Amended Form 10-Q
Table of Contents

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 


 

FORM 10-Q/A

 

x   QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE
       SECURITIES EXCHANGE ACT OF 1934

 

         For the quarterly period ended June 30, 2003

 

¨   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 an accelerated filer (as defined in Rule 12b-2 of the Exchange Act).  YES  x  NO  ¨

 

At August 11, 2003, there were 216,057,569 shares of our $0.01 par value common stock outstanding.

 



Table of Contents

AMENDMENT NO. 1

EXPLANATORY NOTE

 

As described in Note 11 to the Condensed Consolidated Financial Statements, Chesapeake Energy Corporation has reclassified certain amounts previously reported Condensed Consolidated Statement of Operations and has made the corresponding revisions to the Notes to Consolidated Financial Statements for the three and six months ended June 30, 2003 and 2002. The revisions had no effect on previously reported net income or net income per share.

 

Corresponding changes resulting from these revisions of classifications in the financial statements were also made to Item 2. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Item 3. “Quantitative and Qualitative Disclosures About Market Risk”.

 

In light of the refiling of this report for the purpose of revising the financial statements, we have also revised other disclosures from the original filing in response to comments of the staff of the Securities and Exchange Commission.

 

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

 

INDEX TO FORM 10-Q FOR THE QUARTER ENDED JUNE 30, 2003

 

          Page

           

PART I.

    

Financial Information

    

Item 1.

   Consolidated Financial Statements (Unaudited):     
    

Condensed Consolidated Balance Sheets at June 30, 2003 and December 31, 2002

   4
    

Condensed Consolidated Statements of Operations for the Three Months and Six Months Ended June 30, 2003 and 2002

   5
    

Condensed Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2003 and 2002

   6
    

Condensed Consolidated Statements of Comprehensive Income (Loss) for the Three Months and Six Months Ended June 30, 2003 and 2002

   7
    

Notes to Condensed Consolidated Financial Statements

   8

Item 2.

   Management’s Discussion and Analysis of Financial Condition and Results of Operations    27

Item 3.

   Quantitative and Qualitative Disclosures About Market Risk    37

Item 4.

   Controls and Procedures    40

PART II.

    

Other Information

    

Item 1.

   Legal Proceedings    41

Item 2.

   Changes in Securities and Use of Proceeds    41

Item 3.

   Defaults Upon Senior Securities    41

Item 4.

   Submission of Matters to a Vote of Security Holders    41

Item 5.

   Other Information    41

Item 6.

   Exhibits and Reports on Form 8-K    41

 

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Table of Contents

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

 

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

 

    

June 30,

2003


   

December 31,

2002


 
     ($ in thousands)  

ASSETS

                

CURRENT ASSETS:

                

Cash and cash equivalents

   $ 35,909     $ 247,637  

Restricted cash

     —         82  

Accounts receivable:

                

Oil and gas sales

     190,453       109,246  

Joint interest, net of allowance of $2,644,000 and $1,433,000, respectively

     24,973       22,760  

Short-term derivatives

     342       16,498  

Related parties

     3,853       2,155  

Other

     27,647       13,471  

Deferred income tax asset

     6,479       8,109  

Short-term derivative instruments

     31,331       —    

Inventory and other

     12,480       15,359  
    


 


Total Current Assets

     333,467       435,317  
    


 


PROPERTY AND EQUIPMENT:

                

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

                

Evaluated oil and gas properties

     5,575,048       4,334,833  

Unevaluated properties

     177,837       72,506  

Less: accumulated depreciation, depletion and amortization

     (2,280,690 )     (2,123,773 )
    


 


       3,472,195       2,283,566  

Other property and equipment

     175,817       154,092  

Less: accumulated depreciation and amortization

     (52,846 )     (47,774 )
    


 


Total Property and Equipment

     3,595,166       2,389,884  
    


 


OTHER ASSETS:

                

Deferred income tax asset

     —         2,071  

Long-term derivative instruments

     24,873       2,666  

Long-term investments

     29,075       9,075  

Other assets

     30,779       36,595  
    


 


Total Other Assets

     84,727       50,407  
    


 


TOTAL ASSETS

   $ 4,013,360     $ 2,875,608  
    


 


LIABILITIES AND STOCKHOLDERS’ EQUITY

                

CURRENT LIABILITIES:

                

Accounts payable

   $ 128,579     $ 86,001  

Accrued interest

     47,787       35,025  

Derivative payable

     2,296       —    

Short-term derivative instruments

     42,384       33,697  

Other accrued liabilities

     83,665       56,465  

Revenues and royalties due others

     111,160       54,364  
    


 


Total Current Liabilities

     415,871       265,552  
    


 


OTHER LIABILITIES:

                

Long-term debt, net

     1,968,447       1,651,198  

Revenues and royalties due others

     14,882       13,797  

Long-term derivative instruments

     3,442       30,174  

Asset retirement obligation

     44,699       —    

Other liabilities

     10,479       7,012  

Deferred income taxes payable

     92,068       —    
    


 


Total Other Liabilities

     2,134,017       1,702,181  
    


 


CONTINGENCIES AND COMMITMENTS (Note 3)

                

STOCKHOLDERS’ EQUITY:

                

Preferred Stock, $0.01 par value, 10,000,000 shares authorized, 6.75% cumulative convertible preferred stock, 2,998,000 shares issued and outstanding at June 30, 2003 and December 31, 2002, entitled in liquidation to $149.9 million

     149,900       149,900  

6.00% cumulative convertible preferred stock, 4,600,000 and 0 shares issued and outstanding at June 30, 2003 and December 31, 2002, entitled in liquidation to $230.0 million

     230,000       —    

Common Stock, $.01 par value, 350,000,000 shares authorized, 220,933,661 and 194,936,912 shares issued at June 30, 2003 and December 31, 2002, respectively

     2,209       1,949  

Paid-in capital

     1,387,352       1,205,554  

Accumulated deficit

     (296,644 )     (426,085 )

Accumulated other comprehensive income (loss), net of tax of $(7,812,000) and $2,307,000, respectively

     12,746       (3,461 )

Less: treasury stock, at cost; 5,071,571 and 4,792,529 common shares at June 30, 2003 and December 31, 2002, respectively

     (22,091 )     (19,982 )
    


 


Total Stockholders’ Equity

     1,463,472       907,875  
    


 


TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY

   $ 4,013,360     $ 2,875,608  
    


 


 

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

 

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

 

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

 

    

Three Months Ended

June 30,


   

Six Months Ended

June 30,


 
     2003

    2002

    2003

    2002

 
     ($ in thousands, except per share data)  
     (Revised—Note 11)  

REVENUES:

            

Oil and gas sales

   $ 319,519     $ 150,905     $ 605,538     $ 213,561  

Oil and gas marketing sales

     110,296       42,785       200,604       70,118  
    


 


 


 


Total Revenues

     429,815       193,690       806,142       283,679  
    


 


 


 


OPERATING COSTS:

                                

Production expenses

     34,263       24,242       65,720       46,302  

Production taxes

     17,101       7,911       35,698       13,127  

General and administrative

     6,000       3,859       11,665       8,153  

Oil and gas marketing expenses

     106,857       41,181       196,215       67,688  

Oil and gas depreciation, depletion and amortization

     91,570       50,778       168,184       99,397  

Depreciation and amortization of other assets

     4,122       3,652       7,806       6,762  
    


 


 


 


Total Operating Costs

     259,913       131,623       485,288       241,429  
    


 


 


 


INCOME FROM OPERATIONS

     169,902       62,067       320,854       42,250  
    


 


 


 


OTHER INCOME (EXPENSE):

                                

Interest and other income

     781       3,992       1,544       5,537  

Interest expense

     (38,036 )     (24,067 )     (75,040 )     (51,180 )

Loss on repurchases of Chesapeake debt

     —         (273 )     —         (864 )
    


 


 


 


Total Other Income (Expense)

     (37,255 )     (20,348 )     (73,496 )     (46,507 )
    


 


 


 


INCOME (LOSS) BEFORE INCOME TAX AND CUMULATIVE EFFECT OF ACCOUNTING CHANGE

     132,647       41,719       247,358       (4,257 )

INCOME TAX EXPENSE (BENEFIT):

                                

Current

     —         —         —         —    

Deferred

     50,407       16,686       93,998       (1,704 )
    


 


 


 


Total Income Tax Expense (Benefit)

     50,407       16,686       93,998       (1,704 )
    


 


 


 


NET INCOME (LOSS) BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE

     82,240       25,033       153,360       (2,553 )

Cumulative effect of accounting change, net of income taxes of $1,464,000

     —         —         2,389       —    
    


 


 


 


NET INCOME (LOSS)

     82,240       25,033       155,749       (2,553 )

Preferred stock dividends

     (5,979 )     (2,530 )     (9,505 )     (5,062 )
    


 


 


 


NET INCOME (LOSS) AVAILABLE TO COMMON SHAREHOLDERS

   $ 76,261     $ 22,503     $ 146,244     $ (7,615 )
    


 


 


 


EARNINGS (LOSS) PER COMMON SHARE—BASIC:

                                

Income (loss) before cumulative effect of accounting change

   $ 0.36     $ 0.14     $ 0.70     $ (0.05 )

Cumulative effect of accounting change

     —         —         0.01       —    
    


 


 


 


Net income (loss)

   $ 0.36     $ 0.14     $ 0.71     $ (0.05 )
    


 


 


 


EARNINGS (LOSS) PER COMMON SHARE—ASSUMING DILUTION:

                                

Income (loss) before cumulative effect of accounting change

   $ 0.31     $ 0.13     $ 0.62     $ (0.05 )

Cumulative effect of accounting change

     —         —         0.01       —    
    


 


 


 


Net income (loss)

   $ 0.31     $ 0.13     $ 0.63     $ (0.05 )
    


 


 


 


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

                                

Basic

     214,341       165,963       205,995       165,669  
    


 


 


 


Assuming dilution

     263,919       191,947       247,391       165,669  
    


 


 


 


 

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)

 

     Six Months Ended June 30,

 
     2003

    2002

 
     ($ in thousands)  

CASH FLOWS FROM OPERATING ACTIVITIES:

                

NET INCOME (LOSS)

   $ 155,749     $ (2,553 )

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

                

Depreciation, depletion and amortization

     172,543       103,770  

Unrealized (gains) losses on derivatives

     (30,794 )     79,949  

Deferred income taxes

     93,998       (1,702 )

Amortization of loan costs and bond discount

     4,110       2,899  

Cumulative effect of accounting change

     (2,389 )     —    

Other

     565       167  
    


 


Cash provided by operating activities before changes in assets and liabilities

     393,782       182,530  

Changes in assets and liabilities

     (17,149 )     32,295  
    


 


Cash provided by operating activities

     376,633       214,825  
    


 


CASH FLOWS FROM INVESTING ACTIVITIES:

                

Exploration and development of oil and gas properties

     (307,090 )     (176,386 )

Acquisition of unproved oil and gas properties

     (123,122 )     (7,167 )

Acquisition of proved oil and gas properties

     (863,050 )     (124,305 )

Sales of proved oil and gas properties

     19,667       —    

Investment in Pioneer Drilling Company

     (20,000 )     —    

Additions to other property, plant and equipment and other

     (22,179 )     (16,714 )
    


 


Cash used in investing activities

     (1,315,774 )     (324,572 )
    


 


CASH FLOWS FROM FINANCING ACTIVITIES:

                

Proceeds from long-term borrowings

     296,000       45,000  

Payments on long-term borrowings

     (270,000 )     —    

Cash received from issuance of senior notes

     297,306       —    

Cash paid for issuance costs of senior notes

     (6,367 )     —    

Proceeds from issuance of preferred stock, net of issuance costs

     222,893       —    

Proceeds from issuance of common stock, net of issuance costs

     177,444       —    

Net increase in outstanding payments in excess of cash balances

     29,474       —    

Cash paid for common stock dividend

     (12,125 )     —    

Cash paid for preferred stock dividend

     (8,893 )     (5,118 )

Cash paid to repurchase senior notes

     —         (43,220 )

Cash paid for treasury stock

     (2,109 )     —    

Cash received from exercise of stock options and warrants

     6,326       1,956  

Other

     (2,536 )     (169 )
    


 


Cash provided by (used in) financing activities

     727,413       (1,551 )
    


 


NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS

     (211,728 )     (111,298 )

CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD

     247,637       117,594  
    


 


CASH AND CASH EQUIVALENTS, END OF PERIOD

   $ 35,909     $ 6,296  
    


 


 

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

 

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

 

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(Unaudited)

 

     Three Months Ended
June 30,


   

Six Months Ended

June 30,


 
     2003

    2002

    2003

    2002

 
     ($ in thousands)  

Net income (loss)

   $ 82,240     $ 25,033     $ 155,749     $ (2,553 )

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

                                

Change in fair value of derivative instruments

     11,696       (2,242 )     (36,859 )     (12,972 )

Reclassification of (gain) or loss on settled contracts

     2,461       (1,683 )     53,352       (15,769 )

Ineffective portion of derivatives qualifying for cash flow hedge accounting

     (256 )     815       (286 )     1,309  
    


 


 


 


Comprehensive income (loss)

   $ 96,141     $ 21,923     $ 171,956     $ (29,985 )
    


 


 


 


 

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

 

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

1. Basis of Presentation and Summary of Significant Accounting Policies

 

Principles of Consolidation

 

The accompanying unaudited consolidated financial statements of Chesapeake Energy Corporation and Subsidiaries have been prepared in accordance with the instructions to Form 10-Q as prescribed by the Securities and Exchange Commission. All material adjustments (consisting solely of normal recurring adjustments) which, in the opinion of management, are necessary for a fair presentation of the results for the interim periods have been reflected. The results for the three and six months ended June 30, 2003 are not necessarily indicative of the results to be expected for the full year. This Form 10-Q relates to the three and six months ended June 30, 2002 (the “Prior Quarter” and “Prior Period”, respectively) and the three and six months ended June 30, 2003 (the “Current Quarter” and “Current Period”, respectively).

 

Stock Options

 

Chesapeake has elected to follow APB No. 25, Accounting for Stock Issued to Employees, and related interpretations in accounting for its employee stock options. Under APB No. 25, compensation expense is recognized for the difference between the option price and market value on the measurement date. In March 2000, the Financial Accounting Standards Board issued FASB Interpretation No. 44 which provided clarification regarding the application of APB No. 25. FIN 44 specifically addressed the accounting consequences of various modifications to the terms of a previously granted fixed–price stock option. Pursuant to FIN 44, we recognized no compensation adjustment in the Prior Quarter and compensation expense of $387,900, $365,300 and $162,500 in the Current Quarter, the Current Period and the Prior Period, respectively, as a result of modifications to fixed-price stock options that were made during the years ended December 31, 2001 and 2000. No compensation income or expense has been recognized for stock options issued in 2003 or 2002 because the exercise price of the stock options granted under the plans equaled the market price of the underlying stock on the date of grant and there have been no modifications to these options.

 

Presented below is pro forma financial information assuming that Chesapeake had applied the fair value method under SFAS No. 123:

 

     Three Months Ended
June 30,


    Six Months Ended
June 30,


 
     2003

    2002

    2003

    2002

 
     ($ in thousands)  

Net Income (Loss)

                                

As reported (1)

   $ 82,240     $ 25,033     $ 155,749     $ (2,553 )

Compensation expense, net of tax

     (2,539 )     (2,088 )     (5,014 )     (4,155 )
    


 


 


 


Pro forma

   $ 79,701     $ 22,945     $ 150,735     $ (6,708 )
    


 


 


 


Basic earnings (loss) per common share

                                

As reported

   $ 0.36     $ 0.14     $ 0.71     $ (0.05 )

Compensation expense, net of tax

     (0.01 )     (0.01 )     (0.02 )     (0.02 )
    


 


 


 


Pro forma

   $ 0.35     $ 0.13     $ 0.69     $ (0.07 )
    


 


 


 


Diluted earnings (loss) per common share

                                

As reported

   $ 0.31     $ 0.13     $ 0.63     $ (0.05 )

Compensation expense, net of tax

     (0.01 )     (0.01 )     (0.02 )     (0.02 )
    


 


 


 


Pro forma

   $ 0.30     $ 0.12     $ 0.61     $ (0.07 )
    


 


 


 



(1)   Net income includes adjustments related to FIN 44 of $387,900, $365,300 and $162,500 of expense in the Current Quarter, the Current Period and the Prior Period, respectively.

 

For purposes of the pro forma disclosures, the estimated fair value of the options is amortized to expense over the options’ vesting period, which is four years. Because our stock options vest over four years and additional awards are typically made each year, the above pro forma disclosures are not likely to be representative of the effects on pro forma net income for future quarters.

 

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Critical Accounting Policies

 

We consider accounting policies related to stock options, hedging, oil and 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, 2002, except for our accounting policy related to stock options which is summarized in Note 1 of the notes to the consolidated financial statements included in our annual report on Form 10-K.

 

Statement of Financial Accounting Standards No. 141, Business Combinations and Statement of Financial Accounting Standards No. 142, Goodwill and Intangible Assets were issued by the Financial Accounting Standards Board in June 2001 and became effective for us on July 1, 2001 and January 1, 2002, respectively. SFAS 141 requires all business combinations initiated after June 30, 2001 to be accounted for using the purchase method. Additionally, SFAS 141 requires companies to disaggregate and report separately from goodwill certain intangible assets. SFAS 142 establishes new guidelines for accounting for goodwill and other intangible assets. Under SFAS 142, goodwill and certain other intangible assets are not amortized, but rather are reviewed annually for impairment.

 

Oil and gas mineral rights held under lease and other contractual arrangements representing the right to extract such reserves for both undeveloped and developed leaseholds may have to be classified separately from oil and gas properties as intangible assets on our condensed consolidated balance sheets. In addition, the disclosures required by SFAS 141 and 142 relative to intangibles would be included in the notes to the condensed consolidated financial statements. Historically, we, like many other oil and gas companies, have included these rights as part of oil and gas properties, even after SFAS 141 and 142 became effective.

 

As it applies to companies like us that have adopted full cost accounting for oil and gas activities, we understand that this interpretation of SFAS 141 and 142 would only affect our balance sheet classification of proved oil and gas leaseholds acquired after June 30, 2001 and all of our unproved oil and gas leaseholds. We would not be required to reclassify proved reserve leasehold acquisitions prior to June 30, 2001 because we did not separately value or account for these costs prior to the adoption date of SFAS 141. Our results of operations and cash flows would not be affected, since these oil and gas mineral rights held under lease and other contractual arrangements representing the right to extract oil and gas reserves would continue to be amortized in accordance with full cost accounting rules.

 

As of June 30, 2003 and December 31, 2002, we had undeveloped leaseholds of approximately $177.8 million and $72.5 million, respectively, that would be classified on our condensed consolidated balance sheet as “intangible undeveloped leasehold” and developed leaseholds of an estimated $1,423.0 million and $581.9 million, respectively, that would be classified as “intangible developed leasehold” if we applied the interpretation discussed above.

 

We will continue to classify our oil and gas mineral rights held under lease and other contractual rights representing the right to extract such reserves as tangible oil and gas properties until further guidance is provided.

 

2. Financial Instruments and Hedging Activities

 

Oil and Gas Hedging Activities

 

Our results of operations and operating cash flows are impacted by changes in market prices for oil and gas. To mitigate a portion of the exposure to adverse market changes, we have entered into various derivative instruments. As of June 30, 2003, our oil and gas derivative instruments were comprised of swaps, cap-swaps and basis protection swaps. These instruments allow us to predict with greater certainty the effective oil and 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, we receive a fixed price for the hedged commodity and pay a floating market price, as defined in each instrument, 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.

 

    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. Because this derivative includes a written put option (i.e., the cap), cap-swaps do not qualify

 

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for designation as cash flow hedges (in accordance with SFAS 133) since the combination of the hedged item and the written option do not provide as much potential for favorable cash flows as exposure to unfavorable cash flows.

 

    Basis protection swaps are arrangements that guarantee a price differential of oil or gas from a specified delivery point. 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.

 

Chesapeake enters into counter-swaps from time to time for the purpose of locking-in the value of a swap or cap-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. 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 gas prices. Any locked-in gain or loss is recorded in accumulated other comprehensive income and reclassified to oil and gas sales in the month of related production.

 

When Chesapeake enters into a counter-swap with the same counterparty, to the extent that a right of setoff exists in accordance with FASB Interpretation No. 39, we net the value of the swap and the counter-swap.

 

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 a 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 the value of the corresponding counter-swap.

 

Chesapeake enters into oil and gas derivative transactions in order to mitigate a portion of its exposure to adverse market changes in oil and gas commodity prices. Accordingly, we believe that any associated gains or losses from the derivative transactions should be reflected as adjustments to oil and gas sales on the condensed consolidated statement of operations. 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 gas sales. Unrealized gains (losses) included in oil and gas sales in the Current Period and Prior Period were $33.0 million and ($80.4) million, 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 attributed to the hedged risk, are recorded in other comprehensive income. Any change in fair value resulting from ineffectiveness is recognized currently in oil and gas sales. These amounts totaled to a gain of $0.5 million in the Current Period and a loss of $2.2 million in the Prior Period, a gain of $0.4 million in the Current Quarter and a loss of $1.4 million in the Prior Quarter.

 

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The estimated fair values of our oil and gas derivative instruments as of June 30, 2003 are provided below. The associated carrying values of these instruments are equal to the estimated fair values.

 

     June 30, 2003

 
     ($ in thousands)  

Derivative assets (liabilities):

        

Fixed-price gas swaps

   $ 21,393  

Fixed-price gas cap-swaps

     (49,558 )

Fixed-price gas counter-swaps

     45,799  

Fixed-price gas locked swaps

     (1,429 )

Gas basis protection swaps

     33,429  

Fixed-price crude oil cap-swaps

     (3,431 )
    


Estimated fair value

   $ 46,203  
    


 

Based upon the market prices at June 30, 2003, we expect to transfer approximately $13.7 million of the gain included in the balance in accumulated other comprehensive income to earnings during the next 12 months when the hedged transactions actually close. All transactions hedged as of June 30, 2003 will mature by 2007, with the exception of the basis protection swaps which extend to 2009.

 

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

 

     2003

 
     ($ in thousands)  

Fair value of contracts outstanding at January 1

   $ (14,533 )

Change in fair value of contracts during the period

     (30,952 )

Contracts realized or otherwise settled during the period

     91,688  

Fair value of new contracts when entered into during the period

     —    
    


Fair value of contracts outstanding at June 30

   $ 46,203  
    


 

Interest Rate Hedging

 

We also utilize hedging strategies to manage interest rate exposure. Results from interest rate hedging transactions are reflected as adjustments to interest expense in the corresponding months covered by the derivative agreement.

 

In July 2002, we closed two interest rate swaps for a cash settlement of $8.6 million. As of June 30, 2003, the remaining balance to be amortized as a reduction to interest expense was $0.4 million. During the Current Quarter and Current Period, $0.2 million and $0.3 million, respectively, was recorded as a reduction to interest expense.

 

In March 1997, Chesapeake issued $150.0 million of 8.5% senior notes due 2012, of which $7.3 million were subsequently repurchased and retired. The 8.5% senior notes include a “call option” whereby Chesapeake may redeem the debt at declining redemption prices beginning in March 2004. This call option, also referred to as a right of optional redemption, allows Chesapeake to redeem the notes prior to their stated maturity date beginning in March 2004. This right of optional redemption has value depending upon changes in interest rates. Due to a decline in interest rates, Chesapeake effectively sold this optional redemption right to an unrelated third party (or counterparty) for $7.8 million in April 2002. In exchange for $7.8 million, Chesapeake gave the counterparty the option to elect whether or not to enter into an interest rate swap with Chesapeake on March 11, 2004. This transaction is more commonly referred to as a swaption. The terms of the interest rate swap, if executed by the counterparty, would be as follows:

 

Term


 

Notional Amount


 

Fixed Rate


 

Floating Rate


March 2004—March 2012

  $142,665,000   8.5%   U.S. six-month LIBOR plus 75 basis points

 

The interest rate swap would require Chesapeake to pay a fixed rate of 8.5% while the counterparty pays Chesapeake a floating rate of 6 month LIBOR in arrears plus 0.75%. Additionally, if the counterparty elects to enter into the interest rate swap on March 11, 2004, it may also elect to force Chesapeake to settle the transaction at the then current value of the interest rate swap.

 

This transaction does not alter Chesapeake’s ability to redeem the 8.5% senior notes. Instead, it locks-in the economics of a future call. If interest rates are high and the swaption is not “in-the-money”, the counterparty will likely not elect to enter into the interest rate swap, the swaption will expire, and Chesapeake will amortize the $7.8

 

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million premium as a reduction to interest expense over the remaining life of the notes. If interest rates are low and the swaption is “in-the-money”, the counterparty will likely exercise the swaption and force Chesapeake to settle the transaction at the then current value of the interest rate swap, and Chesapeake will amortize both the $7.8 million premium and the amount paid to the counterparty to interest expense over the remaining life of the notes. If Chesapeake elects to refinance the 8.5% senior notes, any unamortized premium or loss remaining related to the swaption would be included in the gain (or loss) on the early extinguishment of debt.

 

According to SFAS 133, a fair value hedge relationship exists between the embedded call option in the 8.5% senior notes and the swaption agreement. The fair value of the swaption is recorded on the condensed consolidated balance sheets as a liability, and the debt’s carrying amount is adjusted by the change in the fair value of the call option subsequent to the initiation of the swaption. Any resulting differences are recorded currently as ineffectiveness in the condensed consolidated statements of operations as an adjustment to interest expense.

 

We have recorded an adjustment to the carrying amount of the debt of $25.3 million as of June 30, 2003. Since the inception of the swaption, we recorded the change in the fair market value of the swaption from a $7.8 million liability to a $37.8 million liability, an increase of $30.0 million. As part of recording the fair value hedge, we also recorded, as an adjustment to the carrying value of the debt, a $25.3 million increase in the fair value of the embedded call option. The difference between the two adjustments, $4.7 million representing ineffectiveness, was recorded as additional interest expense. Results of the interest rate swap, if initiated, will be reflected as adjustments to interest expense in the corresponding months.

 

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 using available market information and valuation methodologies. Considerable judgment is required in interpreting market data to develop the estimates of fair value. The use of different market assumptions or valuation methodologies may have a material effect on the estimated fair value amounts.

 

The carrying values of items 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 using primarily quoted market prices. Our carrying amount for such debt, excluding the value of the interest rate swaps and the call option on the 8.5% senior notes, at June 30, 2003 and December 31, 2002 was $1,967.3 million and $1,669.3 million, respectively, compared to approximate fair values of $2,131.3 million and $1,744.7 million, respectively. The carrying amount for our 6.75% convertible preferred stock at June 30, 2003 and December 31, 2002 was $149.9 million, with a fair value of $227.1 million and $181.5 million, respectively. The carrying amount of our 6.00% convertible preferred stock was $230.0 million which approximated its fair value as of June 30, 2003.

 

Concentration of Credit Risk

 

A significant portion of our liquidity is concentrated in cash and cash equivalents and 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. Other financial instruments which potentially subject us to concentrations of credit risk consist principally of investments in debt and equity instruments and accounts receivable. 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. The 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. Cash and cash equivalents are deposited with major banks or institutions and may at times exceed the federally insured limits.

 

3. Contingencies and Commitments

 

Royalty Owner Litigation. Royalty owners have commenced litigation against a number of oil and gas producers claiming that amounts paid for production attributable to the royalty owners’ interest violated the terms of applicable leases and state law, that deductions from the proceeds of oil and gas production were unauthorized under the leases, and that amounts received by upstream sellers should be used to compute the amounts paid to the royalty owners. Typically this litigation has taken the form of class action suits. There are presently four such suits filed against Chesapeake, two in Texas and two in Oklahoma. No class has been certified in any of them. In one of the

 

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Oklahoma cases, we determined that a portion of the marketing fee we had charged royalty owners should be refunded. We have deposited with the court the aggregate amount of the fees we estimated should be refunded, $3.6 million, in an interest-bearing account for distribution to affected royalty owners. This amount has been charged to general and administrative expenses, of which $0.3 million was charged in the Current Period and the remainder was recorded in 2002. We do not believe any other claims made by royalty owners in the cases pending against us are valid. Even if the claims were upheld, we believe any damages awarded would not be material. This is a developing area of the law, however, and as new cases are decided, our potential liability relating to the marketing of oil and gas may increase or decrease. We will continue to monitor court decisions to ensure that our operations and practices minimize any exposure and to recognize any charges that may be appropriate when we can reasonably estimate a liability.

 

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

 

Chesapeake has employment agreements with its chief executive officer, chief operating officer, chief financial officer and various other senior management personnel, which provide for annual base salaries, bonus compensation and various benefits. The agreements provide for the continuation of salary and benefits for varying terms in the event of termination of employment without cause. The agreements with the chief executive officer and chief operating officer have terms of five years commencing July 1, 2002. The term of each agreement is automatically extended for one additional year on each June 30 unless one of the parties provides 30 days notice of non-extension. The agreements with the chief financial officer and other senior managers expire on June 30, 2006. The company’s employment agreements for executive officers provide for payments in the event of a change of control. The chief executive officer and chief operating officer are each entitled to receive a payment in the amount of five times his base compensation and the prior year’s benefits, plus a tax gross-up payment, and the chief financial officer and other officers are each entitled to receive a payment in the amount of his or her base compensation plus bonuses paid during the prior year.

 

Due to the nature of the oil and 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 its environmental risk profile. These reviews evaluate whether there is a probable 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 the 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 June 30, 2003.

 

4. Net Income (Loss) 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 Prior Quarter, the Current Quarter, the Prior Period and the Current Period, outstanding warrants to purchase 1.1 million, 0.4 million, 1.1 million and 0.4 million shares of common stock at a weighted-average exercise price of $12.61, $14.55, $12.61 and $14.55, respectively, were antidilutive because the exercise prices of the warrants were greater than the average market price of the common stock.

 

    For the Prior Quarter, the Current Quarter, the Prior Period and the Current Period, outstanding options to purchase 0.3 million, 0.4 million, 0.4 million and 0.3 million shares of common stock at a weighted-average exercise price of $15.30, $15.47, $14.44 and $16.33, respectively, were antidilutive because the

 

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exercise prices of the options were greater than the average market price of the common stock.

 

    As a result of the Prior Period’s net loss to common shareholders, the diluted shares do not include the effect of outstanding stock options to purchase 5.9 million shares of common stock at a weighted-average exercise price of $3.90, the assumed conversion of the outstanding 6.75% preferred stock (convertible into 19.5 million common shares), the common stock equivalent of preferred stock outstanding prior to conversion (11,480 shares), or warrants to purchase 6,574 shares of common stock at a weighted-average exercise price of $0.05 as the effects were antidilutive.

 

A reconciliation for the three months ended June 30, 2003 and 2002 and the six months ended June 30, 2003 is as follows:

 

    

Income

(Numerator)


  

Shares

(Denominator)


  

Per Share

Amount


     (in thousands, except per share data)

For the Three Months Ended June 30, 2003:

                  

Basic EPS

                  

Income available to common shareholders

   $ 76,261    214,341    $ 0.36
                

Effect of Dilutive Securities

                  

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

                  

Preferred dividends

     5,979    —         

Common shares assumed issued for 6.00% preferred stock

     —      22,358       

Common shares assumed issued for 6.75% preferred stock

     —      19,468       

Employee stock options

     —      7,752       
    

  
      

Diluted EPS

                  

Income available to common shareholders and assumed conversions

   $ 82,240    263,919    $ 0.31
    

  
  

For the Three Months Ended June 30, 2002:

                  

Basic EPS

                  

Income available to common shareholders

   $ 22,503    165,963    $ 0.14
                

Effect of Dilutive Securities

                  

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

                  

Preferred dividends

     2,530    —         

Common shares assumed issued for 6.75% preferred stock

     —      19,478       

Employee stock options

     —      6,500       

Warrants assumed in Gothic acquisition

     —      6       
    

  
      

Diluted EPS

                  

Income available to common shareholders and assumed conversions

   $ 25,033    191,947    $ 0.13
    

  
  

For the Six Months Ended June 30, 2003:

                  

Basic EPS

                  

Income available to common shareholders

   $ 146,244    205,995    $ 0.71
                

Effect of Dilutive Securities

                  

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

                  

Preferred dividends

     9,505    —         

Common shares assumed issued for 6.00% preferred stock

     —      14,576       

Common shares assumed issued for 6.75% preferred stock

     —      19,468       

Employee stock options

     —      7,352       
    

  
      

Diluted EPS

                  

Income available to common shareholders and assumed conversions

   $ 155,749    247,391    $ 0.63
    

  
  

 

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5. Senior Notes and Revolving Credit Facility

 

At June 30, 2003, our long-term debt consisted of the following ($ in thousands):

 

7.875% senior notes, due 2004

   $ 42,137 (1)

8.375% senior notes, due 2008

     250,000  

8.125% senior notes, due 2011

     800,000  

8.500% senior notes, due 2012

     142,665  

9.000% senior notes, due 2012

     300,000  

7.500% senior notes, due 2013

     300,000  

7.750% senior notes, due 2015

     150,000  

Revolving bank credit facility

     26,000  

Discount on senior notes

     (17,513 )

Call option on 8.5% senior notes

     (25,267 )(2)

Interest rate swaps

     425  
    


Total

   $ 1,968,447  
    



(1)   This amount has been classified as long-term debt based on our ability to satisfy this obligation with funding from our bank credit facility.
(2)   See Note 2 of the notes to the condensed consolidated financial statements included in this report for further discussion on the call option.

 

On March 5, 2003, we issued $300.0 million principal amount of 7.50% senior notes due 2013, which have not been registered under the Securities Act of 1933.

 

On June 30, 2003, we had a $350 million revolving bank credit facility (with a committed borrowing base of $350 million) which matures in May 2007. As of June 30, 2003, we had $26.0 million in outstanding borrowings under this facility and were using $25.3 million of the facility to secure various letters of credit. Borrowings under the facility are collateralized by certain producing oil and gas properties and bear interest at either the reference rate of Union Bank of California, N.A., or London Interbank Offered Rate (LIBOR), at our option, plus a margin that varies according to our senior unsecured long-term debt ratings issued by Standard & Poor’s Ratings Services and Moody’s Investor Service. The unused portion of the facility is subject to an annual commitment fee also based on our senior unsecured long-term debt ratings. Interest is payable quarterly. The collateral value and borrowing base are redetermined periodically.

 

The credit agreement contains various covenants and restrictive provisions which limit our ability to incur additional indebtedness, sell properties, pay dividends, purchase or redeem our capital stock, make investments or loans, purchase certain of our senior notes and create liens. The credit agreement requires us to maintain a current ratio of at least 1 to 1 (as defined in the credit facility) and a fixed charge coverage ratio for the trailing twelve month period of at least 2.5 to 1. At June 30, 2003, our current ratio was 1.6 to 1 and our fixed charge coverage ratio was 3.6 to 1. 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. If such an acceleration involved principal in excess of $10.0 million, the acceleration would constitute an event of default under our senior note indentures, which could in turn result in the acceleration of our senior note indebtedness. The credit agreement also has cross default provisions that apply to other indebtedness we may have with an outstanding principal amount in excess of $25.0 million.

 

Our senior notes are unsecured senior obligations of Chesapeake and rank equally with all of our other unsecured indebtedness. The senior note indentures contain covenants limiting us and our guarantor subsidiaries with respect to asset sales; the incurrence of additional indebtedness and the issuance of preferred stock; liens; sale and leaseback transactions; lines of business; dividend and other payment restrictions affecting guarantor subsidiaries; mergers or consolidations; and transactions with affiliates. The senior note indentures also limit our ability to make restricted payments (as defined), including the payment of cash dividends, unless the debt incurrence and other tests are met. We may redeem the senior notes at any time at specified make-whole or redemption prices as provided in the indentures.

 

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, on a joint and several basis, by each of our “restricted subsidiaries” (as defined in the respective indentures governing these notes) (collectively, the “guarantor subsidiaries”). Each guarantor subsidiary is a direct or indirect wholly-owned subsidiary.

 

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Set forth below are condensed consolidating financial statements of the parent, guarantor subsidiaries and Chesapeake Energy Marketing, Inc., a wholly-owned subsidiary which is not a guarantor of the senior notes and was a non-guarantor subsidiary for all periods presented. All of our other wholly-owned subsidiaries were guarantor subsidiaries during all periods presented.

 

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CONDENSED CONSOLIDATED BALANCE SHEET

AS OF JUNE 30, 2003

($ in thousands)

 

    

Guarantor

Subsidiaries


   

Non-Guarantor

Subsidiary


    Parent

    Eliminations

    Consolidated

 

ASSETS

                                        

CURRENT ASSETS:

                                        

Cash and cash equivalents

   $ (493 )   $ 36,361     $ 41     $ —       $ 35,909  

Accounts receivable

     194,334       133,415       11,837       (92,660 )     246,926  

Short-term derivative receivable

     342       —         —         —         342  

Short-term derivative instruments

     31,331       —         —         —         31,331  

Deferred income tax asset

     —         —         6,479       —         6,479  

Inventory and other

     10,724       1,746       10       —         12,480  
    


 


 


 


 


Total Current Assets

     236,238       171,522       18,367       (92,660 )     333,467  
    


 


 


 


 


PROPERTY AND EQUIPMENT:

                                        

Evaluated oil and gas properties

     5,575,048       —         —         —         5,575,048  

Unevaluated properties

     177,837       —         —         —         177,837  

Other property and equipment

     70,083       35,078       70,656       —         175,817  

Less: accumulated depreciation, depletion and amortization

     (2,306,654 )     (21,910 )     (4,972 )     —         (2,333,536 )
    


 


 


 


 


Net Property and Equipment

     3,516,314       13,168       65,684       —         3,595,166  
    


 


 


 


 


OTHER ASSETS:

                                        

Investments in subsidiaries and intercompany advances

     —         —         718,661       (718,661 )     —    

Long-term derivative instruments

     24,873       —         —         —         24,873  

Long-term investments

     —         —         29,075       —         29,075  

Other assets

     9,141       24       21,638       (24 )     30,779  
    


 


 


 


 


Total Other Assets

     34,014       24       769,374       (718,685 )     84,727  
    


 


 


 


 


TOTAL ASSETS

   $ 3,786,566     $ 184,714     $ 853,425     $ (811,345 )   $ 4,013,360  
    


 


 


 


 


LIABILITIES AND STOCKHOLDERS’ EQUITY

                                        

CURRENT LIABILITIES:

                                        

Accounts payable

   $ 134,220     $ 130,846     $ —       $ (136,487 )   $ 128,579  

Accrued interest

     —         —         47,787       —         47,787  

Other accrued liabilities

     66,750       2,922       13,708       285       83,665  

Short-term derivative instruments

     4,606       —         37,778       —         42,384  

Derivative payable

     2,296       —         —         —         2,296  

Revenues and royalties due others

     67,333       —         —         43,827         111,160  
    


 


 


 


 


Total Current Liabilities

     275,205       133,768       99,273       (92,375 )     415,871  
    


 


 


 


 


OTHER LIABILITIES:

                                        

Long-term debt, net

     26,000       —         1,942,447       —         1,968,447  

Revenues and royalties due others

     14,882       —         —         —         14,882  

Long-term derivative instruments

     3,442       —         —         —         3,442  

Asset retirement obligation

     44,699       —         —         —         44,699  

Other liabilities

     9,153       1,326       —         —         10,479  

Deferred income tax liability (asset)

     192,450       2,888       (103,270 )     —         92,068  

Intercompany payables (receivables)

     2,549,075       (269 )     (2,548,497 )     (309 )     —    
    


 


 


 


 


Total Other Liabilities

     2,839,701       3,945       (709,320 )     (309 )     2,134,017  
    


 


 


 


 


STOCKHOLDERS’ EQUITY:

                                        

Common stock

     56       1       2,209       (57 )     2,209  

Preferred stock

     —         —         379,900       —         379,900  

Other

     671,604       47,000       1,081,363       (718,604 )     1,081,363  
    


 


 


 


 


Total Stockholders’ Equity

     671,660       47,001       1,463,472       (718,661 )     1,463,472  
    


 


 


 


 


TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY

   $ 3,786,566     $ 184,714     $ 853,425     $ (811,345 )   $ 4,013,360  
    


 


 


 


 


 

 

17


Table of Contents

CONDENSED CONSOLIDATED BALANCE SHEET

AS OF DECEMBER 31, 2002

($ in thousands)

 

    

Guarantor

Subsidiary


   

Non-

Guarantor

Subsidiary


    Parent

    Eliminations

    Consolidated

 

ASSETS

                                        

CURRENT ASSETS:

                                        

Cash and cash equivalents, including restricted cash

   $ (31,893 )   $ 24,448     $ 255,164     $ —       $ 247,719  

Accounts receivable

     122,074       69,362       3,006       (46,810 )     147,632  

Short-term derivative receivable

     16,498       —         —         —         16,498  

Deferred income tax asset

     —         —         8,109       —         8,109  

Inventory and other

     14,202       1,157       —         —         15,359  
    


 


 


 


 


Total Current Assets

     120,881       94,967       266,279       (46,810 )     435,317  
    


 


 


 


 


PROPERTY AND EQUIPMENT:

                                        

Evaluated oil and gas properties

     4,334,833       —         —         —         4,334,833  

Unevaluated properties

     72,506       —         —         —         72,506  

Other property and equipment

     64,475       30,818       58,799       —         154,092  

Less: accumulated depreciation, depletion and amortization

     (2,146,538 )     (20,789 )     (4,220 )     —         (2,171,547 )
    


 


 


 


 


Net Property and Equipment

     2,325,276       10,029       54,579       —         2,389,884  
    


 


 


 


 


OTHER ASSETS:

                                        

Investments in subsidiaries and intercompany advances

     —         —         357,698       (357,698 )     —    

Deferred income tax asset (liability)

     (124,455 )     (1,941 )     128,467       —         2,071  

Long-term derivative instruments

     2,666       —         —         —         2,666  

Long-term investments

     —         —         9,075       —         9,075  

Other assets

     20,246       57       16,349       (57 )     36,595  
    


 


 


 


 


Total Other Assets

     (101,543 )     (1,884 )     511,589       (357,755 )     50,407  
    


 


 


 


 


TOTAL ASSETS

   $ 2,344,614     $ 103,112     $ 832,447     $ (404,565 )   $ 2,875,608  
    


 


 


 


 


LIABILITIES AND STOCKHOLDERS’ EQUITY

                                        

CURRENT LIABILITIES:

                                        

Accounts payable

   $ 82,083     $ 71,316     $ —       $ (67,398 )   $ 86,001  

Accrued interest

     —         —         35,025       —         35,025  

Other accrued liabilities

     46,231       1,960       8,326       (52 )     56,465  

Short-term derivative instruments

     33,697       —         —         —         33,697  

Revenues and royalties due others

     33,776       —         —         20,588       54,364  
    


 


 


 


 


Total Current Liabilities

     195,787       73,276       43,351       (46,862 )     265,552  
    


 


 


 


 


OTHER LIABILITIES:

                                        

Long-term debt, net

     —         —         1,651,198       —         1,651,198  

Revenues and royalties due others

     13,797       —         —         —         13,797  

Long-term derivative instruments

     —         —         30,174       —         30,174  

Other liabilities

     5,687       1,325       —         —         7,012  

Intercompany payables (receivable)

     1,801,833       (1,677 )     (1,800,151 )     (5 )     —    
    


 


 


 


 


Total Other Liabilities

     1,821,317       (352 )     (118,779 )     (5 )     1,702,181  
    


 


 


 


 


STOCKHOLDERS’ EQUITY:

                                        

Common stock

     56       1       1,949       (57 )     1,949  

Preferred stock

     —         —         149,900       —         149,900  

Other

     327,454       30,187       756,026       (357,641 )     756,026  
    


 


 


 


 


Total Stockholders’ Equity

     327,510       30,188       907,875       (357,698 )     907,875  
    


 


 


 


 


TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY

   $ 2,344,614     $ 103,112     $ 832,447     $ (404,565 )   $ 2,875,608  
    


 


 


 


 


 

 

18


Table of Contents

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

($ in thousands)

 

    

Guarantor

Subsidiaries


   

Non-

Guarantor

Subsidiary


   Parent

    Eliminations

    Consolidated

 

For the Three Months Ended June 30, 2003 (Revised—Note 11):

                                       

REVENUES:

                                       

Oil and gas sales

   $ 319,519     $ —      $ —       $ —       $ 319,519  

Oil and gas marketing sales

     —         336,392      —         (226,096 )     110,296  
    


 

  


 


 


Total Revenues

     319,519       336,392      —         (226,096 )     429,815  
    


 

  


 


 


OPERATING COSTS:

                                       

Production expenses

     34,263       —        —         —         34,263  

Production taxes

     17,101       —        —         —         17,101  

General and administrative

     4,762       661      577       —         6,000  

Oil and gas marketing expenses

     —         332,953      —         (226,096 )     106,857  

Oil and gas depreciation, depletion and amortization

     91,570       —        —         —         91,570  

Depreciation and amortization of other assets

     2,469       595      1,058       —         4,122  
    


 

  


 


 


Total Operating Costs

     150,165       334,209      1,635       (226,096 )     259,913  
    


 

  


 


 


INCOME (LOSS) FROM OPERATIONS

     169,354       2,183      (1,635 )     —         169,902  
    


 

  


 


 


OTHER INCOME (EXPENSE):

                                       

Interest and other income

     (20 )     372      41,080       (40,651 )     781  

Interest expense

     (38,111 )     —        (40,576 )     40,651       (38,036 )

Equity in net earnings of subsidiaries

     —         —        82,942       (82,942 )     —    
    


 

  


 


 


Total Other Income (Expense)

     (38,131 )     372      83,446       (82,942 )     (37,255 )
    


 

  


 


 


INCOME (LOSS) BEFORE INCOME TAXES

     131,223       2,555      81,811       (82,942 )     132,647  

Income tax expense (benefit)

     49,865       971      (429 )     —         50,407  
    


 

  


 


 


NET INCOME (LOSS)

   $ 81,358     $ 1,584    $ 82,240     $ (82,942 )   $ 82,240  
    


 

  


 


 


 

    

Guarantor

Subsidiaries


   

Non-

Guarantor

Subsidiary


    Parent

    Eliminations

    Consolidated

 

For the Three Months Ended June 30, 2002 (Revised—Note 11):

                                        

REVENUES:

                                        

Oil and gas sales

   $ 150,905     $ —       $ —       $ —       $ 150,905  

Oil and gas marketing sales

     —         138,964       —         (96,179 )     42,785  
    


 


 


 


 


Total Revenues

     150,905       138,964       —         (96,179 )     193,690  
    


 


 


 


 


OPERATING COSTS:

                                        

Production expenses

     24,242       —         —         —         24,242  

Production taxes

     7,911       —         —         —         7,911  

General and administrative

     3,365       441       53       —         3,859  

Oil and gas marketing expenses

     —         137,360       —         (96,179 )     41,181  

Oil and gas depreciation, depletion and amortization

     50,778       —         —         —         50,778  

Other depreciation and amortization

     2,484       493       675       —         3,652  
    


 


 


 


 


Total Operating Costs

     88,780       138,294       728       (96,179 )     131,623  
    


 


 


 


 


INCOME (LOSS) FROM OPERATIONS

     62,125       670       (728 )     —         62,067  
    


 


 


 


 


OTHER INCOME (EXPENSE):

                                        

Interest and other income

     943       112       29,975       (27,038 )     3,992  

Interest expense

     (26,061 )     (8 )     (25,036 )     27,038       (24,067 )

Loss on repurchases of Chesapeake debt

     —         —         (273 )     —         (273 )

Equity in net earnings of subsidiaries

     —         —         22,670       (22,670 )     —    
    


 


 


 


 


Total Other Income (Expense)

     (25,118 )     104       27,336       (22,670 )     (20,348 )
    


 


 


 


 


INCOME BEFORE INCOME TAXES

     37,007       774       26,608       (22,670 )     41,719  

Income tax expense

     14,802       309       1,575       —         16,686  
    


 


 


 


 


NET INCOME

   $ 22,205     $ 465     $ 25,033     $ (22,670 )   $ 25,033  
    


 


 


 


 


 

 

19


Table of Contents

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

($ in thousands)

 

    

Guarantor

Subsidiaries


   

Non-

Guarantor

Subsidiary


    Parent

    Eliminations

    Consolidated

 

For the Six Months Ended June 30, 2003 (Revised—Note 11):

                                        

REVENUES:

                                        

Oil and gas sales

   $ 605,538     $ —       $ —       $ —       $ 605,538  

Oil and gas marketing sales

     —         630,543       —         (429,939 )     200,604  
    


 


 


 


 


Total Revenues

     605,538       630,543       —         (429,939 )     806,142  
    


 


 


 


 


OPERATING COSTS:

                                        

Production expenses

     65,720       —         —         —         65,720  

Production taxes

     35,698       —         —         —         35,698  

General and administrative

     9,709       1,244       712       —         11,665  

Oil and gas marketing expenses

     —         626,154       —         (429,939 )     196,215  

Oil and gas depreciation, depletion and amortization

     168,184       —         —         —         168,184  

Depreciation and amortization of other assets

     4,767       1,120       1,919       —         7,806  
    


 


 


 


 


Total Operating Costs

     284,078       628,518       2,631       (429,939 )     485,288  
    


 


 


 


 


INCOME (LOSS) FROM OPERATIONS

     321,460       2,025       (2,631 )     —         320,854  
    


 


 


 


 


OTHER INCOME (EXPENSE):

                                        

Interest and other income

     (2 )     466       76,745       (75,665 )     1,544  

Interest expense

     (71,945 )     —         (78,760 )     75,665       (75,040 )

Equity in net earnings of subsidiaries

     —         —         158,630       (158,630 )     —    
    


 


 


 


 


Total Other Income (Expense)

     (71,947 )     466       156,615       (158,630 )     (73,496 )
    


 


 


 


 


INCOME (LOSS) BEFORE INCOME TAXES AND CUMULATIVE EFFECT OF ACCOUNTING CHANGE

     249,513       2,491       153,984       (158,630 )     247,358  

Income tax expense (benefit)

     94,816       947       (1,765 )     —         93,998  
    


 


 


 


 


INCOME (LOSS) BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE

     154,697       1,544       155,749       (158,630 )     153,360  

Cumulative effect of accounting change, net of tax

     2,389       —         —         —         2,389  
    


 


 


 


 


NET INCOME (LOSS)

   $ 157,086     $ 1,544     $ 155,749     $ (158,630 )   $ 155,749  
    


 


 


 


 


    

Guarantor

Subsidiaries


   

Non-

Guarantor

Subsidiary


    Parent

    Eliminations

    Consolidated

 

For the Six Months Ended June 30, 2002 (Revised—Note 11):

                                        

REVENUES:

                                        

Oil and gas sales

   $ 213,561     $ —       $ —       $ —       $ 213,561  

Oil and gas marketing sales

     —         228,429       —         (158,311 )     70,118  
    


 


 


 


 


Total Revenues

     213,561       228,429       —         (158,311 )     283,679  
    


 


 


 


 


OPERATING COSTS:

                                        

Production expenses

     46,302       —         —         —         46,302  

Production taxes

     13,127       —         —         —         13,127  

General and administrative

     6,995       892       266       —         8,153  

Oil and gas marketing expenses

     —         225,999       —         (158,311 )     67,688  

Oil and gas depreciation, depletion and amortization

     99,397       —         —         —         99,397  

Other depreciation and amortization

     4,655       770       1,337       —         6,762  
    


 


 


 


 


Total Operating Costs

     170,476       227,661       1,603       (158,311 )     241,429  
    


 


 


 


 


INCOME (LOSS) FROM OPERATIONS

     43,085       768       (1,603 )     —         42,250  
    


 


 


 


 


OTHER INCOME (EXPENSE):

                                        

Interest and other income

     1,152       211       58,681       (54,507 )     5,537  

Interest expense

     (52,630 )     (8 )     (53,049 )     54,507       (51,180 )

Loss on repurchases of Chesapeake debt

     —         —         (864 )     —         (864 )

Equity in net earnings of subsidiaries

     —         —         (4,452 )     4,452       —    
    


 


 


 


 


Total Other Income (Expense)

     (51,478 )     203       316       4,452       (46,507 )
    


 


 


 


 


INCOME (LOSS) BEFORE INCOME TAXES

     (8,393 )     971       (1,287 )     4,452       (4,257 )

Income tax expense (benefit)

     (3,358 )     388       1,266       —         (1,704 )
    


 


 


 


 


NET INCOME (LOSS)

   $ (5,035 )   $ 583     $ (2,553 )   $ 4,452     $ (2,553 )
    


 


 


 


 


 

 

20


Table of Contents

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

($ in thousands)

 

    

Guarantor

Subsidiaries


   

Non-Guarantor

Subsidiary


    Parent

    Eliminations

    Consolidated

 

For the Six Months Ended June 30, 2003:

                                        

CASH FLOWS FROM OPERATING ACTIVITIES

   $ 490,841     $ (119,599 )   $ 164,021     $ (158,630 )   $ 376,633  
    


 


 


 


 


CASH FLOWS FROM INVESTING ACTIVITIES:

                                        

Oil and gas properties, net

     (343,997 )     —         (929,598 )     —         (1,273,595 )

Investment in Pioneer Drilling Company

     —         —         (20,000 )     —         (20,000 )

Other

     (6,062 )     (4,260 )     (11,857 )     —         (22,179 )
    


 


 


 


 


Cash (used in) provided by investing activities

     (350,059 )     (4,260 )     (961,455 )     —         (1,315,774 )
    


 


 


 


 


CASH FLOWS FROM FINANCING ACTIVITIES:

                                        

Proceeds from long-term borrowings

     296,000       —               —         296,000  

Payments on long-term borrowings

     (270,000 )     —               —         (270,000 )

Net increase in outstanding payments in excess of cash balances

     29,474       —               —         29,474  

Cash received from issuance of senior notes

     —         —         297,306       —         297,306  

Cash paid for issuance costs of senior notes

     —         —         (6,367 )     —         (6,367 )

Cash paid for treasury stocks

     —         —         (2,109 )     —         (2,109 )

Proceeds from issuance of common stock, net of issuance costs

     —         —         177,444       —         177,444  

Proceeds from issuance of preferred stock, net of issuance costs

     —         —         222,893       —         222,893  

Cash dividends paid on preferred stock and common stock

     —         —         (21,018 )     —         (21,018 )

Exercise of stock options and warrants

     —         —         6,326       —         6,326  

Other

     (2,314 )     —         (222 )     —         (2,536 )

Intercompany advances, net

     (162,460 )     135,772       (131,942 )     158,630       —    
    


 


 


 


 


Cash provided by (used in) financing activities

     (109,300 )     135,772       542,311       158,630       727,413  
    


 


 


 


 


NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS

     31,482       11,913       (255,123 )     —         (211,728 )

CASH, BEGINNING OF PERIOD

     (31,975 )     24,448       255,164       —         247,637  
    


 


 


 


 


CASH, END OF PERIOD

   $ (493 )   $ 36,361     $ 41     $ —       $ 35,909  
    


 


 


 


 


 

    

Guarantor

Subsidiaries


   

Non-Guarantor

Subsidiary


    Parent

    Eliminations

    Consolidated

 

For the Six Months Ended June 30, 2002:

                                        

CASH FLOWS FROM OPERATING ACTIVITIES

   $ 213,415     $ (13,657 )   $ 10,615     $ 4,452     $ 214,825  
    


 


 


 


 


CASH FLOWS FROM INVESTING ACTIVITIES:

                                        

Oil and gas properties, net

     (180,545 )     —         (127,251 )     —         (307,796 )

Additions to other property, plant and equipment and other

     (6,499 )     (3,408 )     (8,676 )     —         (18,583 )

Other investments, net

     —         —         1,807       —         1,807  
    


 


 


 


 


Cash (used in) provided by investing activities

     (187,044 )     (3,408 )     (134,120 )     —         (324,572 )
    


 


 


 


 


CASH FLOWS FROM FINANCING ACTIVITIES:

                                        

Proceeds from long-term borrowings

     45,000       —         —         —         45,000  

Cash paid for issuance costs of senior notes

     —         —         (95 )     —         (95 )

Cash paid for repurchase of senior notes

     —         —         (42,201 )     —         (42,201 )

Cash paid for repurchase premium on senior notes

     —         —         (1,019 )     —         (1,019 )

Cash dividends paid on preferred stock

     —         —         (5,118 )     —         (5,118 )

Exercise of stock options

     —         —         1,956       —         1,956  

Other

     —         —         (74 )     —         (74 )

Intercompany advances, net

     (59,807 )     3,394       60,865       (4,452 )     —    
    


 


 


 


 


Cash (used in) provided by financing activities

     (14,807 )     3,394       14,314       (4,452 )     (1,551 )
    


 


 


 


 


NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS

     11,564       (13,671 )     (109,191 )     —         (111,298 )

CASH, BEGINNING OF PERIOD

     (11,313 )     19,714       109,193       —         117,594  
    


 


 


 


 


CASH, END OF PERIOD

   $ 251     $ 6,043     $ 2     $ —       $ 6,296  
    


 


 


 


 


 

 

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CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

($ in thousands)

 

    

Guarantor

Subsidiaries


   

Non-Guarantor

Subsidiary


   Parent

   Eliminations

    Consolidated

 

For the Three Months Ended June 30, 2003:

                                      

Net income (loss)

   $ 81,358     $ 1,584    $ 82,240    $ (82,942 )   $ 82,240  

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

                                      

Change in fair value of derivative instruments

     11,696       —        —        —         11,696  

Reclassification of loss on settled contracts

     2,461       —        —        —         2,461  

Ineffectiveness portion of derivatives qualifying for cash flow hedge accounting

     (256 )     —        —        —         (256 )

Equity in net other comprehensive income (loss) of subsidiaries

     —         —        13,901      (13,901 )     —    
    


 

  

  


 


Comprehensive income (loss)

   $ 95,259     $ 1,584    $ 96,141    $ (96,843 )   $ 96,141  
    


 

  

  


 


 

    

Guarantor

Subsidiaries


   

Non-Guarantor

Subsidiary


   Parent

    Eliminations

    Consolidated

 

For the Three Months Ended June 30, 2002:

                                       

Net income

   $ 22,205     $ 465    $ 25,033     $ (22,670 )   $ 25,033  

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

                                       

Change in fair value of derivative instruments

     (2,242 )     —        —         —         (2,242 )

Reclassification of gain on settled contracts

     (1,683 )     —        —         —         (1,683 )

Ineffective portion of derivatives qualifying for cash flow hedge accounting

     815       —        —         —         815  

Equity in net other comprehensive income (loss) of subsidiaries

     —         —        (3,110 )     3,110       —    
    


 

  


 


 


Comprehensive income (loss)

   $ 19,095     $ 465    $ 21,923     $ (19,560 )   $ 21,923  
    


 

  


 


 


 

    

Guarantor

Subsidiaries


   

Non-Guarantor

Subsidiary


   Parent

   Eliminations

    Consolidated

 

For the Six Months Ended June 30, 2003:

                                      

Net income (loss)

   $ 157,086     $ 1,544    $ 155,749    $ (158,630 )   $ 155,749  

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

                                      

Change in fair value of derivative instruments

     (36,859 )     —        —        —         (36,859 )

Reclassification of loss on settled contracts

     53,352       —        —        —         53,352  

Ineffectiveness portion of derivatives qualifying for cash flow hedge accounting

     (286 )     —        —        —         (286 )

Equity in net other comprehensive income (loss) of subsidiaries

     —         —        16,207      (16,207 )     —    
    


 

  

  


 


Comprehensive income (loss)

   $ 173,293     $ 1,544    $ 171,956    $ (174,837 )   $ 171,956  
    


 

  

  


 


 

    

Guarantor

Subsidiaries


   

Non-Guarantor

Subsidiary


   Parent

    Eliminations

   Consolidated

 

For the Six Months Ended June 30, 2002:

                                      

Net income (loss)

   $ (5,035 )   $ 583    $ (2,553 )   $ 4,452    $ (2,553 )

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

                                      

Change in fair value of derivative instruments

     (12,972 )     —        —         —        (12,972 )

Reclassification of gain on settled contracts

     (15,769 )     —        —         —        (15,769 )

Ineffective portion of derivatives qualifying for cash flow hedge accounting

     1,309       —        —         —        1,309  

Equity in net other comprehensive income (loss) of subsidiaries

     —         —        (27,432 )     27,432      —    
    


 

  


 

  


Comprehensive income (loss)

   $ (32,467 )   $ 583    $ (29,985 )   $ 31,884    $ (29,985 )
    


 

  


 

  


 

 

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6. Segment Information

 

Chesapeake has two reportable segments under SFAS No. 131, Disclosures about Segments of an Enterprise and Related Information, consisting of exploration and production, and marketing. The reportable segment information can be derived from Note 5 as Chesapeake Energy Marketing, Inc., which is our marketing segment, is the only non-guarantor subsidiary for all income statement periods presented.

 

7. Recent Accounting Pronouncements

 

During 2002 and 2003, the Financial Accounting Standards Board issued the following Statements of Financial Accounting Standards which were reviewed by Chesapeake to determine the potential impact on our financial statements upon adoption.

 

In July 2002, the FASB issued SFAS No. 146, Accounting For Costs Associated with Exit or Disposal Activities. SFAS 146 is effective for exit or disposal activities initiated after December 31, 2002. We adopted this standard during the quarter ended March 31, 2003 and it did not have any impact on our financial position or results of operations.

 

In March 2003, the FASB issued SFAS No. 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities. SFAS 149 is effective for contracts entered into or modified after June 30, 2003. This statement amends and clarifies financial accounting and reporting for derivative instruments, including certain derivative instruments embedded in other contracts (collectively referred to as derivatives) and for hedging activities under SFAS 133, Accounting for Derivative Instruments and Hedging Activities. We do not expect the adoption of this standard to have any significant impact on our financial position or results of operations.

 

In May 2003, the FASB issued SFAS No. 150, Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity. SFAS 150 is effective for financial instruments entered into or modified after May 31, 2003 and otherwise is effective at the beginning of the first interim period beginning after June 15, 2003. This statement establishes new standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. SFAS 150 requires that an issuer classify a financial instrument that is within the scope of this statement as a liability because the financial instrument embodies an obligation of the issuer. This statement applies to certain forms of mandatorily redeemable financial instruments including certain types of preferred stock, written put options and forward contracts. We do not expect the adoption of this standard to have a significant impact on our financial position or results of operations.

 

8. Asset Retirement Obligations

 

Effective January 1, 2003, Chesapeake adopted SFAS No. 143, Accounting for Asset Retirement Obligations. This statement applies to obligations associated with the retirement of tangible long-lived assets that result from the acquisition, construction and development of the assets.

 

SFAS 143 requires that the fair value of a liability for a retirement obligation be recognized in the period in which the liability is incurred. For oil and gas properties, this is the period in which an oil or gas well is acquired or drilled. The asset retirement obligation is capitalized as part of the carrying amount of our oil and gas properties at its discounted fair value. The liability is then accreted each period until the liability is settled or the well is sold, at which time the liability is reversed and any gain or loss resulting from the settlement of the obligation is recorded.

 

We identified and estimated all of our asset retirement obligations for tangible, long-lived assets as of January 1, 2003. These obligations were for plugging and abandonment costs for depleted oil and gas wells. Prior to the adoption of SFAS 143, we included an estimate of our asset retirement obligations related to our oil and gas properties in our calculation of oil and gas depreciation, depletion and amortization expense. Upon adoption of SFAS 143, we recorded the discounted fair value of our expected future obligations. During the quarter ended March 31, 2003, we recorded a $30.5 million liability, a cumulative effect for the change in accounting principle as an increase to earnings of $2.4 million (net of income taxes) and an increase in net oil and gas properties of $34.3 million. The pro-forma effect on prior periods’ financial position and results of operations was not material.

 

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Table of Contents

The components of the change in our asset retirement obligations are shown below.

 

    

Three
Months

Ended

June 30, 2003


   

Six

Months

Ended

June 30, 2003


 

Asset retirement obligations, beginning balance

   $ 46,438     $ 30,479  

Additions and revisions

     1,246       16,543  

Settlements and disposals

     (3,771 )     (3,771 )

Accretion expense

     786       1,448  
    


 


Asset retirement obligations, ending balance

   $ 44,699     $ 44,699  
    


 


 

9. Acquisitions and Related Financing

 

We completed an acquisition of Mid-Continent gas assets from a wholly-owned subsidiary of ONEOK, Inc. in January 2003 for $296 million, $15 million of which was paid in 2002. In March 2003, we acquired El Paso Corporation’s Anadarko Basin assets in western Oklahoma and the Texas Panhandle for $500 million and Vintage Petroleum, Inc.’s assets in the Bray Field in southern Oklahoma for $29 million. We also completed an acquisition of privately-owned Oxley Petroleum Company for $155 million on May 31, 2003.

 

In March 2003, Chesapeake bought 5.3 million newly issued common shares of Pioneer Drilling Company, or 24.6% of its outstanding common shares, at $3.75 per share, for a total investment of $20 million.

 

On March 5, 2003, we issued 23 million shares of common stock pursuant to a shelf registration statement for net proceeds of $177.4 million. We also issued 4.6 million shares of 6.00% cumulative convertible preferred stock with a liquidation value of $230 million. The net proceeds from the preferred stock were $222.9 million. These proceeds, along with the net proceeds of $290.9 million from the issuance of the $300 million in aggregate principal amount of 7.50% senior notes issued at the same time, were used to fund acquisitions completed in March 2003 and to repay credit facility indebtedness. Each share of the 6.00% preferred stock is convertible at any time at the option of the holder into 4.8605 shares of our common stock, subject to adjustment. At June 30, 2003, 41.8 million shares of our common stock were reserved for issuance upon conversion of the 6.00% and 6.75% cumulative convertible preferred stock.

 

10. Subsequent Events

 

On July 16, 2003, we issued an additional $29.5 million of our 7.75% senior notes due 2015 in exchange for $27.9 million of our 8.375% senior notes due 2008 and $0.5 million of accrued interest, pursuant to a privately negotiated transaction. The $27.9 million of 8.375% senior notes due 2008 were retired upon receipt.

 

On July 31, 2003, Chesapeake purchased oil and gas properties, a gathering system and a gas treatment plant from a major oil and gas company for $44.5 million.

 

On August 5, 2003, we issued an additional $33.5 million of our 7.75% senior notes due 2015 in exchange for $32.0 million of our 8.5% senior notes due 2012 and $1.1 million of accrued interest, pursuant to a privately negotiated transaction. The $32.0 million of 8.5% senior notes were retired upon receipt.

 

On August 13, 2003, we entered into an interest rate swap. The terms of this swap agreement are as follows:

 

Term


 

Notional Amount


 

Fixed Rate


 

Floating Rate


August 2003—August 2005

  $100,000,000   2.735%   U.S. six-month LIBOR in arrears

 

If the floating rate is less than the fixed rate, the counterparty will pay us accordingly. If the floating rate exceeds the fixed rate, we will pay the counterparty. Payments under this interest rate swap will be made on February 15 and August 15 of each year beginning February 15, 2004.

 

 

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Table of Contents

11. Income Statement Reclassifications

 

We have reclassified certain amounts in our previously reported condensed consolidated financial statements for the three and six months ended June 30, 2003 and 2002. These reclassifications had no effect on previously reported net income or net income per share.

 

For the three and six months ended June 30, 2003 and 2002, Chesapeake has reclassified unrealized gains and losses on certain derivative instruments. Previously, gains (losses) resulting from ineffectiveness of oil and gas derivative contracts designated as cash flow hedges, as well as the net unrealized gains and losses related to oil and gas derivative contracts not qualifying for hedge accounting under SFAS 133, were separately classified as “risk management income (loss)”. These amounts have been reclassified and are now included in “oil and gas sales” for the three and six months ended June 30, 2003 and 2002. For the three and six months ended June 30, 2003 and 2002 we have also reclassified to interest expense ineffectiveness related to the fair value of derivatives designated as hedges, as well as the amortization of realized gains and losses on interest rate derivative instruments that were previously reported as risk management income (loss).

 

The effects of these reclassifications on the condensed consolidated statements of operations previously reported for the three and six months ended June 30, 2003 and 2002 are presented below.

 

     Three Months Ended June 30,

 
     2003

    2002

 
     As
Previously
Reported


    As
Revised


    As
Previously
Reported


    As
Revised


 
     ($ in thousands, except per share data)  

REVENUES:

                                

Oil and gas sales

   $ 316,172     $ 319,519     $ 152,009     $ 150,905  

Risk management income (loss)

     3,084       —         (481 )     —    

Oil and gas marketing sales

     110,296       110,296       42,785       42,785  
    


 


 


 


Total Revenues

     429,552       429,815       194,313       193,690  
    


 


 


 


OPERATING COSTS

     259,913       259,913       131,623       131,623  
    


 


 


 


INCOME FROM OPERATIONS

     169,639       169,902       62,690       62,067  
    


 


 


 


OTHER INCOME (EXPENSE):

                                

Interest and other income

     781       781       3,992       3,992  

Interest expense

     (37,773 )     (38,036 )     (24,690 )     (24,067 )

Loss on repurchases of Chesapeake debt

     —         —         (273 )     (273 )
    


 


 


 


Total Other Income (Expense)

     (36,992 )     (37,255 )     (20,971 )     (20,348 )
    


 


 


 


INCOME (LOSS) BEFORE INCOME TAXES AND CUMULATIVE EFFECT OF ACCOUNTING CHANGE

     132,647       132,647       41,719       41,719  

INCOME TAX EXPENSE (BENEFIT):

                                

Current

     —         —         —         —    

Deferred

     50,407       50,407       16,686       16,686