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 June 30, 2002 [ ] 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 (I.R.S. Employer incorporation or organization) Identification No.) 6100 NORTH WESTERN AVENUE 73118 OKLAHOMA CITY, OKLAHOMA (Zip Code) (Address of principal executive offices) (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 [ ] At July 31, 2002, there were 166,122,358 shares of our $.01 par value common stock outstanding.
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES INDEX TO FORM 10-Q FOR THE QUARTER ENDED JUNE 30, 2002
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (UNAUDITED)
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (UNAUDITED)
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS JUNE 30, 2002 (UNAUDITED) 1. BASIS OF PRESENTATION AND 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, 2002 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, 2001 (the "Prior Quarter" and "Prior Period", respectively) and the three and six months ended June 30, 2002 (the "Current Quarter" and "Current Period", respectively). 2. HEDGING ACTIVITIES AND FINANCIAL INSTRUMENTS 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, 2002, our derivative instruments were comprised of swaps, collars, cap-swaps, straddles, strangles 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, our derivative instruments continue to be highly effective in achieving the risk management objectives for which they were intended. o 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. o 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, then we receive the fixed price and pay the market price. If the market price is between the call and the put strike price, then no payments are due from either party. o For cap-swaps, we receive a fixed price for the hedged commodity and pay a floating market price. The fixed price received by Chesapeake includes a premium in exchange for a "cap" limiting the counterparty's exposure. o For straddles, Chesapeake receives a premium from the counterparty in exchange for the sale of a call and a put option at an established fixed price. To the extent that the floating market price differs from the established fixed price, Chesapeake pays the counterparty. o For strangles, Chesapeake receives a premium from the counterparty in exchange for the sale of a call and a put option. If the market price exceeds the fixed price of the call option or falls below the fixed price of the put option, then Chesapeake pays the counterparty. If the market price settles between the fixed price of the call and put option, no payment is due from Chesapeake. o Basis protection swaps are arrangements that guarantee a price differential of oil and 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. 7
From time to time, we close certain swap transactions designed to hedge a portion of our oil and natural gas production by entering into a counter-swap instrument. Under the counter-swap we receive a floating price for the hedged commodity and pay a fixed price to the counterparty. To the extent the counter-swap, which does not qualify for hedge accounting under SFAS 133, is designed to lock the value of an existing SFAS 133 cash flow hedge, the net value of the swap and the counter-swap is frozen and shown as a derivative receivable or payable in the consolidated balance sheets. At the same time, the original swap is designated as a non-qualifying cash flow hedge under SFAS 133. Pursuant to SFAS 133, our cap-swaps, straddles, strangles, counter-swaps and basis protection swaps do not qualify for designation as cash flow hedges. Therefore, changes in the fair value of these instruments that occur prior to their maturity, together with any changes in fair value of cash flow hedges resulting from ineffectiveness, are reported in the consolidated statements of operations as risk management income (loss). Amounts recorded in risk management income (loss) do not represent cash gains or losses. Rather, these amounts are temporary valuation swings in contracts or portions of contracts that are not entitled to receive SFAS 133 cash flow hedge accounting treatment. All amounts initially recorded in this caption related to commodity derivatives are ultimately reversed within this same caption and included in oil and gas sales over the respective contract terms. The estimated fair values of our oil and gas derivative instruments as of June 30, 2002 are provided below. The associated carrying values of these instruments are equal to the estimated fair values.
Risk management income (loss) related to our oil and gas derivatives is comprised of the following ($ in thousands):
In June 2002, we entered into an additional interest rate swap. The terms of this swap agreement are as follows:
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 value amounts by using available market information and valuation methodologies. Considerable judgment is required in interpreting market data to develop the estimates of fair value. The use of different market assumptions or valuation methodologies may have a material effect on the estimated fair value amounts. The carrying values of 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 (including current maturities), fixed-rate debt using primarily quoted market prices. Excluding the impact of our fair value hedges, our carrying amount for such debt at December 31, 2001 and June 30, 2002 was $1,330.1 million and $1,287.9 million, respectively, compared to approximate fair values of $1,343.0 and $1,297.3 million, respectively. The carrying value of other long-term debt, which consists of amounts outstanding under our revolving bank credit facility, approximates its fair value as interest rates on the facility are based on prevailing market rates. The carrying amount for our 6.75% convertible preferred stock at June 30, 2002 was $149.9 million, compared to the approximate fair value of $173.9 million. Concentration of Credit Risk A significant portion of our liquidity is concentrated in cash and cash equivalents, including restricted cash, and derivative instruments that enable us to hedge a portion of our exposure to price volatility from producing oil and natural gas and interest rate volatility. 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 instruments and accounts receivables. 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 concentration of these assets in the oil and gas industry 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 with high credit ratings. 3. CONTINGENCIES AND COMMITMENTS West Panhandle Field Cessation Cases. One of our subsidiaries, Chesapeake Panhandle Limited Partnership ("CP") (f/k/a MC Panhandle, Inc.), and two subsidiaries of Kinder Morgan, Inc. have been defendants in 16 lawsuits filed between June 1997 and December 2001 by royalty owners seeking the cancellation of oil and gas leases in the West Panhandle Field in Texas. MC Panhandle, Inc., which we acquired in April 1998, has owned the leases since January 1, 1997. The co-defendants are prior lessees. The plaintiffs in these cases have claimed the leases terminated upon the cessation of production for various periods, primarily during the 1960s. In addition, the plaintiffs have sought to recover conversion damages, exemplary damages, attorneys' fees and interest. The defendants have asserted that any cessation of production was excused and have pled affirmative defenses of limitations, waiver, temporary estoppel, laches and title by adverse possession. Four of the 16 cases have been tried, and there have been appellate decisions in three of them. In January 2001, we settled the claims of the principal plaintiffs in eight cases tried or pending in the District Court of Moore County, Texas, 69th Judicial District. The settlement was not material to our financial condition or results of operations. In December 2001, the Texas Supreme Court accepted for review petitions we filed with respect to the claims of the non-settling plaintiffs in two of the cases covered by the settlement. The Court heard oral arguments in March 2002 and has not yet issued a decision. There are eight other related West Panhandle cessation cases which are pending, three in the District Court of Moore County, Texas, 69th Judicial District, two in the District Court of Carson County, Texas, 100th Judicial District, and three in the U.S. District Court, Northern District of Texas, Amarillo Division. In one of the Moore County cases, CP and the other defendants have appealed a January 2000 judgment notwithstanding verdict in favor 11
of plaintiffs. In addition to quieting title to the lease (including existing gas wells and all attached equipment) in plaintiffs, the court awarded actual damages against CP in the amount of $716,400 and exemplary damages in the amount of $25,000. The court further awarded, jointly and severally from all defendants, $160,000 in attorneys' fees and interest and court costs. On March 28, 2001, the Amarillo Court of Appeals reversed and rendered judgment in favor of CP and the other defendants, finding that the subject leases had been revived as a matter of law, making all other issues moot. Plaintiffs have filed petitions requesting that the Texas Supreme Court accept the case for review. In another of the Moore County, Texas cases, in June 1999, the court granted plaintiffs' motion for summary judgment in part, finding that the lease had terminated due to the cessation of production, subject to the defendants' affirmative defenses. In February 2001, the court granted plaintiffs' motion for summary judgment on defendants' affirmative defenses but reversed its ruling that the lease had terminated as a matter of law. In one of the U.S. District Court cases, after a trial in May 1999, the jury found plaintiffs' claims were barred by the payment of shut-in royalties, laches and revivor. Plaintiffs have moved for a new trial. There are motions pending in two other cases, and the remaining three cases are in the pleading stage. We have previously established an accrued liability we believe will be sufficient to cover the estimated costs of litigation for each of the pending cases. Because of the inconsistent verdicts reached by the juries in the four cases tried to date and because the amount of damages sought is not specified in all of the pending cases, the outcome of any future trials and the amount of damages that might ultimately be awarded could differ from management's estimates. CP and the other defendants are vigorously defending against the plaintiffs' claims. Royalty. Owner Litigation. Recently royalty owners have commenced litigation against a number of companies in the oil and gas production business claiming that amounts paid for production attributable to the royalty owners' interest violated the terms of the applicable leases and state law, that deductions from the proceeds of oil and gas production were unauthorized under the applicable leases and that amounts received by upstream sellers should be used to compute the amounts paid to the royalty owners. In the course of our oil and gas marketing activities, a portion of the foregoing litigation has been commenced as class action suits including four class action suits filed against Chesapeake and others which we believe do not represent valid claims or, if valid, are not material. As new cases are decided and the law in this area continues to develop, our liability relating to the marketing of oil and gas may increase or decrease. We will continue to monitor the court decisions to ensure that our operations and practices minimize any exposure and to recognize any charges that may be appropriate. 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 the consolidated financial position or results of operations of Chesapeake. 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 is not aware of any potential material environmental issues or claims. 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: o For the Prior Quarter, the Current Quarter, the Prior Period and the Current Period, outstanding warrants to purchase 1.1 million shares of common stock at a weighted average exercise price of $12.61 were antidilutive because the exercise prices of the warrants were greater than the average price of the common stock. o For the Prior Quarter, the Current Quarter, the Prior Period and the Current Period, outstanding options to purchase 0.3 million, 0.3 million, 0.2 million and 0.4 million shares of common stock at a weighted average exercise price of $15.98, $15.30, $18.78 and $14.44, respectively, were antidilutive because the exercise prices of the options were greater than the average market price of the common stock. o As a result of the Current 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 $0.05 as the effects were antidilutive. 12
A reconciliation for the three months ended June 30, 2001 and 2002 and the six months ended June 30, 2001 is as follows:
5. SENIOR NOTES AND REVOLVING CREDIT FACILITY At June 30, 2002, our long-term debt, net of current maturities, consisted of the following ($ in thousands):
CONDENSED CONSOLIDATED BALANCE SHEET AS OF DECEMBER 31, 2001 ($ IN THOUSANDS)
CONDENSED CONSOLIDATED BALANCE SHEET AS OF JUNE 30, 2002 ($ IN THOUSANDS)
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS ($ IN THOUSANDS)
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS ($ IN THOUSANDS)
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS ($ IN THOUSANDS)
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) ($ IN THOUSANDS)
6. SEGMENT INFORMATION Chesapeake has two reportable segments under SFAS No. 131, Disclosures about Segments of an Enterprise and Related Information. One segment relates to our exploration and production activities, and the other segment relates to oil and gas marketing activities. The reportable segment information can be derived from Note 5 as Chesapeake Energy Marketing, Inc., is the only significant non-guarantor subsidiary and the only entity conducting marketing activities for all income statement periods presented. 7. ACQUISITIONS On June 28, 2002, we acquired Canaan Energy Corporation in a cash merger through a Chesapeake subsidiary. Under the agreement, all outstanding common shares of Canaan, other than the Canaan shares already owned by Chesapeake, were purchased at $18.00 per share in cash, and the outstanding options to acquire Canaan common stock were converted into the right to receive, for each share of Canaan common stock to be received upon exercise, the merger consideration less the per share exercise price and withholding taxes. The aggregate net cash consideration for the merger was $120 million, including the retirement of Canaan's outstanding indebtedness of approximately $43 million. 8. RECENT ACCOUNTING PRONOUNCEMENTS In June 2001, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards Nos. 141 and 142. SFAS No. 141, Business Combinations, requires that the purchase method of accounting be used for all business combinations initiated after June 30, 2001. SFAS No. 142, Goodwill and Other Intangible Assets, changes the accounting for goodwill from an amortization method to an impairment-only approach and was effective in January 2002. We have adopted these new standards, which have not had a significant effect on our results of operations or our financial position. In June 2001, the FASB issued SFAS No. 143, Accounting for Asset Retirement Obligations. SFAS No. 143 is effective for fiscal year beginning after June 15, 2002 and establishes an accounting standard requiring the recording of the fair value of liabilities associated with the retirement of long-term assets (mainly plugging and abandonment costs for our depleted wells) in the period in which the liability is incurred (at the time the wells are drilled). We are currently evaluating our oil and natural gas properties to determine the impact of the adoption of SFAS No. 143 or our financial position and results of operations. In August 2001, the FASB issued SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets. SFAS 144 was effective January 1, 2002. This statement supersedes SFAS No. 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of, and amends Accounting Principles Board Opinion No. 30 for the accounting and reporting of discontinued operations, as it relates to long-lived assets. Adoption of SFAS 144 did not affect our financial position or results of operations. In April 2002, the FASB issued SFAS No. 145, Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections. SFAS No. 145 is effective for fiscal years beginning after May 15, 2002. We have not yet adopted SFAS No. 145 nor have we determined the effect of the adoption on our financial position or results of operations. In July 2002, the FASB issued SFAS No. 146, Accounting For Costs Associated with Exit or Disposal Activities. SFAS No. 146 is effective for exit or disposal activities initiated after December 31, 2002. We have not yet adopted SFAS No. 146 nor determined the effect of the adoption of SFAS No. 146 on our financial position or results of operations. 21
PART I. FINANCIAL INFORMATION 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 gas sales, average sales prices received and expenses for the periods indicated:
revenues of $13.4 million, or $0.31 per mcfe, in the Current Quarter, compared to an increase in oil and gas revenues of $7.2 million, or $0.18 per mcfe, in the Prior Quarter. The following table shows our production by region for the Prior Quarter and the Current Quarter:
statutory exemptions on certain wells in Oklahoma and Texas. In general, production taxes are calculated using value-based formulas that produce higher per unit costs when oil and gas prices are higher. We expect production taxes for the remainder of 2002 to be approximately 6% - 7% of oil and gas sales revenues excluding any impact from hedging. General and Administrative. General and administrative expenses, which are net of capitalized internal costs, were $3.9 million in the Current Quarter compared to $2.9 million in the Prior Quarter. The increase in the Current Quarter is the result of Chesapeake's continued growth. 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 acquisition, exploration and development activities and do not include any costs related to production, general corporate overhead or similar activities. We capitalized $2.8 million and $2.1 million of internal costs in the Current Quarter and Prior Quarter, respectively, directly related to our oil and gas exploration and development efforts. We anticipate that general and administrative expenses for the remainder of 2002 will be between $0.10 and $0.11 per mcfe, which is approximately the same level as 2001 and the Current Quarter. Oil and Gas Depreciation, Depletion and Amortization. Depreciation, depletion and amortization of oil and gas properties for the Current Quarter was $50.8 million, compared to $39.9 million in the Prior Quarter. The DD&A rate per mcfe, which is a function of capitalized costs, future development costs and the related underlying reserves in the periods presented, increased from $1.02 in the Prior Quarter to $1.17 per mcfe in the Current Quarter. We expect the DD&A rate for the remainder of 2002 to be between $1.25 and $1.35 per mcfe. Depreciation and Amortization of Other Assets. Depreciation and amortization of other assets was $3.7 million in the Current Quarter, compared to $1.8 million in the Prior Quarter. The increase in the Current Quarter was primarily the result of higher depreciation recorded on recently acquired fixed assets. Other property and equipment costs are depreciated on both straight-line and accelerated methods. Buildings are depreciated on a straight-line basis over 31.5 years. Drilling rigs are depreciated on a straight-line basis over 12 years. All other property and equipment are depreciated over the estimated useful lives of the assets, which range from three to seven years. We expect depreciation and amortization of other assets to average between $0.08 and $0.10 per mcfe for the remainder of 2002 which approximates the current rate. Interest and Other Income. Interest and other income for the Current Quarter was $3.7 million compared to $0.7 million in the Prior Quarter. The increase was primarily the result of additional interest income from significantly higher cash balances held during the Current Quarter, as well as interest income recorded on our investment in senior secured notes issued by Seven Seas Petroleum Inc. Interest Expense. Interest expense increased to $24.7 million in the Current Quarter from $23.0 million in the Prior Quarter. The increase in the Current Quarter was due primarily to a $113 million increase in average long-term borrowings in the Current Quarter compared to the Prior Quarter, partially offset by income of $1.6 million earned on our interest rate swap during the Current Quarter. In addition to the interest expense reported, we capitalized $1.1 million of interest during the Current Quarter, compared to $1.4 million capitalized in the Prior Quarter, on significant investments in unproved properties that were not being currently depreciated, depleted or amortized and on which exploration activities were in progress. Interest is capitalized using the weighted average interest rate of our outstanding borrowings. We anticipate that capitalized interest for the remainder of 2002 will be between $2.0 million and $2.5 million. Provision (Benefit) for Income Taxes. Chesapeake recorded income tax expense of $16.7 million in the Current Quarter, compared to income tax expense of $57.5 million in the Prior Quarter. Income tax expense for the Prior Quarter was comprised of $54.7 million related to our domestic operations and $2.8 million related to our Canadian operations which were sold on October 1, 2001. We anticipate that all 2002 income tax expense will be deferred. 24
RESULTS OF OPERATIONS -- SIX MONTHS ENDED JUNE 30, 2002 ("CURRENT PERIOD") VS. JUNE 30, 2001 ("PRIOR PERIOD") General. For the Current Period, Chesapeake had a net loss available to common shareholders of $7.6 million, or a loss of $0.05 per diluted common share, on total revenues of $284.1 million. This compares to net income available to common shareholders of $109.0 million, or $0.64 per diluted common share, on total revenues of $553.1 million during the Prior Period. The Current Period's net loss included, on a pre-tax basis, a non-cash $79.9 million risk management loss, while the Prior Period's results included, on a pre-tax basis, non-cash risk management income of $62.5 million. Oil and Gas Sales. During the Current Period, oil and gas sales decreased 26% to $294.0 million from $396.4 million in the Prior Period. For the Current Period, we produced 85.3 billion cubic feet equivalent, consisting of 1.7 million barrels of oil and 75.4 billion cubic feet of gas, compared to 1.4 mmbbl and 71.1 bcf, or 79.3 bcfe, in the Prior Period. The production increase is primarily the result of successful drilling results complemented with production from various acquisitions which occurred in late 2001, partially offset by the sale of our Canadian reserves effective October 1, 2001. Average oil prices realized were $25.29 per bbl in the Current Period compared to $28.36 per bbl in the Prior Period, a decrease of 11%. Average gas prices realized were $3.34 per thousand cubic feet in the Current Period compared to $5.03 per mcf in the Prior Period, a decrease of 34%. For the Current Period, we realized an average price of $3.45 per mcfe, compared to $5.00 per mcfe in the Prior Period, including in each case the effects of hedging. Our hedging activities resulted in increased oil and gas revenues of $62.0 million, or $0.73 per mcfe, in the Current Period, compared to decreases in oil and gas revenues of $23.3 million, or $0.29 per mcfe, in the Prior Period. The following table shows our production by region for the Prior Period and the Current Period:
applicable, over the respective contract terms. Detailed information about our oil and gas hedging positions appears in Item 3 - Quantitative and Qualitative Disclosures About Market Risk. Oil and Gas Marketing Sales. We generated $70.1 million in oil and gas marketing sales for third parties in the Current Period, with corresponding oil and gas marketing expenses of $67.7 million, for a net margin of $2.4 million. This compares to sales of $94.2 million, expenses of $91.4 million, and a net margin of $2.8 million in the Prior Period. The decrease in marketing sales and cost of sales was due primarily to a decrease in oil and gas prices in the Current Period compared to the Prior Period, partially offset by an increase in volumes marketed by Chesapeake Energy Marketing, Inc. in the Current Period. Production Expenses. Production expenses, which include lifting costs and ad valorem taxes, increased to $46.3 million in the Current Period, a $9.7 million increase from the $36.6 million of production expenses incurred in the Prior Period. On a unit of production basis, production expenses were $0.54 and $0.46 per mcfe in the Current and Prior Periods, respectively. The increase in costs on a per unit basis in the Current Period is due primarily to increased field service costs, higher production costs associated with properties acquired in 2001 and an increase in ad valorem taxes. We expect that lease operating expenses per mcfe for the remainder of 2002 will range from $0.53 to $0.57. Production Taxes. Production taxes were $13.1 million and $24.3 million in the Current and Prior Periods, respectively. On a per unit basis, production taxes were $0.15 per mcfe in the Current Period compared to $0.31 per mcfe in the Prior Period. The decrease in the Current Period was the result of decreased prices and new statutory exemptions on certain wells in Oklahoma and Texas. In general, production taxes are calculated using value-based formulas that produce higher per unit costs when oil and gas prices are higher. We expect production taxes for the remainder of 2002 to be approximately 6% - 7% of oil and gas sales revenues excluding any impact from hedging. General and Administrative. General and administrative expenses, which are net of capitalized internal costs, were $8.2 million in the Current Period compared to $6.9 million in the Prior Period. The increase in the Current Period is a result of Chesapeake's continued growth. 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 acquisition, exploration and development activities and do not include any costs related to production, general corporate overhead or similar activities. We capitalized $5.3 million and $3.9 million of internal costs in the Current Period and Prior Period, respectively, directly related to our oil and gas exploration and development efforts. We anticipate that general and administrative expenses for the remainder of 2002 will be between $0.10 and $0.11 per mcfe, which is approximately the same level as 2001 and the Current Period. Oil and Gas Depreciation, Depletion and Amortization. Depreciation, depletion and amortization of oil and gas properties for the Current Period was $99.4 million, compared to $78.1 million in the Prior Period. The DD&A rate per mcfe, which is a function of capitalized costs, future development costs and the related underlying reserves in the periods presented, increased from $0.98 in the Prior Period to $1.17 per mcfe in the Current Period. We expect the DD&A rate for the remainder of 2002 to be between $1.25 and $1.35 per mcfe. Depreciation and Amortization of Other Assets. Depreciation and amortization of other assets was $6.8 million in the Current Period, compared to $3.8 million in the Prior Period. The increase in the Current Period was primarily the result of higher depreciation recorded on recently acquired fixed assets. Other property and equipment costs are depreciated on both straight-line and accelerated methods. Buildings are depreciated on a straight-line basis over 31.5 years. Drilling rigs are depreciated on a straight-line basis over 12 years. All other property and equipment are depreciated over the estimated useful lives of the assets, which range from three to seven years. We expect depreciation and amortization of other assets to average between $0.08 and $0.10 per mcfe for the remainder of 2002 which approximates the current rate. Interest and Other Income. Interest and other income for the Current Period was $4.7 million compared to $1.3 million in the Prior Period. The increase was primarily the result of additional interest income from significantly higher cash balances held during the Current Period as well as interest income recorded on our investment in senior secured notes issued by Seven Seas Petroleum Inc. 26
Interest Expense. Interest expense increased to $51.7 million in the Current Period from $48.9 million in the Prior Period. The increase in the Current Period was due to a $167 million increase in average long-term borrowings in the Current Period compared to the Prior Period, partially offset by income of $1.6 million earned on our interest rate swap during the Current Period. In addition to the interest expense reported, we capitalized $2.3 million of interest during each of the Current Period and Prior Period on significant investments in unproved properties that were not being currently depreciated, depleted or amortized and on which exploration activities were in progress. Interest is capitalized using the weighted average interest rate of our outstanding borrowings. We anticipate that capitalized interest for the remainder of 2002 will be between $2.0 million and $2.5 million. Gothic Standby Credit Facility Costs. During the Prior Period, we obtained a standby commitment for a $275 million credit facility, consisting of a $175 million term loan and a $100 million revolving credit facility which, if needed, would have replaced our then existing revolving credit facility. The term loan was available to provide funds to repurchase any of Gothic Production Corporation's 11.125% senior secured notes tendered following the closing of the Gothic acquisition in January 2001 pursuant to a change-of-control offer to purchase. In February 2001, we purchased $1.0 million of notes tendered for 101% of such amount. We did not use the standby credit facility and the commitment terminated in February 2001. Chesapeake incurred $3.4 million of costs for the standby facility, which were recognized in the Prior Period. Provision (Benefit) for Income Taxes. Chesapeake recorded an income tax benefit of $1.7 million in the Current Period, compared to income tax expense of $105.2 million in the Prior Period. Income tax expense for the Prior Period was comprised of $97.9 million related to our domestic operations and $7.3 million related to our Canadian operations which were sold on October 1, 2001. We anticipate that all 2002 income tax expense will be deferred. CASH FLOWS FROM OPERATING, INVESTING, AND FINANCING ACTIVITIES Cash Flows from Operating Activities. Cash provided by operating activities decreased 28% to $214.8 million during the Current Period compared to $297.0 million during the Prior Period. The decrease was due primarily to lower oil and gas prices realized during the Current Period. Cash Flows from Investing Activities. Cash used in investing activities increased to $324.6 million during the Current Period from $302.0 million in the Prior Period. During the Current Period, we expended approximately $176.4 million to initiate drilling on 281 (123.7 net) wells and invested approximately $7.2 million in unproved properties. This compares to $179.9 million to initiate drilling on 280 (143.0 net) wells and $48.5 million to purchase unproved properties in the Prior Period. During the Current Period, we had acquisitions of oil and gas companies and properties of $124.3 million and no divestitures of oil and gas properties. This compares to acquisitions of oil and gas companies and properties of $53.1 million and divestitures of $0.2 million in the Prior Period. During the Current Period, we had additional investments in drilling rig equipment and other fixed assets of $18.6 million compared to $20.8 million in the Prior Period. The Current Period included additional investments in the common stock of two oil and gas companies totaling $2.4 million and $4.2 million in proceeds from the sale of RAM Energy, Inc. notes. Cash Flows from Financing Activities. There was $1.6 million of cash used in financing activities in the Current Period, compared to cash provided by financing activities of $5.1 million in the Prior Period. The activity in the Current Period reflects the net increase in borrowings under our commercial bank credit facility of $45.0 million. This was primarily offset by the repurchase of $42.2 million of our 7.875% senior notes. We received $2.0 million in cash from the exercise of stock options, and $5.1 million was used to pay dividends on our 6.75% preferred stock. The activity in the Prior Period included increased borrowings under our credit facility of $135.0 million, $786.7 million received from the issuance of $800.0 million of 8.125% senior notes, $906.0 million used to redeem various senior notes, $12.2 million used to pay financing costs related to new debt issuance, and $2.8 million received from the exercise of stock options. 27
LIQUIDITY AND CAPITAL RESOURCES Sources of Liquidity Chesapeake had a working capital deficit of $19.6 million at June 30, 2002, including $6.3 million in cash. We have a $225 million revolving bank credit facility (with a committed borrowing base of $225 million) which matures in September 2003 but under certain circumstances can be extended through June 2005. As of June 30, 2002, we had borrowed $45.0 million under the facility and were using $11.1 million of the facility to secure various letters of credit. As of August 2, 2002, borrowings under the credit facility had increased to $65.0 million, largely as a result of borrowings to fund an acquisition in late July 2002. The use of facility borrowings and long-term indebtedness to fund recent and pending acquisitions is discussed below under Investing and Financing Transactions. We believe we will have adequate resources, including operating cash flows, working capital and proceeds from our revolving bank credit facility, to fund our capital expenditure budget for exploration and development activities during the remainder of 2002, which is currently estimated to be $160 - - $180 million. Further, our drilling program is largely discretionary and can be adjusted to match changing circumstances. Based on our current cash flow assumptions we expect operating cash flow to reach $380 - $400 million during 2002. Any operating cash flow not needed to fund our drilling program will be available for acquisitions, debt repayments or other general corporate purposes in 2002. A significant portion of our liquidity is concentrated in cash and cash equivalents (including restricted cash) 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 instruments and accounts receivables. 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 concentration of these assets in the oil and gas industry 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 with high credit ratings. Our liquidity is not dependent on the use of off-balance sheet financing arrangements, such as the securitization of receivables or obtaining access to assets through special purpose entities. We have not relied on off-balance sheet financing arrangements in the past and we do not intend to rely on such arrangements in the future as a source of liquidity. We do not issue commercial paper. Contractual Obligations and Commercial Commitments We have a $225 million revolving bank credit facility (with a committed borrowing base of $225 million) which matures in September 2003. As of June 30, 2002, we had borrowed $45.0 million under this facility and were using $11.1 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 total facility usage. The unused portion of the facility is subject to an annual commitment fee of 0.50%. Interest is payable quarterly. The collateral value and borrowing base are redetermined periodically. The credit facility contains various covenants and restrictive provisions which restrict 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, create liens, and make acquisitions. The credit facility 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 of at least 2.5 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 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 facility also has cross default provisions that apply to other indebtedness we may have with an outstanding principal balance in excess of $5.0 million. 28
As of June 30, 2002, senior notes represented $1.3 billion of our long-term debt and consisted of the following: $800.0 million principal amount of 8.125% senior notes due 2011, $250.0 million principal amount of 8.375% senior notes due 2008, $107.8 million principal amount of 7.875% senior notes due 2004 and $142.7 million principal amount of 8.5% senior notes due 2012. There are no scheduled principal payments required on any of the senior notes until March 2004, when $107.8 million is due, giving effect to the repurchase and retirement of $42.2 million of our 7.875% senior notes in the Current Period. Debt ratings for the senior notes are B1 by Moody's Investor Service, B+ by Standard & Poor's Ratings Services and BB- by Fitch Ratings. Debt ratings for our secured bank credit facility are Ba3 by Moody's Investor Service, BB by Standard & Poor's Ratings Services and BB+ by Fitch Ratings. Our senior notes are unsecured senior obligations of Chesapeake and rank equally with all of our other unsecured indebtedness. All of our wholly owned subsidiaries except Chesapeake Energy Marketing, Inc. guarantee the notes. We can acquire outstanding senior notes at either make-whole or redemption prices set forth in the respective indentures, and from time to time we acquire senior notes through market purchases. If we repurchase at least an additional $32.8 million of the 7.875% senior notes by August 31, 2003, we may extend the bank credit facility until June 2005 for an amount equal to the total revolving credit facility commitment less the outstanding amount of the 7.875% senior notes plus $50 million. The indentures for the 8.125% and 8.375% senior notes contain covenants limiting 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; create restrictions on the payment of dividends or other amounts to us from our restricted subsidiaries; incur liens; engage in transactions with affiliates; sell assets; and consolidate, merge or transfer assets. The debt incurrence covenants do not affect our ability to borrow under or expand our secured credit facility. As of June 30, 2002, we estimate that secured commercial bank indebtedness of approximately $385 million could have been incurred under the most restrictive indenture covenant. The indenture covenants do not apply to Chesapeake Energy Marketing, Inc., an unrestricted subsidiary. Some of our commodity price and interest rate risk management arrangements require us to deliver cash collateral or other assurances of performance to the counterparties in the event that our payment obligations with respect to our commodity price and interest rate risk management transactions exceed certain levels. At June 30, 2002, we posted $10.0 million of collateral with one of our counterparties through a letter of credit issued under our bank credit facility. Future collateral requirements are uncertain and will depend on arrangements with our counterparties and the level of volatility in natural gas and oil prices and interest rates. Investing and Financing Transactions On June 28, 2002, we acquired Canaan Energy Corporation in a cash merger through a Chesapeake subsidiary. Under the agreement, all outstanding common shares of Canaan, other than the Canaan shares already owned by Chesapeake, were purchased at $18.00 per share in cash, and the outstanding options to acquire Canaan common stock were converted into the right to receive, for each share of Canaan common stock to be received upon exercise, the merger consideration less the per share exercise price and withholding taxes. The aggregate net cash consideration for the merger was $120 million, including the retirement of Canaan's outstanding indebtedness of approximately $43 million. In the Current Period, we purchased and subsequently retired $42.2 million of our 7.875% senior notes due 2004 for total consideration of $44.0 million, including accrued interest of $0.8 million and $1.0 million of redemption premium. See Note 2 of the notes to consolidated financial statements included in this report for a discussion of our hedging activities and financial instruments. In late July 2002, we completed an acquisition of oil and gas properties using bank facility borrowings to fund the cash purchase price of $38 million. We have entered into three definitive purchase agreements to acquire additional oil and gas properties for an aggregate cash purchase price of approximately $132 million. We expect to close these acquisitions during the third quarter of 2002. It is our intent to fund these acquisitions by issuing long- 29
term unsecured notes through a private offering. If for any reason this market is not available, we intend to use the bank facility to fund the acquisitions. RECENTLY ISSUED ACCOUNTING STANDARDS See Note 8 of the notes to the consolidated financial statements included in this report for a summary of recently issued accounting standards. 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 gas reserve estimates, planned capital expenditures, the drilling of oil and gas wells and future acquisitions, expected oil and gas production, cash flow and anticipated liquidity, business strategy and other plans and objectives for future operations, expected future expenses and utilization of net operating loss carryforwards. 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 1 of our Form 10-K for the year ended December 31, 2001. These factors include: o the volatility of oil and gas prices, o our substantial indebtedness, o the cost and availability of drilling and production services, o our commodity price risk management activities, including counterparty contract performance risk, o uncertainties inherent in estimating quantities of oil and gas reserves, projecting future rates of production and the timing of development expenditures, o our ability to replace reserves, o the availability of capital, o uncertainties in evaluating oil and gas reserves of acquired properties and associated potential liabilities, o drilling and operating risks, o our ability to generate future taxable income sufficient to utilize our federal and state income tax net operating loss (NOL) carryforwards before their expiration, o future ownership changes which could result in additional limitations to our NOLs, o adverse effects of governmental and environmental regulation, o losses possible from pending or future litigation, o the strength and financial resources of our competitors, and o the loss of officers or key employees. 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 and our other reports filed with the Securities and Exchange Commission that attempt to advise interested parties of the risks and factors that may affect our business. 30
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK 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, 2002, our derivative instruments were comprised of swaps, collars, cap-swaps, straddles, strangles 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, our derivative instruments continue to be highly effective in achieving the risk management objectives for which they were intended. o 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. o 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, then we receive the fixed price and pay the market price. If the market price is between the call and the put strike price, then no payments are due from either party. o For cap-swaps, we receive a fixed price for the hedged commodity and pay a floating market price. The fixed price received by Chesapeake includes a premium in exchange for a "cap" limiting the counterparty's exposure. o For straddles, Chesapeake receives a premium from the counterparty in exchange for the sale of a call and a put option at an established fixed price. To the extent that the floating market price differs from the established fixed price, Chesapeake pays the counterparty. o For strangles, Chesapeake receives a premium from the counterparty in exchange for the sale of a call and a put option. If the market price exceeds the fixed price of the call option or falls below the fixed price of the put option, then Chesapeake pays the counterparty. If the market price settles between the fixed price of the call and put option, no payment is due from Chesapeake. o Basis protection swaps are arrangements that guarantee a price differential of oil and 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. From time to time, we close certain swap transactions designed to hedge a portion of our oil and natural gas production by entering into a counter-swap instrument. Under the counter-swap we receive a floating price for the hedged commodity and pay a fixed price to the counterparty. To the extent the counter-swap, which does not qualify for hedge accounting under SFAS 133, is designed to lock the value of an existing SFAS 133 cash flow hedge, the net value of the swap and the counter-swap is frozen and shown as a derivative receivable or payable in the consolidated balance sheets. At the same time, the original swap is designated as a non-qualifying cash flow hedge under SFAS 133. Pursuant to SFAS 133, our cap-swaps, straddles, strangles, counter-swaps and basis protection swaps do not qualify for designation as cash flow hedges. Therefore, changes in the fair value of these instruments that occur prior to their maturity, together with any changes in fair value of cash flow hedges resulting from ineffectiveness, are reported in the consolidated statements of operations as risk management income (loss). Amounts recorded in risk management income (loss) do not represent cash gains or losses. Rather, these amounts are temporary valuation swings in contracts or portions of contracts that are not entitled to receive SFAS 133 cash flow hedge accounting treatment. All amounts initially recorded in this caption related to commodity derivatives are ultimately reversed within this same caption and included in oil and gas sales over the respective contract terms. 31
As of June 30, 2002, we had the following open oil and gas derivative instruments designed to hedge a portion of our gas production for periods after June 2002:
Additional information concerning the fair value of our oil and gas derivative instruments is as follows ($ in thousands):
Results from interest rate hedging transactions are reflected as adjustments to interest expense in the corresponding months covered by the swap agreement. The remaining $92.2 million of the interest rate swap has not been designated as a fair value hedge. The mark-to-market value of this portion of the instrument is recorded as a derivative asset or liability on the consolidated balance sheets with the offsetting amount reflected in risk management income (loss) on the consolidated statements of operations. The amount recorded in risk management income (loss) will be reversed and reflected in interest expense over the term of the swap. The estimated fair value of the interest rate swap at June 30, 2002 was an asset of approximately $5.0 million comprised of $1.6 million reflected as risk management income, $1.4 million reflected as an increase in the carrying value of our long-term debt, $1.6 million reflected as a reduction in interest expense, and $0.4 million reflected as other income related to the gain on the repurchase of debt. In June 2002, we entered into an additional interest rate swap. The terms of this swap agreement are as follows:
June 30, 2002. Results of the swaption will be reflected as adjustments to interest expense in the corresponding months covered by the swaption agreement. Risk management income related to our fair value hedges is comprised of the following ($ in thousands):
PART II. OTHER INFORMATION ITEM 1. LEGAL PROCEEDINGS We are subject to ordinary routine litigation incidental to our business, none of which is expected to have a material adverse effect on Chesapeake. In addition, Chesapeake is a defendant in other pending actions which are described in Note 3 of the notes to the consolidated financial statements included in this report and Item 3 of our Annual Report on Form 10-K for the year ended December 31, 2001. ITEM 2. CHANGES IN SECURITIES AND USE OF PROCEEDS Not applicable ITEM 3. DEFAULTS UPON SENIOR SECURITIES Not applicable ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS Three matters were submitted to a vote of the shareholders at Chesapeake's annual meeting of shareholders held on June 7, 2002: the election of directors, the adoption of a stock option plan for employees and consultants and the adoption of a stock option plan for non-employee directors. In the election of directors, Aubrey K. McClendon received 153,808,677 votes for election and 4,670,442 shares were withheld from voting for Mr. McClendon; and Shannon T. Self received 153,868,588 votes for election and 4,610,531 share were withheld from voting for Mr. Self. The other directors whose terms continued after the meeting are Edgar F. Heizer, Jr., Breene M. Kerr, Tom L. Ward and Frederick B. Whittemore. In the adoption of our 2002 Stock Option Plan, 121,950,327 votes were received for the adoption of the plan, 36,092,764 votes were received against adoption of the plan and 436,025 shares were withheld from voting on this proposal. In the adoption of our 2002 Non-Employee Director Stock Option Plan, 120,983,754 votes were received for the adoption of the plan, 36,993,462 votes were received against adoption of the plan and 501,899 shares were withheld from voting on this proposal. There were no broker non-votes. ITEM 5. OTHER INFORMATION Not applicable ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K (a) Exhibits The following exhibits are filed as a part of this report: EXHIBIT NUMBER DESCRIPTION 3.1 Chesapeake's Restated Certificate of Incorporation together with the Certificate of Designation for the 6.75% Cumulative Convertible Preferred Stock of Chesapeake and the Certificate of Designation for the Series A Junior Participating Preferred Stock of Chesapeake. Incorporated herein by reference to Exhibit 3.1 to Chesapeake's registration statement on Form S-3 (No. 333-96863) filed July 22, 2002. 4.6.1 Second Amendment dated June 4, 2002 with respect to Second Amended and Restated Credit Agreement, dated as of June 11, 2001, among Chesapeake Energy Corporation, Chesapeake Exploration Limited Partnership, as Borrower, Bear Stearns Corporate Lending Inc., as Syndication Agent, Union Bank of California, N.A., as Administrative Agent and Collateral Agent, and other lenders party thereto. 36
12.1 Computation of Ratios of Earnings to Combined Fixed Charges and Preferred Stock Dividends. (b) Reports on Form 8-K During the quarter ended June 30, 2002, we filed the following current reports on Form 8-K: On April 4, 2002, we filed a current report on Form 8-K reporting under Item 5 that we had issued a press release announcing first quarter 2002 earnings release and conference call dates. On April 16, 2002, we filed a current report on Form 8-K reporting under Item 5 that we had issued a press release announcing that our Board of Directors had declared a regular quarterly dividend on our preferred stock. On April 23, 2002, we filed a current report on Form 8-K reporting under Item 5 that we had issued a press release announcing an agreement to acquire Canaan Energy Corporation. On April 30, 2002, we filed a current report on Form 8-K reporting under Item 5 that we had issued a press release announcing first quarter 2002 financial and operating results. We furnished under Item 9 updates to our operational and financial guidance for 2002 included in the press release. On June 5, 2002, we filed a current report on Form 8-K reporting under Item 5 that we had issued a press release announcing that our 2002 Annual Meeting of Shareholders would be webcast live. 37
SIGNATURES Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. CHESAPEAKE ENERGY CORPORATION (Registrant) By: /s/ AUBREY K. MCCLENDON ---------------------------- Aubrey K. McClendon Chairman and Chief Executive Officer By: /s/ MARCUS C. ROWLAND --------------------------- Marcus C. Rowland Executive Vice President and Chief Financial Officer Date: August 5, 2002 38
INDEX TO EXHIBITS
EXHIBIT 4.6.1 SECOND AMENDMENT TO SECOND AMENDED AND RESTATED CREDIT AGREEMENT THIS SECOND AMENDMENT TO SECOND AMENDED AND RESTATED CREDIT AGREEMENT (herein called this "Amendment") made as of June 4, 2002 by and among Chesapeake Exploration Limited Partnership, an Oklahoma limited partnership ("Borrower"), Chesapeake Energy Corporation, an Oklahoma corporation ("Company"), Bear Stearns Corporate Lending Inc., as syndication agent ("Syndication Agent"), Union Bank of California, N.A., as administrative agent and collateral agent ("Administrative Agent"), and the several banks and other financial institutions or entities parties hereto ("Lenders"). WITNESSETH: WHEREAS, Borrower, Company, Syndication Agent, Administrative Agent and Lenders entered into that certain Second Amended and Restated Credit Agreement dated as of June 11, 2001 (as amended, supplemented, or restated to the date hereof, the "Original Agreement"), for the purpose and consideration therein expressed, whereby Lenders became obligated to make loans to Borrower as therein provided; and WHEREAS, Borrower, Company, Syndication Agent, Administrative Agent and Lenders desire to amend the Original Agreement as set forth herein; NOW, THEREFORE, in consideration of the premises and the mutual covenants and agreements contained herein and in the Original Agreement, in consideration of the loans which may hereafter be made by Lenders to Borrower, and for other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties hereto do hereby agree as follows: ARTICLE I. Definitions and References Section 1.1. Terms Defined in the Original Agreement. Unless the context otherwise requires or unless otherwise expressly defined herein, the terms defined in the Original Agreement shall have the same meanings whenever used in this Amendment.
Section 1.2. Other Defined Terms. Unless the context otherwise requires, the following terms when used in this Amendment shall have the meanings assigned to them in this Section 1.2. "Amendment" means this Second Amendment to Second Amended and Restated Credit Agreement. "Credit Agreement" means the Original Agreement as amended hereby. ARTICLE II. Amendments and Waivers Section 2.1. Defined Terms. Section 1.1 of the Original Agreement is hereby amended to add the following definitions of Pari Passu Lender Hedging Obligations and Lender Hedging Obligations: "'Pari Passu Lender Hedging Obligations' means any Lender Hedging Obligations up to a maximum aggregate amount of $30,000,000 to the extent arising under a Hedge Agreement that explicitly states that such obligations are intended to be Pari Passu Lender Hedging Obligations under this Agreement." "'Lender Hedging Obligations' means all obligations arising from time to time under Hedge Agreements entered into from time to time between the Company or the Borrower and a Lender or an affiliate of a Lender which are within the definition of secured indebtedness under the Mortgage." Section 2.2. Pro Rata Treatment and Payments. Paragraph (f) of Section 3.8 of the Original Agreement is amended in its entirety to read as follows: "(f) Notwithstanding anything in this Section 3.8 or in any of the Loan Documents to the contrary, in the event that the Revolving Loans shall have become due and payable, and the Revolving Commitments shall have been terminated, pursuant to Section 8, any amounts received by the Administrative Agent from the Loan Parties or their Subsidiaries or from the Collateral in respect of the Borrower's Obligations shall be applied in the following order of priority: (i) First, to reimburse the Administrative Agent for its fees, costs and expenses pursuant to the Loan Documents; 2
(ii) Second, to pay unpaid interest accrued on the Revolving Loans; (iii) Third, (A) to pay all other outstanding Obligations (whether or not contingent) under, out of, or in connection with any of the Loan Documents or Letters of Credit, including the outstanding principal of the Revolving Loans and, after the payment of the outstanding principal of the Revolving Loans, to cash collateralize outstanding Letters of Credit (as contemplated pursuant to Section 8) and (B) to pay Pari Passu Lender Hedging Obligations (applied ratable to (A) and to (B) based upon the total outstanding Obligations under (A) and the lesser of the total outstanding Pari Passu Lender Hedging Obligations under (B) or $30,000,000); and (iv) Fourth, once all of the foregoing Obligations (whether or not contingent) and Pari Passu Lender Hedging Obligations have been indefeasibly paid in full and all Letters of Credit have been terminated or cash collateralized (as contemplated pursuant to Section 8), to the Borrower. Agent shall have no responsibility to determine the existence or amount of Pari Passu Lender Hedging Obligations or other Lender Hedging Obligations and may reserve from the application of amounts under this paragraph (f) amounts distributable in respect of Pari Passu Lender Hedging Obligations until it has received evidence satisfactory to it of the existence and amount of such Pari Passu Lender Hedging Obligations." Section 2.3. Investments. Paragraph (i) of Section 7.7 of the Original Agreement is hereby amended by deleting from the proviso "$50,000,000" and inserting in place thereof "$100,000,000." Section 2.4. Releases of Guarantees and Liens; Designation of Subsidiaries. Section 10.14 of the Original Agreement is hereby amended by amending paragraph (a) in its entirety to read as follows and adding the following paragraph (c): "(a) Notwithstanding anything to the contrary contained herein or in any other Loan Document, the Administrative Agent is hereby irrevocably authorized by each Lender (without requirement of notice to or consent of any Lender except as expressly required by Section 10.1) to take any action requested by the Borrower having the effect of releasing any Collateral or guarantee obligations (i) to the extent necessary to permit consummation of any transaction not prohibited by any Loan Document or that has been consented to in accordance with Section 10.1 3
(ii) to release Collateral to the extent provided in paragraph (c) of this Section 10.14, or (iii) at such time as the Revolving Loans, the Reimbursement Obligations and the other obligations under the Loan Documents (other than obligations under or in respect of Hedge Agreements) shall have been paid in full, the Revolving Commitments have been terminated and no Letters of Credit shall be outstanding, the Collateral shall be released from the Liens created by the Security Documents, and the Security Documents and all obligations (other than those expressly stated to survive such termination) of the Administrative Agent and each Loan Party under the Security Documents shall terminate, all without delivery of any instrument or performance of any act by any Person." * * * "(c) The Administrative Agent may release a portion of the Collateral from time to time without notice to or consent of any Lender so long as no Default or Event of Default has occurred and is continuing, no Borrowing Base Deficiency shall exist and the aggregate value of the Collateral released between Determination Dates pursuant to this paragraph (c) does not exceed $500,000, such value based upon the valuation of such Collateral at the time of the most recent Determination Date. The Administrative Agent shall release Collateral pursuant to this paragraph (c) only upon, and shall be protected in relying upon, a certificate of Borrower to the effect that the conditions of the preceding sentence exist with respect to the requested release of Collateral." Section 2.5. Partial Release of Collateral. Borrower and Majority Lenders hereby agree that Administrative Agent may release from the Liens under the Loan Documents the properties listed on Schedule I hereto. Section 2.6. Redetermination of the Borrowing Base and Collateral Value. Borrower, Administrative Agent and Majority Lenders hereby agree that, after giving effect to the partial release of Collateral described in Section 2.5, from the date hereof: (a) until the next date hereafter as of which the Borrowing Base is redetermined, the Borrowing Base shall be $225,000,000; and (b) until the next date hereafter as of which the Collateral Value is redetermined, the Collateral Value shall be $450,466,200. 4
ARTICLE III. Conditions of Effectiveness Section 3.1. Effective Date. This Amendment shall become effective as of the date first above written when and only when: (a) Administrative Agent shall have received, at Administrative Agent's office, duly executed and delivered and in form and substance satisfactory to Administrative Agent, all of the following: (i) this Amendment; (ii) an "Omnibus Certificate" of the Secretary and of the Chairman of the Board or President of the general partner of Borrower, which shall contain the names and signatures of the officers of the general partner of Borrower authorized to execute Loan Documents and which shall certify to the truth, correctness and completeness of the following exhibits attached thereto: (1) a copy of resolutions attached thereto duly adopted by the Board of Directors of the general partner of Borrower and in full force and effect at the time this Amendment is entered into, authorizing the execution of this Amendment and the other Loan Documents delivered or to be delivered in connection herewith and the consummation of the transactions contemplated herein and therein, (2) a copy of the charter documents of Borrower and of the general partner of Borrower and all amendments thereto, certified by the appropriate official of the Borrower's state and general partner's state of organization, and (3) a copy of any bylaws of the general partner of Borrower previously delivered to Agent and Lenders in connection with the Original Agreement (which may, with respect to any such charter documents or bylaws, reference documents previously delivered in connection with the Original Agreement); (iii) a "Compliance Certificate" of the Chairman of the Board or President and of the chief financial officer of the Company, which shall contain (1) a certification by such officers as to the satisfaction of the conditions set out in subsections (a), (b), and (c) of Section 5.2 of the Original Agreement and (2) the calculations required to determine the Senior Debt Limit (along with the supporting documentation described in Section 5.2(c) of the Original Agreement); (iv) documents similar to those specified in subsection (ii) of this Section with respect to each Subsidiary Guarantor (which may, with respect to charter documents or bylaws, reference documents previously delivered in connection with the Original Agreement); and 5
(v) such other supporting documents as Administrative Agent may reasonably request. (b) Borrower shall have paid, in connection with such Loan Documents, all recording, handling, amendment and other fees required to be paid to Administrative Agent pursuant to any Loan Documents. (c) Borrower shall have paid, in connection with such Loan Documents, all other fees and reimbursements to be paid to Administrative Agent pursuant to any Loan Documents, or otherwise due Administrative Agent and including fees and disbursements of Administrative Agent's attorneys. ARTICLE IV. Representations and Warranties Section 4.1. Representations and Warranties of Borrower. In order to induce each Lender to enter into this Amendment, Borrower represents and warrants to each Lender that: (a) The representations and warranties contained in Section 4 of the Original Agreement are true and correct at and as of the time of the effectiveness hereof, except to the extent that the facts on which such representations and warranties are based have been changed by the extension of credit under the Credit Agreement. (b) The Company and Borrower are duly authorized to execute and deliver this Amendment and are and will continue to be duly authorized to borrow monies and to perform their respective obligations under the Credit Agreement. The Company and Borrower have duly taken all corporate or partnership action necessary to authorize the execution and delivery of this Amendment and to authorize the performance of the obligations of the Company and Borrower hereunder. (c) The execution and delivery by the Company and Borrower of this Amendment, the performance by the Company and Borrower of its obligations hereunder and the consummation of the transactions contemplated hereby do not and will not conflict with any provision of law, statute, rule or regulation or of the certificate of incorporation, bylaws, or agreement of limited partnership of the Company or Borrower (as applicable), or of any material agreement, judgment, license, order or permit applicable to or binding upon the Company or Borrower, or result in the creation of any lien, charge or encumbrance upon any assets or properties of the Company or Borrower. Except for those which have been obtained, no 6
consent, approval, authorization or order of any court or governmental authority or third party is required in connection with the execution and delivery by the Company and Borrower of this Amendment or to consummate the transactions contemplated hereby. (d) When duly executed and delivered, each of this Amendment and the Credit Agreement will be a legal and binding obligation of the Company and Borrower, enforceable in accordance with its terms, except as limited by bankruptcy, insolvency or similar laws of general application relating to the enforcement of creditors' rights and by equitable principles of general application. (e) The audited annual consolidated financial statements of the Company dated as of December 31, 2001 and the unaudited quarterly consolidated financial statements of the Company dated as of March 31, 2002 fairly present the consolidated financial position at such dates and the consolidated statement of operations and the changes in consolidated financial position for the periods ending on such dates for the Company. Copies of such financial statements have heretofore been delivered to each Lender. Since such dates no material adverse change has occurred in the financial condition or businesses or in the consolidated financial condition or businesses of the Company. ARTICLE V. Miscellaneous Section 5.1. Ratification of Agreements. The Original Agreement as hereby amended is hereby ratified and confirmed in all respects. Any reference to the Credit Agreement in any Loan Document shall be deemed to be a reference to the Original Agreement as hereby amended. The execution, delivery and effectiveness of this Amendment shall not, except as expressly provided herein, operate as a waiver of any right, power or remedy of Lenders under the Credit Agreement, the Notes, or any other Loan Document nor constitute a waiver of any provision of the Credit Agreement, the Notes or any other Loan Document. Section 5.2. Survival of Agreements. All representations, warranties, covenants and agreements of Borrower herein shall survive the execution and delivery of this Amendment and the performance hereof, including without limitation the making or granting of the Loans, and shall further survive until all of the Obligations are paid in full. All statements and agreements contained in any certificate or instrument delivered by the Company, Borrower or any Subsidiary Guarantor hereunder or under the Credit Agreement to any Lender shall be deemed to constitute 7
representations and warranties by, and/or agreements and covenants of, such Loan Party under this Amendment and under the Credit Agreement. Section 5.3. Loan Documents. This Amendment is a Loan Document, and all provisions in the Credit Agreement pertaining to Loan Documents apply hereto. Section 5.4. Governing Law. This Amendment shall be governed by and construed in accordance the laws of the State of New York and any applicable laws of the United States of America in all respects, including construction, validity and performance. Section 5.5. Counterparts; Fax. This Amendment may be separately executed in counterparts and by the different parties hereto in separate counterparts, each of which when so executed shall be deemed to constitute one and the same Amendment. This Amendment may be validly executed by facsimile or other electronic transmission. THIS AMENDMENT AND THE OTHER LOAN DOCUMENTS REPRESENT THE FINAL AGREEMENT BETWEEN THE PARTIES AND MAY NOT BE CONTRADICTED BY EVIDENCE OF PRIOR, CONTEMPORANEOUS, OR SUBSEQUENT ORAL AGREEMENTS OF THE PARTIES. THERE ARE NO UNWRITTEN ORAL AGREEMENTS OF THE PARTIES. [THE REMAINDER OF THIS PAGE HAS BEEN INTENTIONALLY LEFT BLANK.] 8
IN WITNESS WHEREOF, this Amendment is executed as of the date first above written. CHESAPEAKE EXPLORATION LIMITED PARTNERSHIP By: Chesapeake Operating, Inc., its general partner By: /s/ MARTHA A. BURGER --------------------------------- Name: Martha A. Burger Title: Treasurer CHESAPEAKE ENERGY CORPORATION By: /s/ MARTHA A. BURGER --------------------------------- Name: Martha A. Burger Title: Treasurer & Sr. Vice President Human Resources 9
UNION BANK OF CALIFORNIA, N.A. Administrative Agent, Collateral Agent, Issuing Lender and Lender By: /s/ RANDALL OSTERBERG ------------------------------- Name: Randall Osterberg Title: Senior Vice President By: /s/ SEAN MURPHY -------------------------------- Name: Sean Murphy Title: Assistant Vice President 10
BANK OF OKLAHOMA, N.A. By: /s/ JOHN N. HUFF --------------------------------- Name: John N. Huff Title: Vice President BANK OF SCOTLAND By: /s/ JOSEPH FRATUS ----------------------------------- Name: Joseph Fratus Title: Vice President BEAR STEARNS CORPORATE LENDING INC. By: /s/ VICTOR BULZACCHELLI --------------------------------- Name: Victor Bulzacchelli Title: Authorized Agent BNP PARIBAS By: /s/ DAVID DODD /s/ POLLY SCHOTT --------------------------------- Name: David Dodd Polly Schott Title: Director Vice President COMERICA BANK - TEXAS By: --------------------------------- Name: Title: COMPASS BANK By: /s/ KATHLEEN J. BOWEN --------------------------------- Name: Kathleen J. Bowen Title: Vice President 11
CREDIT AGRICOLE INDOSUEZ By: --------------------------------- Name: Title: NATEXIS BANQUES POPULAIRES By: /s/ DONOVAN C. BROUSSARD --------------------------------- Name: Donovan c. Broussard Title: Vice President /s/ LOUIS P. LAVILLE, III ------------------------------------- Louis P. Laville, III Vice President and Group Manager PNC BANK, NATIONAL ASSOCIATION By: /s/ DOUG CLARK --------------------------------- Name: Doug Clark Title: Vice President RZB FINANCE LLC By: /s/ FRANK J. YAUTZ --------------------------------- Name: Frank J. Yautz Title: First Vice President By: /s/ PEARL GEFFERS --------------------------------- Name: Pearl Geffers Title: First Vice President SUMITOMO MITSUI BANKING CORPORATION By: --------------------------------- Name: Title: 12
TORONTO DOMINION (TEXAS), INC. By: /s/ DEBBIE A. GREENE --------------------------------- Name: Debbie A. Greene Title: Vice President U.S. BANK NATIONAL ASSOCIATION By: --------------------------------- Name: Title: WASHINGTON MUTUAL BANK, FA By: /s/ MARK ISENSEE --------------------------------- Name: Mark Isensee Title: Vice President CREDIT LYONNAIS NEW YORK BRANCH By: /s/ BERNARD WEYMULLER --------------------------------- Name: Bernard Weymuller Title: Senior Vice President 13
Second Amendment CONSENT AND AGREEMENT By its execution below, each Guarantor hereby (i) consents to the provisions of this Amendment and the transactions contemplated herein, (ii) ratifies and confirms the Guarantee Agreement dated as of June 11, 2001 made by it for the benefit of Administrative Agent and Lenders and the other Loan Documents executed pursuant to the Credit Agreement (Carmen Acquisition Corp. and Sap Acquisition Corp. having become parties thereto by execution and delivery of that certain Assumption Agreement of even date herewith), (iii) agrees that all of its respective obligations and covenants thereunder shall remain unimpaired by the execution and delivery of this Amendment and the other documents and instruments executed in connection herewith, and (iv) agrees that the Guarantee Agreement and such other Loan Documents shall remain in full force and effect. CHESAPEAKE ENERGY CORPORATION By: /s/ MARTHA A. BURGER --------------------------------- Name: Martha A. Burger Title: Treasurer & Sr. Vice President Human Resources THE AMES COMPANY, INC. By: /s/ MARTHA A. BURGER --------------------------------- Name: Martha A. Burger Title: Treasurer CHESAPEAKE ACQUISITION CORPORATION By: /s/ MARTHA A. BURGER --------------------------------- Name: Martha A. Burger Title: Treasurer CHESAPEAKE ENERGY LOUISIANA CORPORATION By: /s/ MARTHA A. BURGER --------------------------------- Name: Martha A. Burger Title: Treasurer 1
CHESAPEAKE OPERATING, INC. By: /s/ MARTHA A. BURGER --------------------------------- Name: Martha A. Burger Title: Treasurer & Sr. Vice President Human Resources CHESAPEAKE PANHANDLE LIMITED PARTNERSHIP By: CHESAPEAKE OPERATING, INC., its General Partner By: /s/ MARTHA A. BURGER --------------------------------- Name: Martha A. Burger Title: Treasurer & Sr. Vice President Human Resources CHESAPEAKE ROYALTY COMPANY By: /s/ MARTHA A. BURGER --------------------------------- Name: Martha A. Burger Title: Treasurer CHESAPEAKE-STAGHORN ACQUISITION L .P. By: CHESAPEAKE OPERATING, INC., its General Partner By: /s/ MARTHA A. BURGER --------------------------------- Name: Martha A. Burger Title: Treasurer & Sr. Vice President Human Resources CHESAPEAKE LOUISIANA, L.P. By: CHESAPEAKE OPERATING, INC., its General Partner By: /s/ MARTHA A. BURGER --------------------------------- Name: Martha A. Burger Title: Treasurer & Sr. Vice President Human Resources 2
GOTHIC ENERGY CORPORATION By: /s/ MARTHA A. BURGER --------------------------------- Name: Martha A. Burger Title: Treasurer GOTHIC PRODUCTION CORPORATION By: /s/ MARTHA A. BURGER --------------------------------- Name: Martha A. Burger Title: Treasurer NOMAC DRILLING CORPORATION By: /s/ MARTHA A. BURGER --------------------------------- Name: Martha A. Burger Title: Treasurer CARMEN ACQUISITION CORP. By: /s/ MARTHA A. BURGER --------------------------------- Name: Martha A. Burger Title: Treasurer SAP ACQUISITION CORP. By: /s/ MARTHA A. BURGER --------------------------------- Name: Martha A. Burger Title: Treasurer CHESAPEAKE MOUNTAIN FRONT CORP. By: /s/ MARTHA A. BURGER --------------------------------- Name: Martha A. Burger Title: Treasurer 3
EXHIBIT 12.1 CHESAPEAKE ENERGY CORPORATION RATIOS OF EARNINGS TO COMBINED FIXED CHARGES AND PREFERRED DIVIDENDS (DOLLARS IN 000's) Six Six Year Months Year Year Year Year Months Ended Ended Ended Ended Ended Ended Ended June 30, Dec. 31, Dec. 31, Dec. 31, Dec. 31, Dec. 31, June 30, 1997 1997 1998 1999 2000 2001 2002 ------------------------------------------------------------------------------------ Income before income taxes and extraordinary item $(180,330) $ (31,574) $(920,520) $ 35,030 $ 196,162 $ 438,365 $ (4,257) Interest 18,550 17,448 68,249 81,052 86,256 98,321 51,650 Amortization of capitalized interest 8,772 4,386 12,240 1,047 1,226 1,784 853 Bond discount amortization (a) -- -- -- -- -- -- -- Loan cost amortization 1,455 794 2,516 3,338 3,669 4,022 2,389 ------------------------------------------------------------------------------------ Earnings $(151,553) $ (8,946) $(837,515) $ 120,467 $ 287,313 $ 542,492 $ 50,635 ==================================================================================== Interest expense $ 18,550 $ 17,448 $ 68,249 $ 81,052 $ 86,256 $ 98,321 $ 51,650 Capitalized interest 12,935 5,087 6,470 3,356 2,452 4,719 2,264 Bond discount amortization (a) -- -- -- -- -- -- -- Loan cost amortization 1,455 794 2,516 3,338 3,669 4,022 2,389 ------------------------------------------------------------------------------------ Fixed Charges $ 32,940 $ 23,329 $ 77,235 $ 87,746 $ 92,377 $ 107,062 $ 56,303 ==================================================================================== Preferred Stock Dividends Preferred Dividend Requirements $ -- $ -- $ 12,077 $ 16,711 $ 8,484 $ 2,050 $ 5,062 Ratio of income before provision for taxes to Net Income (b) -- -- N/A 1.05 N/A 1.66 N/A ------------------------------------------------------------------------------------ Subtotal - Preferred Dividends $ -- $ -- $ 12,077 $ 17,597 $ 8,484 $ 3,411 $ 5,062 Combined Fixed Charges and Preferred Dividends $ 32,940 $ 23,329 $ 89,312 $ 105,343 $ 100,861 $ 110,473 $ 61,365 Ratio of Earnings to Fixed Charges -- -- -- 1.4x 3.1x 5.1x -- Insufficient coverage $ 184,493 $ 32,275 $ 914,750 -- -- -- $ 5,668 Ratio of Earnings to Combined Fixed Charges and Preferred Dividends -- -- -- 1.1x 2.8x 4.9x -- Insufficient coverage $ 184,493 $ 32,275 $ 926,827 -- -- -- $ 10,730 (a) Bond discount excluded since it is included in interest expense. (b) Represents income (loss) before income taxes and extraordinary item divided by income (loss) before extraordinary item, which adjusts dividends on preferred stock to a pre-tax basis. Page 1