Unaudited)

 

     Nine Months Ended
September 30,
 
     2006     2005  
     ($ in thousands)  

PREFERRED STOCK:

    

Balance, beginning of period

   $ 1,576,621     $ 490,906  

Issuance of 6.25% mandatory convertible preferred stock

     575,000       —    

Issuance of 5.00% cumulative convertible preferred stock (Series 2005)

     —         460,000  

Issuance of 4.50% cumulative convertible preferred stock

     —         345,000  

Exchange of common stock for 85,995 and 178,675 shares of 4.125% preferred stock

     (85,995 )     (178,675 )

Exchange of common stock for 987,321 and 697,724 shares of 5.00% preferred stock (Series 2003)

     (98,732 )     (69,772 )

Exchange of common stock for 99,310 and 1,835 shares of 6.00% preferred stock

     (4,966 )     (92 )
                

Balance, end of period

     1,961,928       1,047,367  
                

COMMON STOCK:

    

Balance, beginning of period

     3,755       3,169  

Issuance of 28,750,000 and 9,200,000 shares of common stock

     288       92  

Issuance of 1,375,989 shares of common stock for the purchase of Chaparral Energy, Inc. common stock

     14       —    

Exchange of 12,016,423 and 15,804,365 shares of common stock for preferred stock

     120       158  

Exercise of stock options and warrants

     67       38  

Restricted stock grants

     135       37  
                

Balance, end of period

     4,379       3,494  
                

PAID-IN CAPITAL:

    

Balance, beginning of period

     3,803,312       2,440,105  

Issuance of common stock

     834,900       300,932  

Issuance of common stock for the purchase of Chaparral Energy, Inc. common stock

     39,986       —    

Exchange of 12,016,423 and 15,804,365 shares of common stock for preferred stock

     189,572       248,381  

Equity-based compensation

     88,989       78,943  

Adoption of SFAS 123(R)

     (89,242 )     —    

Offering expenses

     (48,829 )     (34,302 )

Exercise of stock options and warrants

     71,187       19,902  

Release of 6,500,000 shares from treasury stock upon exercise of stock options

     (75,102 )     —    

Tax benefit from exercise of stock options and restricted stock

     85,649       17,397  

Preferred stock conversion/exchange expenses

     (788 )     (103 )
                

Balance, end of period

     4,899,634       3,071,255  
                

RETAINED EARNINGS:

    

Balance, beginning of period

     1,100,841       262,987  

Net income

     1,531,961       495,777  

Dividends on common stock

     (68,789 )     (46,612 )

Dividends on preferred stock

     (68,798 )     (25,726 )
                

Balance, end of period

     2,495,215       686,426  
                

ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS):

    

Balance, beginning of period

     (194,972 )     20,425  

Hedging activity

     1,143,738       (546,305 )

Marketable securities activity

     (86,525 )     44,440  
                

Balance, end of period

     862,241       (481,440 )
                

UNEARNED COMPENSATION:

    

Balance, beginning of period

     (89,242 )     (32,618 )

Restricted stock granted

     —         (78,148 )

Amortization of unearned compensation

     —         16,075  

Adoption of SFAS 123(R)

     89,242       —    
                

Balance, end of period

     —         (94,691 )
                

TREASURY STOCK—COMMON:

    

Balance, beginning of period

     (25,992 )     (22,091 )

Purchase of 2,707,471 and 257,220 shares of treasury stock

     (86,185 )     (4,000 )

Release of 6,500,000 shares upon exercise of stock options

     75,102       —    

Release of 221,759 shares for company benefit plans

     6,498       —    
                

Balance, end of period

     (30,577 )     (26,091 )
                

TOTAL STOCKHOLDERS’ EQUITY

   $ 10,192,820     $ 4,206,320  
                

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

(Unaudited)

 

     Three Months Ended
September 30,
    Nine Months Ended
September 30,
 
     2006     2005     2006     2005  
     ($ in thousands)  

Net income

   $ 548,335     $ 176,988     $ 1,531,961     $ 495,777  

Other comprehensive income, net of income tax:

        

Change in fair value of derivative instruments, net of income taxes of $451,888,000, ($345,346,000), $1,084,370,000 and ($389,909,000)

     750,588       (600,807 )     1,799,636       (678,334 )

Reclassification of (gain) loss on settled contracts, net of income taxes of ($105,162,000), $40,815,000, ($268,896,000) and $39,798,000

     (174,040 )     71,007       (444,770 )     69,238  

Ineffective portion of derivatives qualifying for cash flow hedge accounting, net of income taxes of ($64,099,000), $36,307,000, ($125,599,000) and $36,092,000

     (107,730 )     63,165       (211,128 )     62,791  

Unrealized gain (loss) on marketable securities, net of income taxes of ($2,336,000), $12,046,000, ($7,995,000) and $25,544,000

     (3,926 )     20,957       (13,439 )     44,440  

Reclassification of gain on sales of investments, net of income taxes of $0, $0, ($45,824,000) and $0

     —         —         (73,086 )     —    
                                

Comprehensive income

   $ 1,013,227     $ (268,690 )   $ 2,589,174     $ (6,088 )
                                

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. Chesapeake’s 2005 Annual Report on 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, 2006 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, 2006 (the “Current Quarter” and the “Current Period”, respectively) and the three and nine months ended September 30, 2005 (the “Prior Quarter” and the “Prior Period”, respectively).

Stock-Based Compensation

On January 1, 2006, we adopted Statement of Financial Accounting Standards No. 123 (revised 2004), Share-Based Payment (SFAS 123(R)), to account for stock-based compensation. Among other items, SFAS 123(R) eliminates the use of APB Opinion No. 25 and the intrinsic value method of accounting for equity compensation and requires companies to recognize the cost of employee services received in exchange for awards of equity instruments based on the fair value at grant date of those awards in their financial statements. We elected to use the modified prospective method for adoption, which requires compensation expense to be recorded for all unvested stock options and other equity-based compensation beginning in the first quarter of adoption. For all unvested options outstanding as of January 1, 2006, the previously measured but unrecognized compensation expense, based on the fair value at the original grant date, will be recognized in our financial statements over the remaining vesting period. For equity-based compensation awards granted or modified subsequent to January 1, 2006, compensation expense based on the fair value on the date of grant or modification will be recognized in our financial statements over the vesting period. We utilize the Black-Scholes option pricing model to measure the fair value of stock options. To the extent compensation cost relates to employees directly involved in oil and natural gas exploration and development activities, such amounts are capitalized to oil and natural gas properties. Amounts not capitalized to oil and natural gas properties are recognized as general and administrative expenses or production expenses.

Prior to the adoption of SFAS 123(R), we followed the intrinsic value method in accordance with APB 25 to account for employee stock-based compensation. Prior period financial statements have not been restated. Upon adoption of SFAS 123(R), we eliminated $89.2 million of unearned compensation cost and reduced additional paid-in capital by the same amount on our condensed consolidated balance sheet.

 

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

For the three and nine months ended September 30, 2006 and 2005, we recorded the following stock-based compensation ($ in thousands):

 

     Restricted Stock    Stock Options    Total

For the Three Months Ended September 30:

   2006    2005    2006    2005    2006    2005

Production expenses

   $ 2,742    $ —      $ 143    $ —      $ 2,885    $ —  

General and administrative expenses

     7,949      4,315      530      934      8,479      5,249

Oil and natural gas properties

     9,452      3,676      492      1,390      9,944      5,066
                                         

Total

   $ 20,143    $ 7,991    $ 1,165    $ 2,324    $ 21,308    $ 10,315
                                         

For the Nine Months Ended September 30:

                 

Production expenses

   $ 5,191    $ —      $ 523    $ —      $ 5,714    $ —  

General and administrative expenses

     18,066      8,837      3,190      1,335      21,256      10,172

Employee retirement expense

     35,720      —        15,510      —        51,230      —  

Oil and natural gas properties

     17,739      7,395      1,755      1,390      19,494      8,785
                                         

Total

   $ 76,716    $ 16,232    $ 20,978    $ 2,725    $ 97,694    $ 18,957
                                         

The impact to income before income taxes of adopting SFAS 123(R) for the Current Quarter and the Current Period was a reduction of $0.6 million and $2.5 million, respectively. SFAS 123(R) also requires cash inflows resulting from tax deductions in excess of compensation expense recognized for stock options and restricted stock (“excess tax benefits”) to be classified as financing cash inflows in our statements of cash flows. Accordingly, for the nine months ended September 30, 2006, we reported $85.6 million of excess tax benefits from stock-based compensation as cash provided by financing activities on our statement of cash flows.

Pro forma Disclosures

Prior to January 1, 2006, we accounted for our employee and non-employee director stock options using the intrinsic value method prescribed by APB 25. As required by SFAS 123(R), we have disclosed below the effect on net income and earnings per share that would have been recorded using the fair value based method for the three and nine months ended September 30, 2005 ($ in thousands, except per share amounts):

 

     Three Months Ended
September 30, 2005
    Nine Months Ended
September 30, 2005
 

Net Income:

    

As reported

   $ 176,988     $ 495,777  

Add: Stock-based compensation expense included in reported net income, net of income tax

     3,333       6,459  

Deduct: Total stock-based compensation expense determined under fair value based method for all awards, net of income tax

     (5,218 )     (13,176 )
                

Pro forma net income

   $ 175,103     $ 489,060  
                

Basic earnings per common share:

    

As reported

   $ 0.46     $ 1.42  
                

Pro forma

   $ 0.46     $ 1.40  
                

Diluted earnings per common share:

    

As reported

   $ 0.43     $ 1.32  
                

Pro forma

   $ 0.42     $ 1.30  
                

 

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

Restricted Stock

Chesapeake began issuing shares of restricted common stock to employees in January 2004 and to non-employee directors in July 2005. 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 four or five years from the date of grant for employees and three years for non-employee directors.

A summary of the status of the unvested shares of restricted stock as of September 30, 2006, and changes during the Current Period, is presented below:

 

     Number of
Unvested
Restricted Shares
   

Weighted Average
Grant-Date

Fair Value

Unvested shares as of January 1, 2006

   5,805,210     $ 18.38

Granted

   14,183,418       32.12

Vested

   (2,794,835 )     19.73

Forfeited

   (315,948 )     25.76
        

Unvested shares as of September 30, 2006

   16,877,845     $ 29.57
        

The aggregate intrinsic value of restricted stock vested during the Current Period was approximately $85.4 million.

Included in the 14.2 million shares of restricted stock granted during the Current Period are 9.9 million shares of restricted stock granted during the Current Quarter to our employees (except for our CEO and CFO, who did not participate in the stock awards) under a long-term stock incentive and retention program. These shares vest 50% in three years with the remaining 50% vesting in five years.

As of September 30, 2006, there was $478.6 million of total unrecognized compensation cost related to unvested restricted stock. The cost is expected to be recognized over a weighted average period of 4.09 years.

During the Current Quarter, the Prior Quarter, the Current Period and the Prior Period, we recognized excess tax benefits related to restricted stock of $1.3 million, $1.5 million, $4.3 million and $1.6 million, respectively, which were recorded as adjustments to additional paid-in capital and deferred income taxes with respect to such benefits.

Stock Options

We granted stock options in previous years under several stock compensation plans. Outstanding options expire ten years from the date of grant and become exercisable over a four-year period.

 

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

The following table provides information related to stock option activity during the Current Period:

 

     Number of
Shares
Underlying
Options
   

Weighted
Average
Exercise
Price

Per Share

   Weighted
Average
Contract
Life in Years
  

Aggregate
Intrinsic
Value(a)

($ in thousands)

Outstanding at January 1, 2006

   20,256,013     $ 6.14      

Exercised

   (13,198,705 )     5.32      

Forfeited

   (72,713 )     9.18      
                  

Outstanding at September 30, 2006

   6,984,595     $ 7.65    5.54    $ 149,081
                        

Exercisable at September 30, 2006

   5,688,614     $ 7.31    5.30    $ 123,403
                        

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

The aggregate intrinsic value of stock options exercised during the Current Period was approximately $345.0 million.

As of September 30, 2006, there was $2.5 million of total unrecognized compensation cost related to unvested stock options. The cost is expected to be recognized over a weighted average period of 0.52 years.

During the Current Quarter, the Prior Quarter, the Current Period and the Prior Period, we recognized excess tax benefits related to stock options of $2.8 million, $7.4 million, $81.3 million and $15.8 million, respectively, which were recorded as adjustments to additional paid-in capital and deferred income taxes with respect to such benefits.

Critical Accounting Policies

We consider accounting policies related to hedging, oil and natural gas properties, income taxes and business combinations 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, 2005.

2. Financial Instruments and Hedging Activities

Oil and Natural Gas Hedging Activities

Our results of operations and operating cash flows are impacted by changes in market prices for oil and natural gas. To mitigate a portion of the exposure to adverse market changes, we have entered into various derivative instruments. As of September 30, 2006, our oil and natural gas derivative instruments were comprised of swaps, cap-swaps, basis protection swaps, call options and collars. These instruments allow us to predict with greater certainty the effective oil and natural gas prices to be received for our hedged production. Although derivatives often fail to achieve 100% effectiveness for accounting purposes, we believe our derivative instruments continue to be highly effective in achieving the risk management objectives for which they were intended.

 

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

 

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

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

 

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

 

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

 

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

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

With respect to counter-swaps that are designed to lock-in the value of cap-swaps, the counter-swap is effective in locking-in the value of the cap-swap until the floating price reaches the cap (or floor) stipulated in the cap-swap agreement. The value of the counter-swap will increase (or decrease), but in the opposite direction, as the value of the cap-swap decreases (or increases) until the floating price reaches the pre-determined cap (or floor) stipulated in the cap-swap agreement. However, because of the written put option embedded in the cap-swap, the changes in value of the cap-swap are not completely effective in offsetting changes in value of the corresponding counter-swap. Changes in the value of cap-swaps and counter-swaps are recorded as adjustments to oil and natural gas sales.

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

Chesapeake enters into basis protection swaps for the purpose of locking-in a price differential for oil or natural gas from a specified delivery point. We currently have basis protection swaps covering six different

 

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

delivery points, four in the Mid-Continent and two in the Appalachian Basin, which correspond to the actual prices we receive for much of our natural gas production. By entering into these basis protection swaps, we have effectively reduced our exposure to market changes in future natural gas price differentials. As of September 30, 2006, the fair value of our basis protection swaps was $178.8 million. As of September 30, 2006, our Mid-Continent basis protection swaps cover approximately 29% of our anticipated remaining Mid-Continent natural gas production in 2006, 25% in 2007, 18% in 2008 and 13% in 2009. As of September 30, 2006, our Appalachian Basin basis protection swaps cover approximately 74% of our anticipated Appalachian Basin natural gas production in 2007, 65% in 2008 and 30% in 2009.

Gains or losses from certain derivative transactions are reflected as adjustments to oil and natural gas sales on the condensed consolidated statements of operations. Realized gains (losses) included in oil and natural gas sales were $301.4 million, ($122.6) million, $807.1 million and ($126.6) million in the Current Quarter, Prior Quarter, Current Period and Prior Period, respectively. Pursuant to SFAS 133, certain derivatives do not qualify for designation as cash flow hedges. Changes in the fair value of these non-qualifying derivatives that occur prior to their maturity (i.e., temporary fluctuations in value) are reported currently in the condensed consolidated statements of operations as unrealized gains (losses) within oil and natural gas sales. Unrealized gains (losses) included in oil and natural gas sales were $238.5 million, ($104.0) million, $452.6 million and ($137.1) million, in the Current Quarter, Prior Quarter, Current Period and Prior Period, respectively.

Following provisions of SFAS 133, 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 other comprehensive income until the hedged item is recognized in earnings. Any change in fair value resulting from ineffectiveness is recognized currently in oil and natural gas sales as unrealized gains (losses). We recorded an unrealized gain (loss) on ineffectiveness of $171.8 million, ($99.5) million, $336.7 million and ($98.9) million in the Current Quarter, Prior Quarter, Current Period and Prior Period, respectively.

The estimated fair values of our oil and natural gas derivative instruments as of September 30, 2006 and December 31, 2005 are provided below. The associated carrying values of these instruments are equal to the estimated fair values.

 

    

September 30,

2006

   

December 31,

2005

 
     ($ in thousands)  

Derivative assets (liabilities):

    

Fixed-price natural gas swaps

   $ 1,234,681     $ (1,047,094 )

Natural gas basis protection swaps

     178,832       307,308  

Fixed-price natural gas cap-swaps

     69,136       (161,056 )

Fixed-price natural gas counter-swaps

     6,646       37,785  

Natural gas call options (a)

     (21,816 )     (21,461 )

Fixed-price natural gas collars

     (7,016 )     (9,374 )

Fixed-price natural gas locked swaps

     (16,333 )     (34,229 )

Floating-price natural gas swaps

     —         2,607  

Fixed-price oil swaps

     13,547       (16,936 )

Fixed-price oil cap-swaps

     18,317       (3,364 )
                

Estimated fair value

   $ 1,475,994     $ (945,814 )
                

(a) After adjusting for $49.6 million and $23.0 million of unrealized premiums, the cumulative unrealized gain related to these call options as of September 30, 2006 and December 31, 2005 was $27.8 million and $1.6 million, respectively.

 

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

Based upon the market prices at September 30, 2006, we expect to transfer approximately $530.2 million (net of income taxes) of the gain included in the balance in accumulated other comprehensive income to earnings during the next 12 months in the related month of production. All transactions hedged as of September 30, 2006 are expected to mature by December 31, 2009.

We have two secured hedging facilities, each of which permits us to enter into cash-settled natural gas and oil commodity transactions, valued by the counterparty, for up to $500 million. The scheduled maturity date for each of these facilities is May 2010. Outstanding transactions under each facility are collateralized by certain of our oil and natural gas properties that do not secure any of our other obligations. Both of the hedging facilities are subject to a 1.0% per annum exposure fee, which is assessed quarterly on the average of the daily negative fair market value amounts, if any, during the quarter. As of September 30, 2006, the fair market value of the natural gas and oil hedging transactions was an asset of $252.1 million under one of the facilities and an asset of $823.2 million under the other facility. As of November 3, 2006, the fair market value of the same transactions was an asset of approximately $152.2 million and $255.5 million, respectively. The hedging facilities contain the standard representations and default provisions that are typical of such agreements. The agreements also contain various restrictive provisions which govern the aggregate natural gas and oil production volumes that we are permitted to hedge under all of our agreements at any one time.

We assumed certain liabilities related to open derivative positions in connection with our acquisition of Columbia Natural Resources, LLC in November 2005. In accordance with SFAS 141, these derivative positions were recorded at fair value in the purchase price allocation as a liability of $592 million. The recognition of the derivative liability and other assumed liabilities resulted in an increase in the total purchase price which was allocated to the assets acquired. Because of this accounting treatment, only cash settlements for changes in fair value subsequent to the acquisition date for the derivative positions assumed result in adjustments to our oil and natural gas revenues upon settlement. For example, if the fair value of the derivative positions assumed does not change, then upon the sale of the underlying production and corresponding settlement of the derivative positions, cash would be paid to the counterparties and there would be no adjustment to oil and natural gas revenues related to the derivative positions. If, however, the actual sales price is different from the price assumed in the original fair value calculation, the difference would be reflected as either a decrease or increase in oil and natural gas revenues, depending upon whether the sales price was higher or lower, respectively, than the prices assumed in the original fair value calculation. For accounting purposes, the net effect of these acquired hedges is that we hedged the production volumes at market prices on the date of our acquisition of CNR.

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

 

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

The following details the assumed CNR derivatives remaining as of September 30, 2006:

 

     Volume   

Weighted
Average

Fixed
Price to be
Received (Paid)

   Weighted
Average
Put
Fixed
Price
   Weighted
Average
Call
Fixed
Price
   SFAS 133
Hedge
  

Fair

Value at
September 30,
2006

($ in
thousands)

 

Natural Gas (mmbtu):

                 

Swaps:

                 

4Q 2006

   10,626,000    $ 4.86    $ —      $ —      Yes    $ (9,313 )

1Q 2007

   10,350,000      4.82      —        —      Yes      (30,297 )

2Q 2007

   10,465,000      4.82      —        —      Yes      (24,548 )

3Q 2007

   10,580,000      4.82      —        —      Yes      (26,672 )

4Q 2007

   10,580,000      4.82      —        —      Yes      (33,722 )

1Q 2008

   9,555,000      4.68      —        —      Yes      (39,074 )

2Q 2008

   9,555,000      4.68      —        —      Yes      (23,387 )

3Q 2008

   9,660,000      4.68      —        —      Yes      (24,581 )

4Q 2008

   9,660,000      4.66      —        —      Yes      (29,997 )

1Q 2009

   4,500,000      5.18      —        —      Yes      (14,498 )

2Q 2009

   4,550,000      5.18      —        —      Yes      (7,627 )

3Q 2009

   4,600,000      5.18      —        —      Yes      (8,162 )

4Q 2009

   4,600,000      5.18      —        —      Yes      (10,574 )

Collars:

                 

1Q 2009

   900,000      —        4.50      6.00    Yes      (2,538 )

2Q 2009

   910,000      —        4.50      6.00    Yes      (1,268 )

3Q 2009

   920,000      —        4.50      6.00    Yes      (1,375 )

4Q 2009

   920,000      —        4.50      6.00    Yes      (1,835 )
                       

Total Natural Gas

                  $ (289,468 )
                       

Subsequent to September 30, 2006, Chesapeake lifted a portion of its fourth quarter 2006 and full-year 2007, 2008 and 2009 hedges and as a result received $407 million in cash from its hedging counterparties. The gain will be recorded in accumulated other comprehensive income and in unrealized oil and natural gas sales based on the designation of the hedges. The gain will be recognized in realized oil and natural gas sales in the month of the hedged production.

Interest Rate Derivatives

We use interest rate derivatives to mitigate our exposure to the volatility in interest rates. For interest rate derivative instruments designated as fair value hedges (in accordance with SFAS 133), changes in fair value are recorded on the 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 derivative instruments not qualifying as fair value hedges are recorded currently as adjustments to interest expense.

Gains or losses from certain derivative transactions are reflected as adjustments to interest expense on the condensed consolidated statements of operations. Realized gains (losses) included in interest expense were ($1.6) million, $0.8 million, $0.9 million and $2.6 million in the Current Quarter, Prior Quarter, Current Period and

 

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

Prior Period, respectively. Pursuant to SFAS 133, certain derivatives do not qualify for designation as fair value hedges. Changes in the fair value of these non-qualifying derivatives that occur prior to their maturity (i.e., temporary fluctuations in value) are reported currently in the condensed consolidated statements of operations as unrealized gains (losses) within interest expense. Unrealized gains (losses) included in interest expense were $2.5 million, ($1.2) million, $0.8 million and $1.9 million, in the Current Quarter, Prior Quarter, Current Period and Prior Period, respectively.

As of September 30, 2006, the following interest rate swaps used to convert a portion of our long-term fixed-rate debt to floating-rate debt were outstanding:

 

Term

 

Notional

Amount

 

Fixed

Rate

   

Floating Rate

  Fair Value  
                  ($ in thousands)  

September 2004 – August 2012

  $ 75,000,000   9.000 %   6 month LIBOR plus 452 basis points   $ (2,919 )

July 2005 – January 2015

  $ 150,000,000   7.750 %   6 month LIBOR plus 289 basis points     (6,301 )

July 2005 – June 2014

  $ 150,000,000   7.500 %   6 month LIBOR plus 282 basis points     (6,456 )

September 2005 – August 2014

  $ 250,000,000   7.000 %   6 month LIBOR plus 205.5 basis points     (7,305 )

October 2005 – June 2015

  $ 200,000,000   6.375 %   6 month LIBOR plus 112 basis points     (3,308 )

October 2005 – January 2018

  $ 250,000,000   6.250 %   6 month LIBOR plus 99 basis points     (7,124 )

January 2006 – January 2016

  $ 250,000,000   6.625 %   6 month LIBOR plus 129 basis points     (3,178 )

March 2006 – January 2016

  $ 250,000,000   6.875 %   6 month LIBOR plus 120 basis points     (172 )
             
        $ (36,763 )
             

In the Current Period, we closed three interest rate swaps for gains totaling $3.0 million. These interest rate swaps were designated as fair value hedges, and the settlement amounts received will be amortized as a reduction to realized interest expense over the remaining terms of the related senior notes.

To mitigate our short-term exposure to rising interest rates on a portion of our long-term debt that has been converted to floating-rate, we have entered into zero-cost collar transactions. These collars contain a fixed floor rate (put) and fixed ceiling rate (call). If LIBOR exceeds the ceiling rate or falls below the floor rate, Chesapeake pays the fixed rate and receives LIBOR. If LIBOR is between the ceiling and floor rates, no payments are due from either party. As of September 30, 2006, we were a party to the following zero-cost interest rate collars:

 

Payment Dates

 

Notional Amount

 

LIBOR Floor

 

LIBOR Ceiling

July 2007 – January 2010

  $150,000,000   4.53%   5.37%

June 2007 – December 2009

  $150,000,000   4.53%   5.37%

August 2007 – February 2010

  $250,000,000   4.53%   5.37%

July 2007 – January 2010

  $250,000,000   4.53%   5.37%

Fair Value of Financial Instruments

The following disclosure of the estimated fair value of financial instruments is made in accordance with the requirements of Statement of Financial Accounting Standards No. 107, Disclosures About Fair Value of 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.

 

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

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 fixed-rate debt and our convertible preferred stock using primarily quoted market prices. Our carrying amounts for such debt, excluding discounts or premiums related to interest rate derivatives, at September 30, 2006 and December 31, 2005 were $6.421 billion and $5.429 billion, respectively, compared to approximate fair values of $6.317 billion and $5.582 billion, respectively. The carrying amounts for our convertible preferred stock as of September 30, 2006 and December 31, 2005 were $1.962 billion and $1.577 billion, respectively, compared to approximate fair values of $1.950 billion and $1.686 billion, respectively.

Concentration of Credit Risk

A significant portion of our liquidity is concentrated in derivative instruments that enable us to hedge a portion of our exposure to price volatility from producing oil and natural gas. These arrangements expose us to credit risk from our counterparties. Accounts receivable potentially subject us to concentrations of credit risk as well. Our accounts receivable are primarily from purchasers of oil and natural gas products 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 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.

3. Contingencies and Commitments

Litigation

Chesapeake is currently involved in various disputes incidental to its business operations. Management, after consultation with legal counsel, is of the opinion that the final resolution of all currently pending or threatened litigation is not likely to have a material adverse effect on our consolidated financial position, results of operations or cash flows.

Employment Agreements with Officers

Chesapeake has employment agreements with its chief executive officer, chief operating officer, chief financial officer and other executive officers, which provide for annual base salaries, various benefits and eligibility for bonus compensation. The agreement with the chief executive officer has a term of five years commencing July 1, 2006. The term of the agreement is automatically extended for one additional year on each January 31 unless the company provides 30 days notice of non-extension. In the event of termination of employment without cause, the chief executive officer’s base compensation and benefits would continue during the remaining term of the agreement. The agreements with the chief operating officer, chief financial officer and other executive officers expire on September 30, 2009 and provide for the continuation of salary for one year in the event of termination of employment without cause. The company’s employment agreements with the executive officers provide for payments in the event of a change of control. The chief executive officer is entitled to receive a payment in the amount of three times his base compensation and three times the value of the prior year’s benefits, plus a tax gross-up payment, upon the happening of certain events following a change of control, and the company will also provide him office space and secretarial and accounting support for a period of 12 months thereafter. The chief operating officer, chief financial officer and other executive officers are each entitled to receive a payment in the amount of two times his or her base compensation plus bonuses paid during the prior year in the event of a change of control. Any stock-based awards held by an executive officer will immediately become 100% vested upon termination of employment without cause or upon a change of control event.

 

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

Environmental Risk

Due to the nature of the oil and natural gas 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, 2006.

Rig Leases

In September 2006, our wholly owned subsidiary, Nomac Drilling Corporation, sold 18 of its drilling rigs and related equipment for $187.5 million and entered into a master lease agreement under which it agreed to lease the rigs from the buyer for an initial term of eight years from October 1, 2006 for rental payments of $26.0 million annually. Nomac’s lease obligations are guaranteed by Chesapeake and its other material domestic subsidiaries. This transaction was recorded as a sale and operating leaseback, with an aggregate deferred gain of $14.8 million on the sale which will be amortized to service operations expense over the lease term. Under the rig lease, we have the option to purchase the rigs on September 30, 2013 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 rental equal to the fair market rental value of the rigs as determined at the time of renewal.

Commitments related to these lease payments are not recorded in the accompanying consolidated balance sheets. As of September 30, 2006, minimum future rig lease payments were as follows (in thousands):

 

2006

   $ 6,130

2007

     25,993

2008

     25,993

2009

     25,993

2010

     25,993

Thereafter

     97,478
      

Total

   $ 207,580
      

Other Commitments

As of September 30, 2006, Chesapeake’s wholly owned subsidiary, Nomac Drilling Corporation, had contracted to acquire 22 rigs to be constructed during 2006 and 2007. The total remaining cost of the rigs will be approximately $200 million.

Currently, Chesapeake has contracts with various drilling contractors to use approximately 50 rigs in 2006 with terms of one to three years. As of September 30, 2006, the minimum aggregate drilling rig commitment was approximately $450 million.

 

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

Chesapeake and a leading investment bank have an agreement to lend Mountain Drilling Company, of which Chesapeake is a 49% equity owner, up to $25 million each through December 31, 2009. At September 30, 2006, there was a $19.5 million loan outstanding under this agreement.

As of September 30, 2006, Chesapeake had agreed to acquire 16,600 net acres of Barnett Shale leasehold from the Dallas/Fort Worth International Airport Board and the cities of Dallas and Fort Worth for $181 million in cash and a 25% royalty (subject to an assignment of a 20% interest to various minority and women businesses that will participate with Chesapeake in the development of the lease). This transaction closed on October 5, 2006.

As of September 30, 2006, Chesapeake had agreed to acquire oil and natural gas properties and mid-stream natural gas systems from Dale Resources, L.L.C. et al. for approximately $220 million of which $10.9 million was paid in the Current Quarter. This transaction closed on October 12, 2006.

4. Net Income Per Share

Statement of Financial Accounting Standards No. 128, Earnings Per Share, requires presentation of “basic” and “diluted” earnings per share, as defined, on the face of the statements of operations for all entities with complex capital structures. SFAS 128 requires a reconciliation of the numerator and denominator of the basic and diluted EPS computations.

The following securities were not included in the calculation of diluted earnings per share, as the effect was antidilutive:

 

    For the Current Quarter, Prior Quarter and the Prior Period, outstanding options to purchase 0.1 million shares of common stock at a weighted average exercise price of $30.63, $30.59 and $29.85, respectively, were antidilutive because the exercise price of the options was greater than the average market price of the common stock during the period.

 

    For the Prior Quarter and Prior Period, diluted shares do not include the common stock equivalent of our 4.125% preferred stock outstanding prior to conversion (convertible into 3,913,918 and 8,403,579 shares, respectively), and the preferred stock adjustment to net income does not include $14.7 million and $22.9 million, respectively, of dividends and loss on conversion related to these preferred shares, as the effect on diluted earnings per share would have been antidilutive.

 

    For the Prior Quarter and Prior Period, diluted shares do not include the common stock equivalent of our 5.0% (Series 2003) preferred stock outstanding prior to conversion (convertible into 3,603,567 and 4,034,450 shares, respectively), and the preferred stock adjustment to net income does not include $4.0 million and $5.8 million, respectively, of dividends and loss on conversion related to these preferred shares, as the effect on diluted earnings per share would have been antidilutive.

 

    For the Prior Quarter and the Prior Period, diluted shares do not include the common stock equivalent of our 4.5% preferred stock outstanding prior to conversion (convertible into 1,443,236 and 486,365 shares, respectively), and the preferred stock adjustment to net income does not include $0.7 million and $0.7 million, respectively, of dividends related to these preferred shares, as the effect on diluted earnings per share would have been antidilutive.

 

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

Reconciliations for the three months ended September 30, 2006 and 2005 and the nine months ended September 30, 2006 and 2005 are as follows:

 

For the Three Months Ended September 30, 2006:

 

Income

(Numerator)

 

Shares

(Denominator)

 

Per

Share

Amount

    ($ in thousands, except per share data)

Basic EPS:

     

Income available to common shareholders

  $ 522,582   417,569   $ 1.25
               

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 4.125% convertible preferred stock

    —     184  

Common shares assumed issued for 4.50% convertible preferred stock

    —     7,811  

Common shares assumed issued for 5.00% convertible preferred stock (Series 2003)

    —     235  

Common shares assumed issued for 5.00% convertible preferred stock (Series 2005)

    —     17,856  

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

    —     14,717  

Common shares assumed issued for 6.25% convertible preferred stock

    —     19,100  

Employee stock options

    —     4,248  

Restricted stock

    —     1,553  

Preferred stock dividends

    25,753   —    
           

Diluted EPS Income available to common shareholders and assumed conversions

  $ 548,335   483,273   $ 1.13
               

For the Three Months Ended September 30, 2005:

           

Basic EPS:

     

Income available to common shareholders

  $ 149,059   322,101   $ 0.46
               

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 4.125% convertible preferred stock

    —     8,082  

Common shares assumed issued for 5.00% convertible preferred stock (Series 2003)

    —     6,262  

Common shares assumed issued for 5.00% convertible preferred stock (Series 2005)

    —     17,853  

Common shares assumed issued for 6.00% convertible preferred stock

    —     492  

Employee stock options

    —     11,006  

Restricted stock

    —     1,843  

Preferred stock dividends

    8,498   —    
           

Diluted EPS Income available to common shareholders and assumed conversions

  $ 157,557   367,639   $ 0.43
               

 

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

For the Nine Months Ended September 30, 2006:

 

Income

(Numerator)

 

Shares

(Denominator)

 

Per

Share

Amount

    ($ in thousands, except per share data)

Basic EPS:

     

Income available to common shareholders

  $ 1,458,612   389,136   $ 3.75
               

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 4.125% convertible preferred stock

    —     184  

Common shares assumed issued for 4.50% convertible preferred stock

    —     7,811  

Common shares assumed issued for 5.00% convertible preferred stock (Series 2003)

    —     235  

Common shares assumed issued for 5.00% convertible preferred stock (Series 2005)

    —     17,856  

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

    —     14,717  

Common shares assumed issued for 6.25% convertible preferred stock

    —     6,498  

Assumed conversion as of the beginning of the period of preferred shares outstanding prior to conversion:

     

Common stock equivalent of preferred stock outstanding prior to conversion,

     

6.00% convertible preferred stock

    —     137  

4.125% convertible preferred stock

    —     2,795  

5.00% convertible preferred stock (Series 2003)

    —     2,807  

Employee stock options

    —     6,714  

Restricted stock

    —     1,790  

Loss on redemption of preferred stock

    10,556   —    

Preferred stock dividends

    62,793   —    
           

Diluted EPS Income available to common shareholders and assumed conversions

  $ 1,531,961   450,680   $ 3.40
               

For the Nine Months Ended September 30, 2005:

           

Basic EPS:

     

Income available to common shareholders

  $ 447,783   314,425   $ 1.42
               

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 4.125% convertible preferred stock

    —     8,082  

Common shares assumed issued for 5.00% convertible preferred stock (Series 2003)

    —     6,262  

Common shares assumed issued for 5.00% convertible preferred stock (Series 2005)

    —     10,739  

Common shares assumed issued for 6.00% convertible preferred stock

    —     492  

Assumed conversion as of the beginning of the period of preferred shares outstanding prior to conversion:

     

Common stock equivalent of preferred stock outstanding prior to conversion,

     

6.00% convertible preferred stock

    —     5  

Employee stock options

    —     10,810  

Restricted stock

    —     1,382  

Warrants assumed in Gothic acquisition

    —     13  

Preferred stock dividends

    18,546   —    
           

Diluted EPS Income available to common shareholders and assumed conversions

  $ 466,329   352,210   $ 1.32
               

 

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

5. Stockholders’ Equity

The following is a summary of the changes in our common shares outstanding for the nine months ended September 30, 2006 and 2005:

 

     2006    2005
     (in thousands)

Shares outstanding at January 1

   375,511    316,941

Stock option and warrant exercises

   6,676    3,820

Restricted stock issuances

   13,530    3,619

Preferred stock conversions/exchanges

   12,016    15,804

Common stock issuances

   28,750    9,200

Common stock issued for the purchase of Chaparral Energy, Inc. common stock

   1,376    —  
         

Shares outstanding at September 30

   437,859    349,384
         

The following is a summary of the changes in our preferred shares outstanding for the nine months ended September 30, 2006 and 2005:

 

     6.00%    

5.00%

(2003)

    4.125%    

5.00%

(2005)

   4.50%   

5.00%

(2005B)

   6.25%
     (in thousands)

Shares outstanding at January 1, 2006

   99     1,026     89     4,600    3,450    5,750    —  

Preferred stock issuances

   —       —       —       —      —      —      2,300

Conversion/exchange of preferred for common stock

   (99 )   (987 )   (86 )   —      —      —      —  
                                     

Shares outstanding at September 30, 2006

   —       39     3     4,600    3,450    5,750    2,300
                                     

Shares outstanding at January 1, 2005

   103     1,725     313     —      —      —      —  

Preferred stock issuances

   —       —       —       4,600    3,450    —      —  

Conversion/exchange of preferred for common stock

   (2 )   (698 )   (178 )   —      —      —      —  
                                     

Shares outstanding at September 30, 2005

   101     1,027     135     4,600    3,450    —      —  
                                     

In connection with the exchanges and conversions noted above, we recorded a loss of $17.7 million, $10.6 million and $22.5 million in the Prior Quarter, Current Period and Prior Period, respectively. In general, the loss is equal to the excess of the fair value of all common stock exchanged over the fair value of the securities issuable pursuant to the original conversion terms of the preferred stock.

During the Current Period, holders of our 5.0% (Series 2003) cumulative convertible preferred stock exchanged 183,273 shares for 1,140,223 shares of our common stock.

During the Current Period, holders of our 4.125% cumulative convertible preferred stock exchanged 2,750 shares for 172,594 shares of our common stock.

During the Current Period, the remaining 99,310 shares of our 6.0% preferred stock were converted into or exchanged for 482,694 shares of common stock.

During the Current Period, we completed tender offers for our 4.125% and 5.0% (Series 2003) cumulative convertible preferred stock, issuing 5.2 million shares of our common stock in exchange for 83,245 shares of the

 

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

4.125% preferred stock, which represented 96.4% or $83.2 million of the aggregate liquidation value of the shares outstanding, and 5.0 million shares of our common stock in exchange for 804,048 shares of the 5.0% (Series 2003) preferred stock, which represented 95.4% or $80.4 million of the aggregate liquidation value of the shares outstanding. No cash was received or paid in connection with these transactions.

In June 2006, we issued 2,000,000 shares of 6.25% mandatory convertible preferred stock, par value $0.01 per share and liquidation preference $250 per share, in a public offering for net proceeds of $484.8 million. We issued an additional 300,000 shares of such preferred stock in July 2006, upon the exercise of the underwriters’ option to purchase the additional shares, for net proceeds of $72.8 million.

In June 2006, we issued 25,000,000 shares of Chesapeake common stock at $29.05 per share in a public offering for net proceeds of $698.9 million. We issued an additional 3,750,000 shares in July 2006 at the same price pursuant to the underwriters’ exercise of their overallotment option to purchase the additional shares for net proceeds of $104.8 million.

In the Current Quarter, we issued 9.9 million shares of restricted stock to our employees (except for our CEO and CFO, who did not participate in the stock awards) under a long-term stock incentive and retention program. These shares vest 50% in three years with the remaining 50% vesting in five years.

In September 2006, we acquired 32% of the outstanding common stock of Chaparral Energy, Inc. for $240 million in cash and 1,375,989 newly issued shares of our common stock valued at $40 million. Chaparral is a privately-held independent oil and natural gas company headquartered in Oklahoma City, Oklahoma, with estimated proved reserves of approximately 618 bcfe and daily production of approximately 83 mmcfe.

6. Senior Notes and Revolving Bank Credit Facility

Our long-term debt consisted of the following as of September 30, 2006 and December 31, 2005:

 

    

September 30,

2006

   

December 31,

2005

 
     ($ in thousands)  

7.5% Senior Notes due 2013

   $ 363,823     $ 363,823  

7.625% Senior Notes due 2013

     500,000       —    

7.0% Senior Notes due 2014

     300,000       300,000  

7.5% Senior Notes due 2014

     300,000       300,000  

7.75% Senior Notes due 2015

     300,408       300,408  

6.375% Senior Notes due 2015

     600,000       600,000  

6.625% Senior Notes due 2016

     600,000       600,000  

6.875% Senior Notes due 2016

     670,437       670,437  

6.5% Senior Notes due 2017

     1,100,000       600,000  

6.25% Senior Notes due 2018

     600,000       600,000  

6.875% Senior Notes due 2020

     500,000       500,000  

2.75% Contingent Convertible Senior Notes due 2035 (a)

     690,000       690,000  

Revolving bank credit facility

     1,464,000       72,000  

Discount on senior notes

     (103,939 )     (95,577 )

Discount for interest rate derivatives (b)

     (23,621 )     (11,349 )
                

Total senior notes and long-term debt

   $ 7,861,108     $ 5,489,742  
                

(a)

The holders of the 2.75% Contingent Convertible Senior Notes due 2035 may require us to repurchase all or a portion of these notes on November 15, 2015, 2020, 2025 and 2030, or upon a fundamental change, at

 

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

 

100% of the principal amount of these notes. 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. In general, upon conversion of a 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. In addition, we will pay contingent interest on the convertible senior notes, beginning with the nine-month period ending May 14, 2016, under certain conditions. We may redeem the convertible senior notes on or after November 15, 2015 at a redemption price of 100% of the principal amount of such notes.

(b) See Note 2 for a description of these instruments.

No scheduled principal payments are required under our senior notes until 2013 when $863.8 million is due.

There were no repurchases or exchanges of Chesapeake debt in the Current Quarter or the Current Period. The following table sets forth the losses we incurred in connection with repurchases of senior notes in the Prior Quarter and Prior Period, respectively ($ in millions):

 

    

Notes

Retired

   Loss on Repurchases/Exchanges

For the Three Months Ended September 30, 2005:

      Premium    Other(a)    Total

8.125% Senior Notes due 2011

   $ 7.6    $ 0.5    $ 0.1    $ 0.6

9.0% Senior Notes due 2012

     1.1      0.1      0.0      0.1
                           
   $ 8.7    $ 0.6    $ 0.1    $ 0.7
                           

For the Nine Months Ended September 30, 2005:

                   

8.375% Senior Notes due 2008

   $ 11.0    $ 0.8    $ 0.1    $ 0.9

8.125% Senior Notes due 2011

     245.4      17.3      4.4      21.7

9.0% Senior Notes due 2012

     300.0      41.4      6.0      47.4
                           
   $ 556.4    $ 59.5    $ 10.5    $ 70.0
                           

(a) Includes the write-off of unamortized discounts, deferred charges, transaction costs and derivative charges.

Our outstanding senior notes are unsecured senior obligations of Chesapeake that rank equally in right of payment with all of our existing and future senior indebtedness and rank senior in right of payment to all of our future subordinated indebtedness. We may redeem the senior notes, other than the 2.75% Contingent Convertible Senior Notes due 2035, at any time at specified make-whole or redemption prices. Senior notes issued before July 2005 are governed by indentures containing covenants that limit our ability and our restricted subsidiaries’ ability to incur additional indebtedness; pay dividends on our capital stock or redeem, repurchase or retire our capital stock or subordinated indebtedness; make investments and other restricted payments; incur liens; enter into sale-leaseback transactions; create restrictions on the payment of dividends or other amounts to us from our restricted subsidiaries; engage in transactions with affiliates; sell assets; and consolidate, merge or transfer assets. Senior notes issued after June 2005 are governed by indentures containing covenants that limit our ability and our restricted subsidiaries’ ability to incur certain secured indebtedness; enter into sale-leaseback transactions; and consolidate, merge or transfer assets.

Chesapeake 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 have been fully and unconditionally guaranteed, jointly and severally, by all of our wholly owned subsidiaries, other than minor subsidiaries, on a senior unsecured basis.

 

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

We have a $2.5 billion syndicated revolving bank credit facility which matures in February 2011. The credit facility was increased from $1.25 billion to $2.0 billion in February 2006 and to $2.5 billion in September 2006. As of September 30, 2006, we had $1.464 billion in outstanding borrowings under our facility and utilized $6.2 million of the facility for various letters of credit. Borrowings under our facility are collateralized by certain producing oil and natural gas properties and bear interest at either (i) the greater of the reference rate of Union Bank of California, N.A. or the federal funds effective rate plus 0.50% or (ii) the London Interbank Offered Rate (LIBOR), at our option, plus a margin that varies from 0.875% to 1.50% 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 that also varies according to our senior unsecured long-term debt ratings, from 0.125% to 0.30% per annum. Currently, the commitment fee rate is 0.25% per annum. Interest is payable quarterly or, if LIBOR applies, it may be payable at more frequent intervals.

The credit facility agreement contains various covenants and restrictive provisions which govern our ability to incur additional indebtedness, make investments or loans and create liens. The credit facility agreement requires us to maintain an indebtedness to total capitalization ratio (as defined) not to exceed 0.65 to 1 and an indebtedness to EBITDA ratio (as defined) not to exceed 3.5 to 1. As defined by the credit facility agreement, our indebtedness to total capitalization ratio was 0.44 to 1 and our indebtedness to EBITDA ratio was 1.87 to 1 at September 30, 2006. If we should fail to perform our obligations under these and other covenants, the revolving credit commitment could be terminated and any outstanding borrowings under the facility could be declared immediately due and payable. Such acceleration, if involving a principal amount of $10 million ($50 million in the case of our senior notes issued after 2004), would constitute an event of default under our senior note indentures, which could in turn result in the acceleration of a significant portion of our senior note indebtedness. The credit facility agreement also has cross default provisions that apply to other indebtedness we may have with an outstanding principal amount in excess of $75 million.

Two of our subsidiaries, Chesapeake Exploration Limited Partnership and Chesapeake Appalachia, L.L.C., are the borrowers under our revolving bank credit facility. The facility is fully and unconditionally guaranteed, on a joint and several basis, by Chesapeake and all of our other wholly owned subsidiaries except minor subsidiaries.

7. Segment Information

In accordance with Statement of Financial Accounting Standards No. 131, Disclosures about Segments of an Enterprise and Related Information, we have two reportable operating segments. Our exploration and production segment and oil and natural gas marketing 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 crude oil. The marketing segment is responsible for gathering, processing, compressing, transporting and selling natural gas and crude oil primarily from Chesapeake-operated wells. We also have drilling rig and trucking operations, which were considered a part of the exploration and production segment prior to 2006. These service operations 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.

Management evaluates the performance of our segments based upon income before income taxes. Revenues from the marketing segment’s sale of oil and natural gas related to Chesapeake’s ownership interests are reflected as exploration and production revenues. Such amounts totaled $631.0 million, $617.4 million, $1.919 billion and

 

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

$1.486 billion for the Current Quarter, Prior Quarter, Current Period and Prior Period, respectively. The following table presents selected financial information for Chesapeake’s operating segments. Our drilling rig and trucking service operations are presented in “Other Operations” for all periods presented.

 

For the Three Months Ended September 30, 2006:

  Exploration
and Production
  Marketing     Other
Operations
    Intercompany
Eliminations
    Consolidated
Total
    ($ in thousands)

Revenues

  $ 1,493,226   $ 1,029,126     $ 98,401     $ (691,342 )   $ 1,929,411

Intersegment revenues

    —       (631,012 )     (60,330 )     691,342       —  
                                   

Total revenues

  $ 1,493,226   $ 398,114     $ 38,071     $ —       $ 1,929,411
                                   

Income before income taxes

  $ 866,789   $ 9,661     $ 33,900     $ (25,941 )   $ 884,409
                                   

For the Three Months Ended September 30, 2005:

                         

Revenues

  $ 720,928   $ 979,281     $ 16,405     $ (633,771 )   $ 1,082,843

Intersegment revenues

    —       (617,366 )     (16,405 )     633,771       —  
                                   

Total revenues

  $ 720,928   $ 361,915     $ —       $ —       $ 1,082,843
                                   

Income before income taxes

  $ 271,835   $ 6,887     $ 1,823     $ (1,823 )   $ 278,722
                                   

For the Nine Months Ended September 30, 2006:

                         

Revenues

  $ 4,190,430   $ 3,089,348     $ 218,909     $ (2,040,693 )   $ 5,457,994

Intersegment revenues

    —       (1,919,257 )     (121,436 )     2,040,693       —  
                                   

Total revenues

  $ 4,190,430   $ 1,170,091     $ 97,473     $ —       $ 5,457,994
                                   

Income before income taxes

  $ 2,448,286   $ 29,099     $ 67,653     $ (49,941 )   $ 2,495,097
                                   

For the Nine Months Ended September 30, 2005:

                         

Revenues

  $ 2,032,271   $ 2,368,502     $ 39,587     $ (1,526,049 )   $ 2,914,311

Intersegment revenues

    —       (1,486,462 )     (39,587 )     1,526,049       —  
                                   

Total revenues

  $ 2,032,271   $ 882,040     $ —       $ —       $ 2,914,311
                                   

Income before income taxes

  $ 764,200   $ 16,554     $ 4,638     $ (4,638 )   $ 780,754
                                   

As of September 30, 2006:

                         

Total assets

  $ 22,669,668   $ 667,399     $ 532,414     $ (474,560 )   $ 23,394,921

As of December 31, 2005:

                         

Total assets

  $ 15,722,795   $ 688,747     $ 305,875     $ (598,955 )   $ 16,118,462

 

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

8. Acquisitions

Oil and Natural Gas Properties

The following table describes oil and natural gas property acquisitions of proved and unproved properties that we completed in the Current Period ($ in millions):

 

Quarter

  

Acquired From

  

Location of Properties

   Amount  

First

   Midland-based oil and gas company    Ark-La-Tex and Barnett Shale    $ 272  
   Tulsa-based oil and gas company    Texas Gulf Coast and Mid-Continent      146  
   Houston-based oil and gas company    Texas Gulf Coast      125  
   Tulsa-based oil and gas company    Ark-La-Tex      70  
   Houston-based oil and gas company    Various      53  
   Dallas-based oil and gas company    Mid-Continent      30  
   Other    Various      297  

Second

   Dallas-based oil and gas company    Permian      375  
   Oklahoma City-based oil and gas company    Permian      175  
   Other    Various      196  

Third

  

Four Sevens Oil Co., Ltd. and
Sinclair Oil Corporation

   Barnett Shale      845 (a)
   Dallas-based oil and gas company    Ark-La-Tex and Texas Gulf Coast      200  
   Houston-based oil and gas company    Texas Gulf Coast      111  
   Other    Various      285  
              
  

Total oil and natural gas acquisitions

      $ 3,180  
              

(a) Includes $55 million related to mid-stream natural gas systems which was allocated to other property and equipment.

We also recorded approximately $177.7 million of deferred income taxes to reflect the tax effect of the cost paid in excess of the tax basis acquired on certain corporate acquisitions.

Drilling Rigs and Oilfield Trucks

In January 2006, we acquired a privately-owned Oklahoma-based oilfield trucking service company for $47.5 million. In addition to the cash purchase price, we recorded approximately $17.0 million of deferred income taxes to reflect the tax effect of the cost paid in excess of the tax basis acquired in connection with this acquisition. Of the total $64.5 million purchase price, $27.1 million was allocated to tangible equipment, $11.0 million to intangibles and $26.4 million to goodwill. The amounts allocated to intangibles and goodwill are included in long-term assets in the accompanying condensed consolidated balance sheet. Goodwill is not amortized but is subject to an annual assessment of impairment. In February 2006, we acquired 13 drilling rigs and related assets through our wholly-owned subsidiary, Nomac Drilling Corporation, from Martex Drilling Company, L.L.P., a privately-owned drilling contractor with operations in East Texas and North Louisiana, for $150 million. In July 2006, we acquired a drilling contractor and an affiliated trucking company in the Appalachian Basin for approximately $70 million in cash.

 

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

Other

In August 2006, we invested $254 million to acquire a 19.9% interest in a privately-held provider of well stimulation and high pressure pumping services, with operations currently focused in Texas (principally in the Fort Worth Barnett Shale) and the Rocky Mountains. In September 2006, we acquired 32% of the outstanding common stock of Chaparral Energy, Inc. for $240 million in cash and 1,375,989 newly issued shares of our common stock valued at $40 million. Chaparral is a privately-held independent oil and natural gas company headquartered in Oklahoma City, Oklahoma, with estimated proved reserves of approximately 618 bcfe and daily production of 83 mmcfe.

9. Full-Cost Ceiling Test

We review the carrying value of our oil and natural gas properties under the full-cost accounting rules of the Securities and Exchange Commission (SEC) on a quarterly and annual basis. This review is referred to as a ceiling test. Under the ceiling test, capitalized costs, less accumulated amortization and related deferred income taxes, may not exceed an amount equal to the sum of the present value of estimated future net revenues (including the impact of cash flow hedges) less estimated future expenditures to be incurred in developing and producing the proved reserves, less any related income tax effects. The two primary factors impacting this test are reserve levels and current prices, and their associated impact on the present value of estimated future net revenues. Revisions to the estimates of natural gas and oil reserves and/or an increase or decrease in prices can have a material impact on the present value of estimated future net revenues. Any excess of the net book value, less deferred income taxes, is generally written off as an expense. Under SEC regulations, the excess above the ceiling is not expensed (or is reduced) if, subsequent to the end of the period, but prior to the release of the financial statements, oil and natural gas prices increase sufficiently such that an excess above the ceiling would have been eliminated (or reduced) if the increased prices were used in the calculations.

In calculating future net revenues, current prices and costs used are those as of the end of the appropriate quarterly period. Such prices are utilized except where different prices are fixed and determinable from applicable contracts for the remaining term of those contracts, including the effects of derivatives qualifying as cash flow hedges. Such derivative contracts, which consist of swaps and collars, and the related production volumes are discussed in Note 2 and in Item 3. Quantitative and Qualitative Disclosures About Market Risk. Based on spot prices for oil and natural gas as of September 30, 2006, these cash flow hedges increased the full cost ceiling by $4.4 billion, thereby reducing any potential ceiling test write-down by the same amount.

At December 31, 2005, Chesapeake’s net book value of oil and natural gas properties less deferred income taxes was below the calculated ceiling by approximately $6.5 billion. From December 31, 2005 to September 30, 2006, spot natural gas prices decreased by approximately 59% from $10.08 to $4.18 per mcf. As a result, as of September 30, 2006, our ceiling test calculation indicated an impairment of our oil and natural gas properties of approximately $415 million, net of income tax. However, natural gas prices subsequent to September 30, 2006, have improved sufficiently to eliminate this calculated impairment. As a result, we were not required to record a write-down of our oil and natural gas properties under the full-cost method of accounting in the third quarter of 2006.

10. Recently Issued 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.

 

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

In December 2004, the FASB issued SFAS 123(R), Share-Based Payment, a revision of SFAS 123, Accounting for Stock-Based Compensation. This statement establishes standards for the accounting for transactions in which an entity exchanges its equity instruments for goods or services by requiring a public entity to measure the cost of employee services received in exchange for an award of equity instruments based on the grant-date fair value of the award. We adopted this statement effective January 1, 2006. The effect of SFAS 123(R) is more fully described in Note 1.

In September 2005, the Emerging Issues Task Force (EITF) reached a consensus on Issue No. 04-13, Accounting for Purchases and Sales of Inventory with the Same Counterparty. EITF Issue No. 04-13 requires that purchases and sales of inventory with the same counterparty in the same line of business should be accounted for as a single non-monetary exchange, if entered into in contemplation of one another. The consensus is effective for inventory arrangements entered into, modified or renewed in interim or annual reporting periods beginning after March 15, 2006. We adopted this issue effective April 1, 2006. The adoption of EITF Issue No. 04-13 did not have a material impact on our financial statements.

In June 2006, the FASB issued FASB Interpretation (FIN) No. 48, Accounting for Uncertainty in Income Taxes—an interpretation of FASB Statement No. 109. FIN 48 provides guidance for recognizing and measuring uncertain tax positions, as defined in SFAS 109, Accounting for Income Taxes. FIN 48 prescribes a threshold condition that a tax position must meet for any of the benefit of the uncertain tax position to be recognized in the financial statements. Guidance is also provided regarding de-recognition, classification and disclosure of these uncertain tax positions. FIN 48 is effective for fiscal years beginning after December 15, 2006. We do not expect that FIN 48 will have a material impact on our financial position, results of operations or cash flows.

In February 2006, the FASB issued SFAS No. 155, Accounting for Certain Hybrid Financial Instruments—an amendment of FASB Statements No. 133 and 140. SFAS 155 permits an entity to measure at fair value any financial instrument that contains an embedded derivative that otherwise would require bifurcation. This statement is effective for all financial instruments acquired or issued after the beginning of an entity’s first fiscal year that begins after September 15, 2006. We are currently evaluating the provisions of SFAS 155 and believe that adoption will not have a material effect on our financial position, results of operations or cash flows.

In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements. This statement defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles (GAAP), and expands disclosures about fair value measurements. This statement is effective for financial statements issued for fiscal years beginning after November 15, 2007. We are currently assessing the impact, if any, SFAS 157 will have on our financial position, results of operations or cash flows.

In September 2006, the FASB issued SFAS No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans. This statement requires an employer to recognize the overfunded or underfunded status of a defined benefit postretirement plan (other than a multiemployer plan) as an asset or liability in its statement of financial position and to recognize changes in that funded status in the year in which the changes occur through comprehensive income. This statement is effective as of the end of the fiscal year ending after December 15, 2006. We do not expect that SFAS 158 will have a material impact on our financial position, results of operations or cash flows.

 

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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, oil and natural gas sales, average sales prices received, other operating income and expenses for the three and nine months ended September 30, 2006 (the “Current Quarter” and the “Current Period”) and the three and nine months ended September 30, 2005 (the “Prior Quarter” and the “Prior Period”):

 

    Three Months Ended
September 30,
    Nine Months Ended
September 30,
 
    2006     2005     2006     2005  

Net Production:

       

Oil (mbbls)

    2,178       1,926       6,437       5,684  

Natural gas (mmcf)

    133,822       108,801       387,696       304,060  

Natural gas equivalent (mmcfe)

    146,890       120,357       426,318       338,164  

Oil and Natural Gas Sales ($ in thousands):

       

Oil sales

  $ 141,687     $ 113,590     $ 404,595     $ 290,332  

Oil derivatives – realized gains (losses)

    (9,660 )     (10,937 )     (25,695 )     (28,654 )

Oil derivatives – unrealized gains (losses)

    28,724       (4,009 )     24,825       (5,951 )
                               

Total oil sales

    160,751       98,644       403,725       255,727  
                               

Natural gas sales

    811,591       833,992       2,526,168       2,005,670  

Natural gas derivatives – realized gains (losses)

    311,090       (111,668 )     832,769       (97,955 )

Natural gas derivatives – unrealized gains (losses)

    209,794       (100,040 )     427,768       (131,171 )
                               

Total natural gas sales

    1,332,475       622,284       3,786,705       1,776,544  
                               

Total oil and natural gas sales

  $ 1,493,226     $ 720,928     $ 4,190,430     $ 2,032,271  
                               

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

       

Oil ($ per bbl)

  $ 65.05     $ 58.98     $ 62.85     $ 51.08  

Natural gas ($ per mcf)

  $ 6.06     $ 7.67     $ 6.52     $ 6.60  

Natural gas equivalent ($ per mcfe)

  $ 6.49     $ 7.87     $ 6.87     $ 6.79  

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

       

Oil ($ per bbl)

  $ 60.62     $ 53.30     $ 58.86     $ 46.04  

Natural gas ($ per mcf)

  $ 8.39     $ 6.64     $ 8.66     $ 6.27  

Natural gas equivalent ($ per mcfe)

  $ 8.54     $ 6.85     $ 8.77     $ 6.42  

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

       

Oil and natural gas marketing

  $ 13,641     $ 8,405     $ 38,570     $ 21,251  

Service operations

  $ 19,250     $ —       $ 48,548     $ —    

Other Operating Income ($ per mcfe):

       

Oil and natural gas marketing

  $ 0.09     $ 0.07     $ 0.09     $ 0.06  

Service operations

  $ 0.13     $ —       $ 0.11     $ —    

Expenses ($ per mcfe):

       

Production expenses

  $ 0.84     $ 0.67     $ 0.85     $ 0.66  

Production taxes

  $ 0.28     $ 0.44     $ 0.30     $ 0.40  

General and administrative expenses

  $ 0.25     $ 0.13     $ 0.23     $ 0.12  

Oil and natural gas depreciation, depletion and amortization

  $ 2.34     $ 1.92     $ 2.29     $ 1.84  

Depreciation and amortization of other assets

  $ 0.18     $ 0.11     $ 0.17     $ 0.10  

Interest expense (b)

  $ 0.52     $ 0.48     $ 0.52     $ 0.47  

Interest Expense ($ in thousands):

       

Interest expense

  $ 75,100     $ 58,206     $ 221,832     $ 160,209  

Interest rate derivatives – realized (gains) losses

    1,555       (843 )     (852 )     (2,639 )

Interest rate derivatives – unrealized (gains) losses

    (2,543 )     1,230       (754 )     (1,947 )
                               

Total interest expense

  $ 74,112     $ 58,593     $ 220,226     $ 155,623  
                               

Net Wells Drilled

    401       218       985       583  

Net Producing Wells as of the End of the Period

    18,511       9,313       18,511       9,313  

(a) Includes revenue and operating costs.
(b) Includes the effects of realized gains (losses) from interest rate derivatives, but does not include the effects of unrealized gains (losses) and is net of amounts capitalized.

 

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Chesapeake is the third largest independent producer of natural gas in the United States. We own interests in approximately 33,700 producing oil and natural gas wells that are currently producing approximately 1.66 bcfe per day, which includes approximately 0.1 bcfe per day of previously curtailed production that is now back on line. Our strategy is focused on discovering, developing and acquiring onshore natural gas reserves in the U.S. east of the Rocky Mountains. Our most important operating area has historically been in various conventional plays in the Mid-Continent region, which includes Oklahoma, Arkansas, Kansas and the Texas Panhandle. At September 30, 2006, 47% of our estimated proved oil and natural gas reserves were located in the Mid-Continent. During the past four years, we have also built significant positions in various conventional and unconventional plays in the South Texas and Texas Gulf Coast regions, the Permian Basin of West Texas and eastern New Mexico, the Barnett Shale area of North Texas, the Ark-La-Tex area of East Texas and northern Louisiana, the Appalachian Basin in West Virginia, eastern Kentucky, eastern Ohio and southern New York, the Caney and Woodford Shales in southeastern Oklahoma, the Fayetteville Shale in Arkansas, the Barnett and Woodford Shales in West Texas and the Conasauga, Floyd and Chattanooga Shales of Alabama.

Oil and natural gas production for the Current Quarter was 146.9 bcfe, an increase of 26.5 bcfe, or 22% over the 120.4 bcfe produced in the Prior Quarter. We have increased our production for 21 consecutive quarters. During these 21 quarters, Chesapeake’s U.S. production has increased 308% for an average compound quarterly growth rate of 6.9% and an average compound annual growth rate of 30.5%.

In addition to increased oil and natural gas production, the prices we received were higher in the Current Quarter than in the Prior Quarter. On a natural gas equivalent basis, weighted average prices (excluding the effect of unrealized gains or losses on derivatives) were $8.54 per mcfe in the Current Quarter compared to $6.85 per mcfe in the Prior Quarter. The increase in prices resulted in an increase in revenue of $247.9 million, and increased production resulted in an increase in revenue of $181.8 million, for a total increase in revenue of $429.7 million (excluding the effect of unrealized gains or losses on derivatives). In each of the operating areas where Chesapeake sells its oil and natural gas, established marketing and transportation infrastructures exist, thereby contributing to relatively high wellhead price realizations for our production.

During the Current Quarter, Chesapeake continued to lead the nation in drilling activity with an average utilization of 103 operated rigs and 71 non-operated rigs. Through this drilling activity, we drilled 411 (348 net) operated wells and participated in another 353 (53 net) wells operated by other companies. The company’s drilling success rate was 99% for company-operated wells and 96% for non-operated wells. During the Current Quarter, Chesapeake invested $674 million in operated wells, $119 million in non-operated wells and $162 million in acquiring 3-D seismic data and leasehold (excluding leasehold acquired through acquisitions). Our acquisition expenditures totaled $1.391 billion during the Current Quarter, including amounts paid for unproved leasehold and excluding $96.3 million of deferred income taxes in connection with certain corporate acquisitions. We expect to continue replacing reserves through the drillbit and acquisitions, although the timing and magnitude of future additions are uncertain.

Chesapeake began 2006 with estimated proved reserves of 7.521 tcfe and based on internal estimates ended the Current Quarter with 8.433 tcfe, an increase of 912 bcfe, or 12%. During the Current Period, we replaced 426 bcfe of production with an estimated 1.339 tcfe of new proved reserves, for a reserve replacement rate of 314%. Reserve replacement through the drillbit was 825 bcfe, or 194% of production (including 541 bcfe of positive performance revisions and 387 bcfe of downward revisions resulting from natural gas price declines between December 31, 2005 and September 30, 2006) and 62% of the total increase. Reserve replacement through the acquisition of proved reserves was 514 bcfe, or 120% of production and 38% of the total increase. Based on our current drilling schedule and budget, we expect that virtually all of the proved undeveloped reserves added in 2006 will begin producing within the next three to five years. Generally, proved developed reserves are producing at the time they are added or will begin producing within one year.

Chesapeake attributes its strong drilling results and organic growth rates during the first nine months of 2006 (and in this decade) to management’s early recognition that oil and natural gas prices were undergoing

 

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structural change and its subsequent decision to invest aggressively in the building blocks of value creation in the E&P industry—people, land and seismic. During the past five years, Chesapeake has significantly strengthened its technical capabilities by increasing its land, geoscience and engineering staff to approximately 800 employees. Today, the company has more than 4,600 employees, of which approximately 65% work in the company’s E&P operations and 35% work in the company’s oilfield service operations.

Since 2000, Chesapeake has invested $5.7 billion in new leasehold and 3-D seismic acquisitions and now owns what it believes to be one of the largest inventories of onshore leasehold (10.5 million net acres) and 3-D seismic (14.7 million acres) in the U.S. On this leasehold, the company has an estimated 25,000 net drilling locations representing an approximate 10-year inventory of drilling projects.

To further hedge its exposure to oilfield service costs and achieve greater operational efficiency, Chesapeake has recently invested $254 million to acquire a 19.9% interest in a privately-held provider of well stimulation and high pressure pumping services with operations currently focused in Texas (principally in the Fort Worth Barnett Shale) and the Rocky Mountains. It also has expansion efforts underway in many other key regions in which Chesapeake operates.

This investment complements Chesapeake’s direct and indirect drilling rig investments that have served as an effective hedge to higher service costs and have also provided competitive advantages in making acquisitions and in developing the company’s own leasehold on a more timely and efficient basis. To date, Chesapeake has invested approximately $254 million to build or acquire 42 drilling rigs and is building 22 additional rigs. Additionally, the company entered into a sale/leaseback transaction to monetize its investment in 18 of its rigs in exchange for cash proceeds of $187.5 million. These rigs are under lease to Chesapeake through 2014 at which time the company has the option to reacquire them. In total, the company’s drilling rig fleet should reach 82 rigs by mid-year 2007, which would rank Chesapeake as the sixth largest drilling rig contractor in the U.S. Additionally, the company has a $69 million investment in two private drilling rig contractors, DHS Drilling Company and Mountain Drilling Company, in which Chesapeake’s equity ownership is approximately 45% and 49%, respectively. DHS owns 16 rigs and Mountain is operating two rigs and has another eight rigs under construction or on order for delivery in 2006 and 2007.

As of September 30, 2006, the company’s debt as a percentage of total capitalization (total capitalization is the sum of debt and stockholders’ equity) was 44% compared to 47% as of December 31, 2005. During the Current Period, we received net proceeds of $2.3 billion through issuances of $575 million of preferred equity, $835 million of common equity and $1.0 billion principal amount of senior notes. We used the net proceeds from these offerings primarily to fund the purchase price for acquisitions and to repay outstanding indebtedness under our revolving bank credit facility. As a result of our debt transactions in 2005 and the Current Period, we have extended the average maturity of our long-term debt to over nine years and have lowered our average interest rate to approximately 6.4%.

We intend to continue to focus on improving the strength of our balance sheet. We believe our business strategy and operational performance will lead to an investment grade credit rating for our unsecured debt at some point in the future.

Liquidity and Capital Resources

Sources and Uses of Funds

Our primary source of liquidity to meet operating expenses and fund capital expenditures (other than for certain acquisitions) is cash flow from operations. Based on our current production, price and expense assumptions, we expect cash flow from operations will exceed our drilling capital expenditures for the remainder of 2006 and 2007. Our budget for drilling, land and seismic activities for the remainder of 2006 is currently between $1.1 billion and $1.3 billion. We believe this level of exploration and development will be sufficient to increase our proved oil and natural gas reserves in 2006 and achieve our goal of an organic growth rate of more

 

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than 10% over 2005 production and at least a 23% increase in total production (inclusive of acquisitions completed or scheduled to close in 2006 through the filing date of this report but without regard to any additional acquisitions that may be completed in 2006). However, higher drilling and field operating costs, drilling results that alter planned development schedules, acquisitions, prolonged shut-ins or other factors could cause us to revise our drilling program, which is largely discretionary. Any cash flow from operations not needed to fund our drilling program will be available for acquisitions, debt repayment or other general corporate purposes.

Cash provided by operating activities was $2.982 billion in the Current Period compared to $1.577 billion in the Prior Period. The $1.405 billion increase was primarily due to higher realized prices and higher oil and natural gas production. While a further decline in natural gas prices for the remainder of 2006 and 2007 would affect the amount of cash flow that would be generated from operations, we have 88% and 73% of our expected oil production for the fourth quarter of 2006 and 2007, respectively, hedged at an average NYMEX price of $65.64 and $71.42 per barrel of oil, respectively, and 57% of our expected natural gas production for both the fourth quarter of 2006 and 2007, respectively, hedged at an average NYMEX price of $9.10 and $9.61 per mmbtu, respectively. These levels of hedging provide greater certainty of the cash flow we will receive for a substantial portion of our remaining 2006 and 2007 production. Depending on changes in oil and natural gas futures markets and management’s view of underlying oil and natural gas supply and demand trends, however, we may increase or decrease our current hedging positions.

Based on fluctuations in natural gas and oil prices, our hedging counterparties may require us to deliver cash collateral or other assurances of performance from time to time. All but two of our commodity price risk management counterparties require us to provide assurances of performance in the event that the counterparties’ mark-to-market exposure to us exceeds certain levels. Most of these arrangements allow us to minimize the potential liquidity impact of significant mark-to-market fluctuations by making collateral allocations from our bank credit facility or directly pledging oil and natural gas properties, rather than posting cash or letters of credit with the counterparties. As of September 30, 2006, we had outstanding collateral allocations and pledges of oil and gas properties, with respect to commodity price risk management transactions but were not required to post any collateral with our counterparties through letters of credit issued under our bank credit facility. As of November 3, 2006, we had outstanding transactions with thirteen counterparties, seven of which hold collateral allocations from our bank facility or liens against certain oil and natural gas properties under our secured hedging facilities, and two of which do not require us to provide security for our risk management transactions. As of November 3, 2006, we were not required to post cash or letters of credit with the remaining four counterparties. Future collateral requirements are uncertain and will depend on the arrangements with our counterparties and highly volatile natural gas and oil prices.

A significant source of liquidity is our $2.5 billion syndicated revolving bank credit facility which matures in February 2011. At November 3, 2006, there was $749.8 million of borrowing capacity available under the revolving bank credit facility. We use the facility to fund daily operating activities and acquisitions as needed. We borrowed $7.058 billion and repaid $5.666 billion in the Current Period, and we borrowed $3.561 billion and repaid $3.620 billion in the Prior Period under the credit facility. We incurred $5.1 million and $4.7 million of financing costs related to amendments to the credit facility agreement in the Current Period and the Prior Period, respectively.

We believe that our available cash, cash provided by operating activities and funds available under our revolving bank credit facility will be sufficient to fund our operating, debt service and general and administrative expenses, our capital expenditure budget, our short-term contractual obligations and dividend payments at current levels for the foreseeable future.

The public and institutional markets have been our principal source of long-term financing for acquisitions. We have sold debt and equity in both public and private offerings in the past, and we expect that these sources of capital will continue to be available to us in the future to finance acquisitions. Nevertheless, we caution that ready access to capital on reasonable terms and the availability of desirable acquisition targets at attractive prices are subject to many uncertainties, as explained under “Risk Factors” in Item 1A of our Form 10-K for the year ended December 31, 2005.

 

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The following table reflects the proceeds from sales of securities we issued in the Current Period and the Prior Period ($ in millions):

 

     For the Nine Months Ended September 30,
     2006    2005
     Total Proceeds    Net Proceeds    Total Proceeds    Net Proceeds

Convertible preferred stock

   $ 575.0    $ 557.6    $ 805.0    $ 782.4

Common stock

     835.2      803.7      301.0      289.4

Unsecured senior notes guaranteed by subsidiaries

     1,000.0      969.2      1,800.0      1,765.4
                           

Total

   $ 2,410.2    $ 2,330.5    $ 2,906.0    $ 2,837.2
                           

We qualify as a well-known seasoned issuer (WKSI), as defined in Rule 405 of the Securities Act of 1933, and therefore we may utilize automatic shelf registration to register future debt and equity issuances with the Securities and Exchange Commission. A prospectus supplement will be prepared at the time of an offering and will contain a description of the security issued, the plan of distribution and other information.

We paid dividends on our common stock of $61.8 million and $45.8 million in the Current Period and the Prior Period, respectively. The board of directors increased the quarterly dividend on common stock from $0.05 to $0.06 per share beginning with the dividend paid in July 2006. We paid dividends on our preferred stock of $62.5 million and $17.3 million in the Current Period and the Prior Period, respectively. We received $71.3 million and $19.9 million from the exercise of employee and director stock options and warrants in the Current Period and the Prior Period, respectively. The Current Period amount included $38.3 million paid by Tom L. Ward, our former President and Chief Operating Officer, to exercise all of his stock options following his resignation in February 2006.

In the Current Period, we paid $68.4 million to settle a portion of the derivative liabilities assumed in our November 2005 acquisition of Columbia Natural Resources, LLC.

On January 1, 2006, we adopted SFAS 123(R), which requires tax benefits resulting from stock-based compensation deductions in excess of amounts reported for financial reporting purposes to be reported as cash flows from financing activities. In the Current Period, we reported a tax benefit from stock-based compensation of $85.6 million.

Outstanding payments from certain disbursement accounts in excess of funded cash balances where no legal right of set-off exists increased by $43.3 million and $33.8 million in the Current Period and the Prior Period, respectively. All disbursements are funded on the day they are presented to our bank using available cash on hand or draws on our revolving bank credit facility.

Historically, we have used significant funds to redeem or purchase and retire outstanding senior notes issued by Chesapeake. The following table shows our purchases and exchanges of senior notes in the Prior Period ($ in millions):

 

     Senior Notes Activity

For the Nine Months Ended September 30, 2005:

   Retired    Premium    Other(a)    Cash Paid

8.375% Senior Notes due 2008

   $ 11.0    $ 0.8    $    $ 11.8

8.125% Senior Notes due 2011

     245.4      17.3      0.7      263.4

9.0% Senior Notes due 2012

     300.0      41.4      0.8      342.2
                           
   $ 556.4    $ 59.5    $ 1.5    $ 617.4
                           

(a) Includes adjustments to accrued interest and discount associated with notes retired and new notes issued, cash in lieu of fractional notes, transaction costs and fair value hedging adjustments.

 

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Cash used in investing activities increased to $6.668 billion during the Current Period, compared to $3.655 billion during the Prior Period. The following table shows our cash used in (provided by) investing activities during these periods ($ in millions):

 

     Nine Months Ended
September 30,
 
     2006     2005  

Oil and Natural Gas Investing Activities:

    

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

   $ 960.8     $ 1,175.3  

Acquisition of unproved properties

     2,128.9       757.6  

Exploration and development of oil and natural gas properties

     2,041.8       1,294.6  

Leasehold acquisitions

     456.2       164.6  

Geological and geophysical costs

     101.8       44.3  

Other oil and natural gas activities

     (16.0 )     (15.4 )
                

Total oil and natural gas investing activities

     5,673.5       3,421.0  
                

Other Investing Activities:

    

Additions to buildings and other fixed assets

     406.8       157.0  

Additions to drilling rig equipment (including Martex Drilling Company, L.L.P)

     340.8       42.1  

Additions to investments

     537.7       37.3  

Proceeds from sale of investment in Pioneer Drilling Company

     (158.9 )     —    

Proceeds from sale of drilling rigs and equipment

     (187.5 )     —    

Acquisition of trucking company, net of cash acquired

     45.2       —    

Deposits for acquisitions

     12.1       —    

Other

     (1.7 )     (2.4 )
                

Total other investing activities

     994.5       234.0  
                

Total cash used in (provided by) investing activities

   $ 6,668.0     $ 3,655.0  
                

Our accounts receivable are primarily from purchasers of oil and natural gas ($499.0 million at September 30, 2006) and exploration and production companies which own interests in properties we operate ($115.0 million at September 30, 2006). 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 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.

 

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Acquisitions and Financing Transactions

The following table describes investing transactions related to the acquisition of proved and unproved properties that we completed in the Current Period ($ in millions):

 

Quarter

  

Acquired From

  

Location of Properties

   Amount  
First    Midland-based oil and gas company    Ark-La-Tex and Barnett Shale    $ 272  
   Tulsa-based oil and gas company    Texas Gulf Coast and Mid-Continent      146  
   Houston-based oil and gas company    Texas Gulf Coast      125  
   Tulsa-based oil and gas company    Ark-La-Tex      70  
   Houston-based oil and gas company    Various      53  
   Dallas-based oil and gas company    Mid-Continent      30  
   Other    Various      297  
Second    Dallas-based oil and gas company    Permian      375  
   Oklahoma City-based oil and gas company    Permian      175  
   Other    Various      196  
Third    Four Sevens Oil Co., Ltd. and      
   Sinclair Oil Corporation    Barnett Shale      845 (a)
   Dallas-based oil and gas company    Ark-La-Tex and Texas Gulf Coast      200  
   Houston-based oil and gas company    Texas Gulf Coast      111  
   Other    Various      285  
              
  

Total oil and natural gas acquisitions

        3,180  
              
   Less cash deposits paid in 2005         (35 )
              
  

Total oil and natural gas acquisitions in the Current Period

      $ 3,145  
              

(a) Includes $55 million related to mid-stream natural gas systems which was allocated to other property and equipment.

We also recorded approximately $177.7 million of deferred income taxes to reflect the tax effect of the cost paid in excess of the tax basis acquired on certain corporate acquisitions.

In January 2006, we acquired a privately-owned Oklahoma-based oilfield trucking service company for $47.5 million. We recorded approximately $17.0 million of deferred income taxes to reflect the tax effect of the cost paid in excess of the tax basis acquired in connection with this acquisition. In February 2006, we acquired 13 drilling rigs and related assets through our wholly-owned subsidiary, Nomac Drilling Corporation, from Martex Drilling Company, L.L.P., a privately-owned drilling contractor with operations in East Texas and North Louisiana, for $150 million. In July 2006, we acquired a drilling contractor and an affiliated trucking company in the Appalachian Basin for approximately $70 million in cash.

In August 2006, we invested $254 million to acquire a 19.9% interest in a privately-held provider of well stimulation and high pressure pumping services, with operations currently focused in Texas (principally in the Fort Worth Barnett Shale) and the Rocky Mountains. In September 2006, we acquired 32% of the outstanding common stock of Chaparral Energy, Inc. for $240 million in cash and 1,375,989 newly issued shares of our common stock valued at $40 million. Chaparral is a privately-held independent oil and natural gas company headquartered in Oklahoma City, Oklahoma, with estimated proved reserves of approximately 618 bcfe and daily production of approximately 83 mmcfe.

During 2005 and continuing in 2006, we have taken several steps to improve our capital structure. These transactions enabled us to extend our average maturity of long-term debt to over nine years with an average interest rate of approximately 6.4%. Maintaining a debt-to-total-capitalization ratio of below 50% and reducing debt per mcfe of proved reserves remain key goals of our business strategy.

 

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We completed the following significant financing transactions in the Current Period:

First Quarter 2006

 

    Amended and restated our revolving bank credit facility, increasing the commitments to $2.0 billion and extending the maturity date to February 2011.

 

    Issued an additional $500 million of our 6.5% Senior Notes due 2017 in a private placement and used the proceeds of approximately $487 million to repay outstanding borrowings under our revolving bank credit facility incurred primarily to fund our recent acquisitions.

Second Quarter 2006

 

    Completed a public exchange of 83,245 shares of our 4.125% cumulative convertible preferred stock, representing 96.4% or $83.2 million of the aggregate liquidation value of the shares outstanding, for 5.2 million shares of our common stock pursuant to a tender offer. No cash was received or paid in connection with this transaction.

 

    Completed a public exchange of 804,048 shares of our 5.0% (Series 2003) cumulative convertible preferred stock, representing 95.4% or $80.4 million of the aggregate liquidation value of the shares outstanding, for 5.0 million shares of our common stock pursuant to a tender offer. No cash was received or paid in connection with this transaction.

 

    Completed public offerings of $500 million of 7.625% Senior Notes due 2013, 2.0 million shares of 6.25% mandatory convertible preferred stock having a liquidation preference of $250 per share, and 25 million shares of common stock at $29.05 per share. Net proceeds of approximately $1.666 billion were used to fund acquisitions, to repay borrowings under our revolving bank credit facility and for general corporate purposes.

Third Quarter 2006

 

    Increased the commitments under our revolving bank credit facility to $2.5 billion.

 

    Issued 3.75 million shares of common stock at $29.05 per share and 300,000 shares of our 6.25% mandatory convertible preferred stock having a liquidation preference of $250 per share upon the exercise of the underwriters’ options to purchase the additional shares pursuant to the June 2006 public offerings of our common stock and 6.25% preferred stock. Net proceeds of approximately $177.6 million were used to repay borrowings under our revolving bank credit facility.

Contractual Obligations

We currently have a $2.5 billion syndicated revolving bank credit facility which matures in February 2011. The credit facility was increased from $1.25 billion to $2.0 billion in February 2006 and to $2.5 billion in September 2006. As of September 30, 2006, we had $1.464 billion in outstanding borrowings under this facility and had utilized $6.2 million of the facility for various letters of credit. Borrowings under the facility are collateralized by certain producing oil and natural gas properties and bear interest at either (i) the greater of the reference rate of Union Bank of California, N.A., or the federal funds effective rate plus 0.50% or (ii) London Interbank Offered Rate (LIBOR), at our option, plus a margin that varies from 0.875% to 1.50% per annum according to our senior unsecured long-term debt ratings. The collateral value and borrowing base are redetermined periodically. The unused portion of the facility is subject to a commitment fee that also varies according to our senior unsecured long-term debt ratings, from 0.125% to 0.30% per annum. Currently the commitment fee is 0.25% per annum. Interest is payable quarterly or, if LIBOR applies, it may be payable at more frequent intervals.

The credit facility agreement contains various covenants and restrictive provisions which limit our ability to incur additional indebtedness, make investments or loans and create liens. The credit facility agreement requires

 

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us to maintain an indebtedness to total capitalization ratio (as defined) not to exceed 0.65 to 1 and an indebtedness to EBITDA ratio (as defined) not to exceed 3.5 to 1. As defined by the credit facility, our indebtedness to total capitalization ratio was 0.44 to 1 and our indebtedness to EBITDA ratio was 1.87 to 1 at September 30, 2006. If we should fail to perform our obligations under these and other covenants, the revolving credit commitment could be terminated and any outstanding borrowings under the facility could be declared immediately due and payable. Such acceleration, if involving a principal amount of $10 million ($50 million in the case of our senior notes issued after 2004), would constitute an event of default under our senior note indentures which could in turn result in the acceleration of a significant portion of our senior note indebtedness. The credit facility agreement also has cross default provisions that apply to other indebtedness we may have with an outstanding principal amount in excess of $75 million.

We also have two secured hedging facilities, each of which permits us to enter into cash-settled natural gas and oil commodity transactions, valued by the counterparty, for up to $500 million. The scheduled maturity date for these facilities is May 2010. Outstanding transactions under each facility are collateralized by certain of our oil and natural gas properties that do not secure any of our other obligations. The hedging facilities are subject to a 1.0% per annum exposure fee, which is assessed quarterly on the average of the daily negative fair market value amounts, if any, during the quarter. As of September 30, 2006, the fair market value of the natural gas and oil hedging transactions was an asset of $252.1 million under one of the facilities and an asset of $823.2 million under the other facility. As of November 3, 2006, the fair market value of the same transactions was an asset of approximately $152.2 million and $255.5 million, respectively. The hedging facilities contain the standard representations and default provisions that are typical of such agreements. The agreements also contain various restrictive provisions which govern the aggregate oil and natural gas production volumes that we are permitted to hedge under all of our agreements at any one time.

Two of our subsidiaries, Chesapeake Exploration Limited Partnership and Chesapeake Appalachia, L.L.C., are the borrowers under our revolving bank credit facility and Chesapeake Exploration Limited Partnership is the named party to our hedging facilities. The facilities are guaranteed by Chesapeake and all its other wholly-owned subsidiaries except minor subsidiaries. Our revolving bank credit facility and secured hedging facilities do not contain material adverse change or adequate assurance covenants. Although the applicable interest rates and commitment fees in our bank credit facility fluctuate slightly based on our long-term senior unsecured credit ratings, the bank facility and the secured hedging facilities do not contain provisions which would trigger an acceleration of amounts due under the facilities or a requirement to post additional collateral in the event of a downgrade of our credit ratings.

As of September 30, 2006, our senior notes consisted of the following ($ in thousands):

 

7.5% Senior Notes due 2013

   $ 363,823  

7.625% Senior Notes due 2013

     500,000  

7.0% Senior Notes due 2014

     300,000  

7.5% Senior Notes due 2014

     300,000  

7.75% Senior Notes due 2015

     300,408  

6.375% Senior Notes due 2015

     600,000  

6.625% Senior Notes due 2016

     600,000  

6.875% Senior Notes due 2016

     670,437  

6.5% Senior Notes due 2017

     1,100,000  

6.25% Senior Notes due 2018

     600,000  

6.875% Senior Notes due 2020

     500,000  

2.75% Contingent Convertible Senior Notes due 2035

     690,000  

Discount on senior notes

     (103,939 )

Discount for interest rate derivatives

     (23,621 )
        
   $ 6,397,108  
        

 

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No scheduled principal payments are required under our senior notes until 2013, when $863.8 million is due. The holders of the 2.75% Contingent Convertible Senior Notes due 2035 may require us to repurchase all or a portion of these notes on November 15, 2015, 2020, 2025 and 2030 at 100% of the principal amount of these notes.

As of September 30, 2006 and currently, debt ratings for the senior notes are Ba2 by Moody’s Investor Service (stable outlook), BB by Standard & Poor’s Ratings Services (stable outlook) and BB by Fitch Ratings.

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 with all of our future subordinated indebtedness. All of our wholly-owned subsidiaries, except minor subsidiaries, fully and unconditionally guarantee the notes jointly and severally on an unsecured basis. Senior notes issued before July 2005 are governed by indentures containing covenants that limit our ability and our restricted subsidiaries’ ability to incur additional indebtedness; pay dividends on our capital stock or redeem, repurchase or retire our capital stock or subordinated indebtedness; make investments and other restricted payments; incur liens; enter into sale-leaseback transactions; create restrictions on the payment of dividends or other amounts to us from our restricted subsidiaries; engage in transactions with affiliates; sell assets; and consolidate, merge or transfer assets. Senior notes issued after June 2005 are governed by indentures containing covenants that limit our ability and our restricted subsidiaries’ ability to incur certain secured indebtedness; enter into sale-leaseback transactions; and consolidate, merge or transfer assets. The debt incurrence covenants do not presently restrict our ability to borrow under or expand our secured credit facility. As of September 30, 2006, we estimate that secured commercial bank indebtedness of approximately $5.4 billion could have been incurred under the most restrictive indenture covenant.

In September 2006, our wholly owned subsidiary, Nomac Drilling Corporation, sold 18 of its drilling rigs and related equipment for $187.5 million and entered into a master lease agreement under which it agreed to lease the rigs from the buyer for an initial term of eight years from October 1, 2006 at rental payments of $26.0 million annually. Nomac’s lease obligations are guaranteed by Chesapeake and its other material domestic subsidiaries. This transaction was recorded as a sale and operating leaseback, with an aggregate deferred gain of $14.8 million on the sale which will be amortized to service operations expense over the lease term. Under the rig lease, we have the option to purchase the rigs on September 30, 2013 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 rental equal to the fair market rental value of the rigs as determined at the time of renewal.

Commitments related to these lease payments are not recorded in the accompanying condensed consolidated balance sheets. As of September 30, 2006, minimum future rig lease payments were as follows (in thousands):

 

2006

   $ 6,130

2007

     25,993

2008

     25,993

2009

     25,993

2010

     25,993

Thereafter

     97,478
      

Total

   $ 207,580
      

Results of Operations—Three Months Ended September 30, 2006 vs. September 30, 2005

General.    For the Current Quarter, Chesapeake had net income of $548.3 million, or $1.13 per diluted common share, on total revenues of $1.929 billion. This compares to net income of $177.0 million, or $0.43 per diluted common share, on total revenues of $1.083 billion during the Prior Quarter.

 

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Oil and Natural Gas Sales.    During the Current Quarter, oil and natural gas sales were $1.493 billion compared to $720.9 million in the Prior Quarter. In the Current Quarter, Chesapeake produced 146.9 bcfe at a weighted average price of $8.54 per mcfe, compared to 120.4 bcfe produced in the Prior Quarter at a weighted average price of $6.85 per mcfe (weighted average prices exclude the effect of unrealized gains or (losses) on oil and natural gas derivatives of $238.5 million and ($104.0) million in the Current Quarter and Prior Quarter, respectively). In the Current Quarter, the increase in prices resulted in an increase in revenue of $247.9 million and increased production resulted in a $181.8 million increase, for a total increase in revenues of $429.7 million (excluding unrealized gains or losses on oil and natural gas derivatives). The increase in production from the Prior Quarter to the Current Quarter is due to the combination of drilling and acquisitions completed in 2005 and 2006.

For the Current Quarter, we realized an average price per barrel of oil of $60.62, compared to $53.30 in the Prior Quarter (weighted average prices for both quarters discussed exclude the effect of unrealized gains or losses on derivatives). Natural gas prices realized per mcf (excluding unrealized gains or losses on derivatives) were $8.39 and $6.64 in the Current Quarter and Prior Quarter, respectively. Realized gains or losses from our oil and natural gas derivatives resulted in a net increase in oil and natural gas revenues of $301.4 million, or $2.05 per mcfe, in the Current Quarter and a net decrease of $122.6 million, or $1.02 per mcfe, in the Prior Quarter.

The change in oil and natural gas prices has a significant impact on our oil and natural gas 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 $13.4 million and $12.8 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 $2.2 million and $2.1 million, respectively, without considering the effect of derivative activities.

The following table shows our production by region for the Current Quarter and the Prior Quarter:

 

     For the Three Months Ended September 30,  
     2006     2005  
     Mmcfe    Percent     Mmcfe    Percent  

Mid-Continent

   80,946    55 %   74,910    62 %

South Texas and Texas Gulf Coast

   19,421    13     17,018    14  

Appalachian Basin

   11,750    8         

Barnett Shale

   11,557    8     4,898    4  

Ark-La-Tex

   11,529    8     10,945    9  

Permian Basin

   11,072    8     11,843    10  

Other

   615        743    1  
                      

Total Production

   146,890    100 %   120,357    100 %
                      

Natural gas production represented approximately 91% of our total production volume on a natural gas equivalent basis in the Current Quarter, compared to 90% in the Prior Quarter.

Oil and Natural Gas Marketing Sales and Operating Expenses.    Oil and natural gas marketing activities are substantially for third parties that are owners in Chesapeake-operated wells. Chesapeake recognized $398.1 million in oil and natural gas marketing sales to third parties in the Current Quarter, with corresponding oil and natural gas marketing expenses of $384.5 million, for a net margin of $13.6 million. This compares to sales of $361.9 million, expenses of $353.5 million and a net margin of $8.4 million in the Prior Quarter. In the Current Quarter, Chesapeake realized an increase in oil and natural gas marketing sales volumes.

Service Operations Revenue and Operating Expenses.    Service operations consist of third-party revenue and operating expenses related to our drilling and oilfield trucking operations. These operations have grown as a result of businesses we acquired in the Current Period. Chesapeake recognized $38.1 million in service operations revenue in the Current Quarter with corresponding service operations expense of $18.8 million, for a net margin of $19.3 million. During the Prior Quarter, service operations for third parties were insignificant.

 

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Production Expenses.    Production expenses, which include lifting costs and ad valorem taxes, were $124.0 million in the Current Quarter compared to $80.8 million in the Prior Quarter. On a unit-of-production basis, production expenses were $0.84 per mcfe in the Current Quarter compared to $0.67 per mcfe in the Prior Quarter. The increase in the Current Quarter was primarily due to higher third-party field service costs, energy costs, ad valorem tax increases and personnel costs. We expect that production expenses for the remainder of 2006 will range from $0.85 to $0.95 per mcfe produced.

Production Taxes.    Production taxes were $40.6 million and $53.1 million in the Current Quarter and the Prior Quarter, respectively. On a unit-of-production basis, production taxes were $0.28 per mcfe in the Current Quarter compared to $0.44 per mcfe in the Prior Quarter. This decrease is the result of an increase in production tax exemptions realized in addition to a decrease in natural gas prices. In general, production taxes are calculated using value-based formulas that produce higher per unit costs when oil and natural gas prices are higher. We expect production taxes for the remainder of 2006 to range from $0.36 to $0.40 per mcfe produced based on NYMEX prices of $56.25 per barrel of oil and natural gas prices ranging from $6.40 to $7.20 per mcf.

General and Administrative Expenses.    General and administrative expenses, which are net of internal payroll and non-payroll costs capitalized in our oil and natural gas properties, were $37.4 million in the Current Quarter and $15.8 million in the Prior Quarter. General and administrative expenses were $0.25 and $0.13 per mcfe for the Current Quarter and Prior Quarter, respectively. The increase in the Current Quarter was the result of the company’s overall growth as well as cost and wage inflation. Included in general and administrative expenses is stock-based compensation of $8.5 million and $5.2 million for the Current Quarter and Prior Quarter, respectively. We anticipate that general and administrative expenses for the remainder of 2006 will be between $0.27 and $0.33 per mcfe produced (including stock-based compensation ranging from $0.10 to $0.11 per mcfe).

Our stock-based compensation for employees and non-employee directors is principally in the form of restricted stock. We have awarded shares of restricted stock to employees since January 2004 and to non-employee directors since July 2005. Stock-based compensation awards before 2004 (and before 2005 for non-employee directors) were in the form of stock options. Employee stock-based compensation awards vest over a period of four or five years. Our non-employee director awards vest over a period of three years.

Until December 31, 2005, as permitted under Statement of Financial Accounting Standards (“SFAS”) No. 123, Accounting for Stock-Based Compensation, as amended, we accounted for our stock options under the recognition and measurement provisions of APB Opinion No. 25, Accounting for Stock Issued to Employees, and related interpretations. Generally, we recognized no compensation cost on grants of employee and non-employee director stock options because the exercise price was equal to the market price of our common stock on the date of grant. Effective January 1, 2006, we implemented the fair value recognition provisions of SFAS 123(R), Share-Based Payment, using the modified-prospective transition method. Under this transition method, compensation cost in 2006 includes the portion vesting in the period for (1) all share-based payments granted prior to, but not vested as of January 1, 2006, based on the grant-date fair value estimated in accordance with the original provisions of SFAS 123 and (2) all share-based payments granted subsequent to January 1, 2006, based on the grant-date fair value estimated in accordance with the provisions of SFAS 123(R). Results for prior periods have not been restated.

Stock-based compensation expense increased from $5.2 million in the Prior Quarter to $8.5 million in the Current Quarter. This increase is primarily due to additional restricted stock grants to employees during the past year.

The discussion of stock-based compensation in note 1 to the financial statements included in Part I of this report provides additional detail on the accounting for and reporting of our stock options and restricted stock, as well as the effects of our adoption of SFAS 123(R).

Chesapeake follows the full-cost method of accounting under which all costs associated with property acquisition, exploration and development activities are capitalized. We capitalize internal costs that can be

 

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directly identified with our exploration and development activities and do not include any costs related to production, general corporate overhead or similar activities. We capitalized $49.0 million and $29.5 million of internal costs in the Current Quarter and the Prior Quarter, respectively, directly related to our oil and natural gas property acquisition, exploration and development efforts.

Oil and Natural Gas Depreciation, Depletion and Amortization.    Depreciation, depletion and amortization of oil and natural gas properties was $343.7 million and $231.1 million during the Current Quarter and the Prior Quarter, respectively. The average DD&A rate per mcfe, which is a function of capitalized costs, future development costs and the related underlying reserves in the periods presented, was $2.34 and $1.92 in the Current Quarter and in the Prior Quarter, respectively. The $0.42 increase in the average DD&A rate is primarily the result of higher drilling costs and higher costs associated with acquisitions, including the recognition of the tax effect of acquisition costs in excess of the tax basis acquired in certain corporate acquisitions. We expect the DD&A rate for the remainder of 2006 to be between $2.35 and $2.40 per mcfe produced.

Depreciation and Amortization of Other Assets.    Depreciation and amortization of other assets was $27.0 million in the Current Quarter, compared to $12.9 million in the Prior Quarter. The increase in the Current Quarter was primarily the result of depreciation of assets acquired in 2005 and 2006. These assets include various gathering facilities and compression equipment, new buildings constructed at our corporate headquarters complex and at various field office locations, additional drilling rigs and oilfield trucks and new information technology equipment and software. Property and equipment costs are depreciated on a straight-line basis. Buildings are depreciated over 15 to 39 years, gathering facilities are depreciated over seven to 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 seven years. To the extent drilling rigs are used to drill Chesapeake wells, a substantial portion of the depreciation is capitalized in oil and natural gas properties as exploration or development costs. We expect depreciation and amortization of other assets for the remainder of 2006 to be between $0.19 and $0.23 per mcfe produced.

Interest and Other Income.    Interest and other income was $5.1 million in the Current Quarter compared to $2.4 million in the Prior Quarter. The Current Quarter income consisted of $1.8 million of interest income, $2.3 million related to earnings of equity investees, a $0.1 million gain on sale of assets and $0.9 million of miscellaneous income. The Prior Quarter income consisted of $0.4 million of interest income, ($0.1) million related to earnings of equity investees and $2.1 million of miscellaneous income.

Interest Expense.    Interest expense increased to $74.1 million in the Current Quarter compared to $58.6 million in the Prior Quarter as follows:

 

     Three Months Ended
September 30,
 
     2006     2005  
     ($ in millions)  

Interest expense on senior notes and revolving bank credit facility

   $ 122.3     $ 77.6  

Capitalized interest

     (49.3 )     (20.8 )

Amortization of loan discount

     2.0       1.4  

Unrealized (gain) loss on interest rate derivatives

     (2.5 )     1.2  

Realized (gain) loss on interest rate derivatives

     1.6       (0.8 )
                

Total interest expense

   $ 74.1     $ 58.6  
                

Average long-term borrowings

   $ 6,525     $ 4,047  
                

We use interest rate derivatives to mitigate our exposure to the volatility in interest rates. For interest rate derivative instruments designated as fair value hedges (in accordance with SFAS 133), changes in fair value are recorded on the consolidated balance sheets as assets (liabilities) and the debt’s carrying value amount is adjusted

 

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by the change in the fair value of the debt subsequent to the initiation of the derivative. Any resulting differences are recorded currently as ineffectiveness in the consolidated statements of operations as an adjustment to interest expense. Changes in the fair value of derivative instruments not qualifying as fair value hedges are recorded currently as adjustments to interest expense. A detailed explanation of our interest rate derivative activity appears later in Item 3—Quantitative and Qualitative Disclosures About Market Risk.

Interest expense, excluding unrealized gains or losses on derivatives and net of amounts capitalized, was $0.52 per mcfe in the Current Quarter compared to $0.48 per mcfe in the Prior Quarter. We expect interest expense for the remainder of 2006 to be between $0.58 and $0.62 per mcfe produced (before considering the effect of interest rate derivatives).

Loss on Repurchases or Exchanges of Chesapeake Debt.    We repurchased or exchanged Chesapeake debt in the Prior Quarter and incurred losses in connection with the transactions. The following table shows the losses related to these transactions ($ in millions):

 

For the Three Months Ended September 30, 2005:

  

Notes

Retired

   Loss on Repurchases/Exchanges
      Premium    Other(a)    Total

8.125% Senior Notes due 2011

   $ 7.6    $ 0.5    $ 0.1    $ 0.6

9.0% Senior Notes due 2012

     1.1      0.1      0.0      0.1
                           
   $ 8.7    $ 0.6    $ 0.1    $ 0.7
                           

(a) Includes write-offs of discounts, deferred charges and interest rate derivatives associated with retired notes and transaction costs.

There were no repurchases or exchanges of Chesapeake debt in the Current Quarter.

Income Tax Expense.    Chesapeake recorded income tax expense of $336.1 million in the Current Quarter, compared to income tax expense of $101.7 million in the Prior Quarter. Our effective income tax rate increased to 38% in the Current Quarter compared to 36.5% in the Prior Quarter. This increase included the impact that both state income taxes and permanent differences had on our overall effective rate along with the effect of a Texas tax law change. In May 2006, Texas House Bill 3 was signed into law which eliminated the existing franchise tax and replaced it with a new income-based margin tax. The new tax is effective for tax returns due on or after January 1, 2008 for our 2007 business activity. Although the new margin tax is not effective until 2007, the provisions of SFAS 109, Accounting for Income Taxes, require us to record the impact that this change has on our liability for additional deferred income taxes in the period of enactment. All 2005 income tax expense was deferred, and we expect most, if not all, of our 2006 income tax expense to be deferred.

Results of Operations—Nine Months Ended September 30, 2006 vs. September 30, 2005

General.    For the Current Period, Chesapeake had net income of $1.532 billion, or $3.40 per diluted common share, on total revenues of $5.458 billion. This compares to net income of $495.8 million, or $1.32 per diluted common share, on total revenues of $2.914 billion during the Prior Period.

Oil and Natural Gas Sales.    During the Current Period, oil and natural gas sales were $4.190 billion compared to $2.032 billion in the Prior Period. In the Current Period, Chesapeake produced 426.3 bcfe at a weighted average price of $8.77 per mcfe, compared to 338.2 bcfe produced in the Prior Period at a weighted average price of $6.42 per mcfe (weighted average prices exclude the effect of unrealized gains or (losses) on oil and natural gas derivatives of $452.6 million and ($137.1) million in the Current Period and Prior Period, respectively). In the Current Period, the increase in prices resulted in an increase in revenue of $1.003 billion and increased production resulted in a $565.5 million increase, for a total increase in revenues of $1.568 billion (excluding unrealized gains or losses on oil and natural gas derivatives). The increase in production from the Prior Period to the Current Period is due to the combination of drilling as well as acquisitions completed in 2005 and the Current Period.

 

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For the Current Period, we realized an average price per barrel of oil of $58.86 compared to $46.04 in the Prior Period (weighted average prices for both periods discussed exclude the effect of unrealized gains or losses on derivatives). Natural gas prices realized per mcf (excluding unrealized gains or losses on derivatives) were $8.66 and $6.27 in the Current Period and Prior Period, respectively. Realized gains or losses from our oil and natural gas derivatives resulted in a net increase in oil and natural gas revenues of $807.1 million, or $1.89 per mcfe, in the Current Period and a net decrease of $126.6 million, or $0.37 per mcfe, in the Prior Period.

The change in oil and natural gas prices has a significant impact on our oil and natural gas 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 $38.8 million and $36.9 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 $6.4 million and $6.1 million, respectively, without considering the effect of derivative activities.

The following table shows our production by region for the Current Period and the Prior Period:

 

     For the Nine Months Ended September 30,  
     2006     2005  
     Mmcfe    Percent     Mmcfe    Percent  

Mid-Continent

   233,078    55 %   222,290    65 %

South Texas and Texas Gulf Coast

   59,040    14     45,082    13  

Permian Basin

   34,582    8     28,955    9  

Ark-La-Tex

   34,410    8     28,845    9  

Appalachian Basin

   33,268    8         

Barnett Shale

   30,035    7     10,927    3  

Other

   1,905        2,065    1  
                      

Total Production

   426,318    100 %   338,164    100 %
                      

Natural gas production represented approximately 91% of our total production volume on a natural gas equivalent basis in the Current Period, compared to 90% in the Prior Period.

Oil and Natural Gas Marketing Sales and Operating Expenses.    Oil and natural gas marketing activities are substantially for third parties that are owners in Chesapeake-operated wells. Chesapeake recognized $1.170 billion in oil and natural gas marketing sales to third parties in the Current Period, with corresponding oil and natural gas marketing expenses of $1.132 billion, for a net margin of $38.6 million. This compares to sales of $882.0 million, expenses of $860.8 million and a net margin of $21.2 million in the Prior Period. In the Current Period, Chesapeake realized an increase in oil and natural gas marketing sales volumes and an increase in oil and natural gas prices.

Service Operations Revenue and Operating Expenses.    Service operations consist of third-party revenue and operating expenses related to our drilling and oilfield trucking operations. These operations have grown as a result of businesses we acquired in the Current Period. Chesapeake recognized $97.5 million in service operations revenue in the Current Period with corresponding service operations expenses of $48.9 million, for a net margin of $48.6 million principally associated with businesses acquired in the Current Period. During the Prior Period, service operations for third parties were insignificant.

Production Expenses.    Production expenses, which include lifting costs and ad valorem taxes, were $364.1 million in the Current Period compared to $222.7 million in the Prior Period. On a unit-of-production basis, production expenses were $0.85 per mcfe in the Current Period compared to $0.66 per mcfe in the Prior Period. The increase in the Current Period was primarily due to higher third-party field service costs, energy costs, ad valorem tax increases and personnel costs. We expect that production expenses for the remainder of 2006 will range from $0.85 to $0.95 per mcfe produced.

 

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Production Taxes.    Production taxes were $129.9 million and $136.3 million in the Current Period and the Prior Period, respectively. On a unit-of-production basis, production taxes were $0.30 per mcfe in the Current

Period compared to $0.40 per mcfe in the Prior Period. The Current Period included a $2.1 million accrual for certain severance tax claims and then a subsequent reversal of the cumulative $11.6 million accrual for such severance tax claims as a result of their dismissal. The Prior Period included an accrual of $5.0 million associated with such severance tax claims. Excluding these items, production taxes were $0.33 per mcfe in the Current Period and $0.39 per mcfe in the Prior Period. This decrease is the result of an increase in production tax exemptions realized. In general, production taxes are calculated using value-based formulas that produce higher per unit costs when oil and natural gas prices are higher. We expect production taxes for the remainder of 2006 to range from $0.36 to $0.40 per mcfe produced based on NYMEX prices of $56.25 per barrel of oil and natural gas prices ranging from $6.40 to $7.20 per mcf.

General and Administrative Expenses.    General and administrative expenses, which are net of internal payroll and non-payroll costs capitalized in our oil and natural gas properties, were $99.7 million in the Current Period and $39.6 million in the Prior Period. General and administrative expenses were $0.23 and $0.12 per mcfe for the Current Period and Prior Period, respectively. The increase in the Current Period was the result of the company’s overall growth as well as cost and wage inflation. Included in general and administrative expenses is stock-based compensation of $21.3 million and $10.2 million for the Current Period and Prior Period, respectively. We anticipate that general and administrative expenses for the remainder of 2006 will be between $0.27 and $0.33 per mcfe produced (including stock-based compensation ranging from $0.10 to $0.11 per mcfe).

Our stock-based compensation for employees and non-employee directors is principally in the form of restricted stock. We have awarded shares of restricted stock to employees since January 2004 and to non-employee directors annually since July 2005. Employee compensation awards before 2004 (and before 2005 for non-employee directors) were in the form of stock options. These stock-based compensation awards vest over a period of four or five years. Our non-employee director awards vest over a period of three years.

Until December 31, 2005, as permitted under Statement of Financial Accounting Standards (“SFAS”) No. 123, Accounting for Stock-Based Compensation, as amended, we accounted for our stock options under the recognition and measurement provisions of APB Opinion No. 25, Accounting for Stock Issued to Employees, and related interpretations. Generally, we recognized no compensation cost on grants of employee and non-employee director stock options because the exercise price was equal to the market price of our common stock on the date of grant. Effective January 1, 2006, we implemented the fair value recognition provisions of SFAS 123(R), Share-Based Payment, using the modified-prospective transition method. Under this transition method, compensation cost in 2006 includes the portion vesting in the period for (1) all share-based payments granted prior to, but not vested as of January 1, 2006, based on the grant-date fair value estimated in accordance with the original provisions of SFAS 123 and (2) all share-based payments granted subsequent to January 1, 2006, based on the grant-date fair value estimated in accordance with the provisions of SFAS 123(R). Results for prior periods have not been restated.

Stock-based compensation expense increased from $10.2 million in the Prior Period to $21.3 million in the Current Period. Of this increase, $1.9 million was due to stock option expense, $9.1 million was due to a higher number of unvested restricted shares outstanding during the Current Period compared to the Prior Period and $0.1 million was due to stock granted to a new director.

The discussion of stock-based compensation in note 1 to the financial statements included in Part I of this report provides additional detail on the accounting for and reporting of our stock options and restricted stock, as well as the effects of our adoption of SFAS 123(R).

Chesapeake follows the full-cost method of accounting under which all costs associated with 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

 

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production, general corporate overhead or similar activities. We capitalized $119.3 million and $75.3 million of internal costs in the Current Period and the Prior Period, respectively, directly related to our oil and natural gas property acquisition, exploration and development efforts.

Oil and Natural Gas Depreciation, Depletion and Amortization.    Depreciation, depletion and amortization of oil and natural gas properties was $976.8 million and $621.5 million 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 $2.29 and $1.84 in the Current Period and in the Prior Period, respectively. The $0.45 increase in the average DD&A rate is primarily the result of higher drilling costs and higher costs associated with acquisitions, including the recognition of the tax effect of acquisition costs in excess of tax basis acquired in certain corporate acquisitions. We expect the DD&A rate for the remainder of 2006 to be between $2.35 and $2.40 per mcfe produced.

Depreciation and Amortization of Other Assets.    Depreciation and amortization of other assets was $74.1 million in the Current Period, compared to $34.8 million in the Prior Period. The increase in the Current Period was primarily the result of the depreciation of recently acquired assets resulting from our acquisition of various gathering facilities and compression equipment, the construction of new buildings at our corporate headquarters complex and at various field office locations, the purchase of additional drilling rigs and oilfield trucks and the purchase of additional information technology equipment and software. Property and equipment costs are depreciated on a straight-line basis. Buildings are depreciated over 15 to 39 years, gathering facilities are depreciated over seven to 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 seven years. To the extent drilling rigs are used to drill our wells, a substantial portion of the depreciation is capitalized in oil and natural gas properties as exploration or development costs. We expect depreciation and amortization of other assets for the remainder of 2006 to be between $0.19 and $0.23 per mcfe produced.

Employee Retirement Expense.    Our President and Chief Operating Officer, Tom L. Ward, resigned as a director, officer and employee of the company effective February 10, 2006. Mr. Ward’s Resignation Agreement provided for the immediate vesting of all of his unvested stock options and restricted stock on February 10, 2006. As a result of such vesting, options to purchase 724,615 shares of Chesapeake’s common stock at an average exercise price of $8.01 per share and 1,291,875 shares of restricted common stock became immediately vested. As a result, we incurred an expense of $54.8 million in the Current Period.

Interest and Other Income.    Interest and other income was $19.7 million in the Current Period compared to $7.8 million in the Prior Period. The Current Period income consisted of $3.1 million of interest income, $9.5 million related to earnings of equity investees, a $3.5 million gain on sale of assets and $3.6 million of miscellaneous income. The Prior Period income consisted of $3.5 million of interest income, $1.1 million related to earnings of equity investees and $3.2 million of miscellaneous income.

Interest Expense.    Interest expense increased to $220.2 million in the Current Period compared to $155.6 million in the Prior Period as follows:

 

     Nine Months Ended
September 30,
 
         2006             2005      
     ($ in millions)  

Interest expense on senior notes and revolving bank credit facility

   $ 335.8     $ 210.7  

Capitalized interest

     (119.2 )     (54.8 )

Amortization of loan discount

     5.3       4.2  

Unrealized (gain) loss on interest rate derivatives

     (0.8 )     (1.9 )

Realized (gain) loss on interest rate derivatives

     (0.9 )     (2.6 )
                

Total interest expense

   $ 220.2     $ 155.6  
                

Average long-term borrowings

   $ 6,125     $ 3,593  
                

 

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We use interest rate derivatives to mitigate our exposure to the volatility in interest rates. For interest rate derivative instruments designated as fair value hedges (in accordance with SFAS 133), changes in fair value are recorded on the consolidated balance sheets as assets (liabilities), and the debt’s carrying value amount is adjusted by the change in the fair value of the debt subsequent to the initiation of the derivative. Any resulting differences are recorded currently as ineffectiveness in the consolidated statements of operations as an adjustment to interest expense. Changes in the fair value of derivative instruments not qualifying as fair value hedges are recorded currently as adjustments to interest expense. A detailed explanation of our interest rate derivative activity appears later in Item 3—Quantitative and Qualitative Disclosures About Market Risk.

Interest expense, excluding unrealized gains or losses on derivatives and net of amounts capitalized, was $0.52 per mcfe in the Current Period compared to $0.47 per mcfe in the Prior Period. We expect interest expense for the remainder of 2006 to be between $0.58 and $0.62 per mcfe produced (before considering the effect of interest rate derivatives).

Gain on Sale of Investment.    In the Current Period, Chesapeake sold its investment in publicly-traded Pioneer Drilling Company (“Pioneer”) common stock, realizing proceeds of $158.9 million and a gain of $117.4 million. We owned 17% of the common stock of Pioneer, which we began acquiring in 2003.

Loss on Repurchases or Exchanges of Chesapeake Senior Notes.    We repurchased or exchanged Chesapeake debt in the Prior Period and incurred losses in connection with the transactions. The following table shows the losses related to these transactions ($ in millions):

 

For the Nine Months Ended September 30, 2005:

  

Notes

Retired

   Loss on Repurchases/Exchanges
      Premium    Other(a)    Total

8.375% Senior Notes due 2008

   $ 11.0    $ 0.8    $ 0.1    $ 0.9

8.125% Senior Notes due 2011

     245.4      17.3      4.4      21.7

9.0% Senior Notes due 2012

     300.0      41.4      6.0      47.4
                           
   $ 556.4    $ 59.5    $ 10.5    $ 70.0
                           

(a) Includes write-offs of discounts, deferred charges and interest rate derivatives associated with retired notes and transaction costs.

There were no repurchases or exchanges of Chesapeake debt in the Current Period.

Income Tax Expense.    Chesapeake recorded income tax expense of $963.1 million in the Current Period, compared to income tax expense of $285.0 million in the Prior Period. Our effective income tax rate increased to 38.6% in the Current Period compared to 36.5% in the Prior Period. This increase included the impact that both state income taxes and permanent differences had on our overall effective rate along with the effect of a Texas tax law change. In May 2006, Texas House Bill 3 was signed into law which eliminated the existing franchise tax and replaced it with a new income-based margin tax. The new tax is effective for tax returns due on or after January 1, 2008 for our 2007 business activity. Although the new margin tax is not effective until 2007, the provisions of SFAS 109, Accounting for Income Taxes, require us to record the impact that this change has on our liability for deferred income taxes in the period of enactment. As a result, we recorded $15 million in additional deferred state income tax expense, net of the federal income tax benefit, in the Current Period. Excluding the effect of this adjustment, our effective income tax rate was 38% for the Current Period. All 2005 income tax expense was deferred, and we expect most, if not all, of our 2006 income tax expense to be deferred.

Critical Accounting Policies

We consider accounting policies related to hedging, oil and natural gas properties, income taxes and business combinations 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, 2005.

 

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Recently Issued 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 December 2004, the FASB issued SFAS 123(R), Share-Based Payment, a revision of SFAS 123, accounting for stock-based compensation. This statement establishes standards for the accounting for transactions in which an entity exchanges its equity instruments for goods or services by requiring a public entity to measure the cost of employee services received in exchange for an award of equity instruments based on the grant-date fair value of the award. We adopted this statement effective January 1, 2006. The effect of SFAS 123(R) is more fully described in Note 1.

In September 2005, the Emerging Issues Task Force (EITF) reached a consensus on Issue No. 04-13, Accounting for Purchases and Sales of Inventory with the Same Counterparty. EITF Issue No. 04-13 requires that purchases and sales of inventory with the same counterparty in the same line of business should be accounted for as a single non-monetary exchange, if entered into in contemplation of one another. The consensus is effective for inventory arrangements entered into, modified or renewed in interim or annual reporting periods beginning after March 15, 2006. We adopted this issue effective April 1, 2006. The adoption of EITF Issue No. 04-13 did not have a material impact on our financial statements.

In June 2006, the FASB issued FASB Interpretation (FIN) No. 48, Accounting for Uncertainty in Income Taxes—an interpretation of FASB Statement No. 109. FIN 48 provides guidance for recognizing and measuring uncertain tax positions, as defined in SFAS 109, Accounting for Income Taxes. FIN 48 prescribes a threshold condition that a tax position must meet for any of the benefit of the uncertain tax position to be recognized in the financial statements. Guidance is also provided regarding de-recognition, classification and disclosure of these uncertain tax positions. FIN 48 is effective for fiscal years beginning after December 15, 2006. We do not expect that FIN 48 will have a material impact on our financial position, results of operations or cash flows.

In February 2006, the FASB issued SFAS No. 155, Accounting for Certain Hybrid Financial Instruments—an amendment of FASB Statements No. 133 and 140. SFAS 155 permits an entity to measure at fair value any financial instrument that contains an embedded derivative that otherwise would require bifurcation. This statement is effective for all financial instruments acquired or issued after the beginning of an entity’s first fiscal year that begins after September 15, 2006. We are currently evaluating the provisions of SFAS 155 and believe that adoption will not have a material effect on our financial position, results of operations or cash flows.

In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements. This statement defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles (GAAP), and expands disclosures about fair value measurements. This statement is effective for financial statements issued for fiscal years beginning after November 15, 2007. We are currently assessing the impact SFAS 157 will have on our financial position, results of operations or cash flows.

In September 2006, the FASB issued SFAS No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans. This statement requires an employer to recognize the overfunded or underfunded status of a defined benefit postretirement plan (other than a multiemployer plan) as an asset or liability in its statement of financial position and to recognize changes in that funded status in the year in which the changes occur through comprehensive income. This statement is effective as of the end of the fiscal year ending after December 15, 2006. We do not expect that SFAS 158 will have a material impact on our financial position, results of operations or cash flows.

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 statements regarding oil and natural gas reserve

 

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estimates, planned capital expenditures, the drilling of oil and natural gas wells and future acquisitions, expected oil and natural gas production, cash flow and anticipated liquidity, business strategy and other plans and objectives for future operations and expected future expenses. Statements 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 annual report on Form 10-K for the year ended December 31, 2005 and include:

 

    the volatility of oil and natural gas prices,

 

    our level of indebtedness,

 

    the strength and financial resources of our competitors,

 

    the availability of capital on an economic basis to fund reserve replacement costs,

 

    our ability to replace reserves and sustain production,

 

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

 

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

 

    inability to effectively integrate and operate acquired companies and properties,

 

    unsuccessful exploration and development drilling,

 

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

 

    lower prices realized on oil and natural gas sales and collateral required to secure hedging liabilities resulting from our commodity price risk management activities,

 

    lower oil and natural gas prices negatively affecting our ability to borrow, and

 

    drilling and operating risks.

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

Oil and Natural Gas Hedging Activities

Our results of operations and operating cash flows are impacted by changes in market prices for oil and natural gas. To mitigate a portion of the exposure to adverse market changes, we have entered into various derivative instruments. As of September 30, 2006, our oil and natural gas derivative instruments were comprised of swaps, cap-swaps, basis protection swaps, call options and collars. These instruments allow us to predict with greater certainty the effective oil and natural gas prices to be received for our hedged production. Although derivatives often fail to achieve 100% effectiveness for accounting purposes, we believe our derivative instruments continue to be highly effective in achieving the risk management objectives for which they were intended.

 

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

 

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

 

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

 

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

 

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

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

With respect to counter-swaps that are designed to lock-in the value of cap-swaps, the counter-swap is effective in locking-in the value of the cap-swap until the floating price reaches the cap (or floor) stipulated in the cap-swap agreement. The value of the counter-swap will increase (or decrease), but in the opposite direction, as the value of the cap-swap decreases (or increases) until the floating price reaches the pre-determined cap (or floor) stipulated in the cap-swap agreement. However, because of the written put option embedded in the cap-swap, the changes in value of the cap-swap are not completely effective in offsetting changes in value of the corresponding counter-swap. Changes in the value of cap-swaps and counter-swaps are recorded as adjustments to oil and natural gas sales.

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

Chesapeake enters into basis protection swaps for the purpose of locking-in a price differential for oil or natural gas from a specified delivery point. We currently have basis protection swaps covering six different delivery points, four in the Mid-Continent and two in the Appalachian Basin, which correspond to the actual prices we receive for much of our natural gas production. By entering into these basis protection swaps, we have

 

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effectively reduced our exposure to market changes in future natural gas price differentials. As of September 30, 2006, the fair value of our basis protection swaps was $178.8 million. As of September 30, 2006, our Mid-Continent basis protection swaps covered approximately 29% of our anticipated Mid-Continent natural gas production remaining in 2006, 25% in 2007, 18% in 2008 and 13% in 2009. As of September 30, 2006, our Appalachian Basin basis protection swaps cover approximately 74% of our anticipated Appalachian Basin natural gas production in 2007, 65% in 2008 and 30% in 2009.

Gains or losses from derivative transactions are reflected as adjustments to oil and natural gas sales on the condensed consolidated statements of operations. Realized gains (losses) included in oil and natural gas sales were $301.4 million, ($122.6) million, $807.1 million and ($126.6) million in the Current Quarter, Prior Quarter, Current Period and Prior Period, respectively. Pursuant to SFAS 133, certain derivatives do not qualify for designation as cash flow hedges. Changes in the fair value of these non-qualifying derivatives that occur prior to their maturity (i.e., temporary fluctuations in value) are reported currently in the condensed consolidated statements of operations as unrealized gains (losses) within oil and natural gas sales. Unrealized gains (losses) included in oil and natural gas sales were $238.5 million, ($104.0) million, $452.6 million and ($137.1) million in the Current Quarter, Prior Quarter, Current Period and Prior Period, respectively.

Following provisions of SFAS 133, 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 other comprehensive income until the hedged item is recognized in earnings. Any change in fair value resulting from ineffectiveness is recognized currently in oil and natural gas sales as unrealized gains (losses). We recorded an unrealized gain (loss) on ineffectiveness of $171.8 million, ($99.5) million, $336.7 million and ($98.9) million in the Current Quarter, Prior Quarter, Current Period and Prior Period, respectively.

As of September 30, 2006, we had the following open oil and natural gas derivative instruments (excluding CNR derivatives assumed) designed to hedge a portion of our oil and natural gas production for periods after September 2006:

 

    Volume   Weighted
Average Fixed
Price to be
Received (Paid)
  Weighted
Average
Put
Fixed
Price
  Weighted
Average
Call
Fixed
Price
  Weighted
Average
Differential
    SFAS 133
Hedge
  Net Premiums
Received ($ in
thousands)
 

Fair

Value at
September 30,
2006

($ in
thousands)

Natural Gas (mmbtu):

               

Swaps:

               

4Q 2006

  106,585,000   $ 9.68   $ —     $ —     $ —       Yes   $ —     $ 422,505

1Q 2007

  102,150,000     11.09     —       —       —       Yes     —       336,329

2Q 2007

  78,715,000     9.18     —       —       —       Yes     —       152,602

3Q 2007

  79,580,000     9.24     —       —       —       Yes     —       142,030

4Q 2007

  79,580,000     9.90     —       —       —       Yes     —       135,751

1Q 2008

  64,610,000     10.84     —       —       —       Yes     —       114,992

2Q 2008

  64,610,000     8.45     —       —       —       Yes     —       71,924

3Q 2008

  65,320,000     8.51     —       —       —       Yes     —       67,639

4Q 2008

  65,320,000     9.15     —       —       —       Yes     —       68,693

1Q 2009

  900,000     10.53     —       —       —       Yes     —       1,551

2Q 2009

  910,000     8.29     —       —       —       Yes     —       1,093

3Q 2009

  920,000     8.34     —       —       —       Yes     —       1,026

4Q 2009

  920,000     8.95     —       —       —       Yes     —       998

Basis Protection Swaps (Mid-Continent):

               

4Q 2006

  33,720,000     —       —       —       (0.32 )   No     —       13,446

1Q 2007

  32,850,000     —       —       —       (0.29 )   No     —       18,781

2Q 2007

  34,125,000     —       —       —       (0.35 )   No     —       13,449

3Q 2007

  34,500,000     —       —       —       (0.35 )   No     —       11,385

4Q 2007

  35,720,000     —       —       —       (0.32 )   No     —       25,796

1Q 2008

  33,215,000     —       —       —       (0.30 )   No     —       28,210

2Q 2008

  26,845,000     —       —       —       (0.25 )   No     —       15,241

3Q 2008

  27,140,000     —       —       —       (0.25 )   No     —       13,469

4Q 2008

  31,410,000     —       —       —       (0.28 )   No     —       18,293

1Q 2009

  26,100,000     —       —       —       (0.32 )   No     —       13,746

2Q 2009

  20,020,000     —       —       —       (0.28 )   No     —       1,906

3Q 2009

  20,240,000     —       —       —       (0.28 )   No     —       1,348

4Q 2009

  20,240,000     —       —       —       (0.28 )   No     —       4,726

 

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Table of Contents
    Volume     Weighted
Average Fixed
Price to be
Received (Paid)
  Weighted
Average
Put
Fixed
Price
  Weighted
Average
Call
Fixed
Price
  Weighted
Average
Differential
  SFAS 133
Hedge
  Net Premiums
Received ($ in
thousands)
 

Fair

Value at
September 30,
2006

($ in
thousands)

 

Basis Protection Swaps (Appalachian Basin):

               

1Q 2007

  9,000,000     $ —     $ —     $ —     $ 0.35   No   $ —     $ 273  

2Q 2007

  9,100,000       —       —       —       0.35   No     —       (462 )

3Q 2007

  9,200,000       —       —       —       0.35   No     —       (491 )

4Q 2007

  9,200,000       —       —       —       0.35   No     —       (55 )

1Q 2008

  9,100,000       —       —       —       0.35   No     —       652  

2Q 2008

  9,100,000       —       —       —       0.35   No     —       (338 )

3Q 2008

  9,200,000       —       —       —       0.35   No     —       (365 )

4Q 2008

  9,200,000       —       —       —       0.35   No     —       (152 )

1Q 2009

  4,500,000       —       —       —       0.31   No     —       205  

2Q 2009

  4,550,000       —       —       —       0.31   No     —       (108 )

3Q 2009

  4,600,000       —       —       —       0.31   No     —       (121 )

4Q 2009

  4,600,000       —       —       —       0.31   No     —       (2 )

Cap-Swaps:

               

4Q 2006

  11,960,000       6.89     5.13     —       —     No     —       (1,869 )

1Q 2007

  14,400,000       11.44     5.73     —       —     No     —       28,620  

2Q 2007

  19,110,000       9.57     5.91     —       —     No     —       8,120  

3Q 2007

  19,320,000       9.76     5.91     —       —     No     —       2,402  

4Q 2007

  19,320,000       10.56     5.91     —       —     No     —       6,113  

1Q 2008

  19,110,000       11.58     6.18     —       —     No     —       11,135  

2Q 2008

  19,110,000       10.00     6.18     —       —     No     —       6,369  

3Q 2008

  19,320,000       10.09     6.18     —       —     No     —       3,863  

4Q 2008

  19,320,000       10.65     6.18     —       —     No     —       4,383  

Counter Swaps:

               

4Q 2006

  (36,605,000 )     5.27     —       —       —     No     —       600  

1Q 2007

  (900,000 )     7.53     —       —       —     No     —       243  

2Q 2007

  (4,550,000 )     7.09     —       —       —     No     —       675  

3Q 2007

  (4,600,000 )     7.31     —       —       —     No     —       659  

4Q 2007

  (4,600,000 )     8.03     —       —       —     No     —       755  

1Q 2008

  (4,550,000 )     8.84     —       —       —     No     —       1,000  

2Q 2008

  (4,550,000 )     7.14     —       —       —     No     —       880  

3Q 2008

  (4,600,000 )     7.28     —       —       —     No     —       903  

4Q 2008

  (4,600,000 )     7.90     —       —       —     No     —       931  

Call Options:

               

4Q 2006

  1,840,000       —       —       12.50     —     No     1,932     (51 )

1Q 2007

  6,300,000       —       —       11.58     —     No     1,890     (2,575 )

2Q 2007

  6,370,000       —       —       9.96     —     No     1,911     (3,077 )

3Q 2007

  6,440,000       —       —       10.04     — &n