1 - -------------------------------------------------------------------------------- UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-K [X] Annual Report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 For the Fiscal Year Ended December 31, 1998 [ ] Transition Report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 COMMISSION FILE NO. 1-13726 CHESAPEAKE ENERGY CORPORATION (Exact Name of Registrant as Specified in Its Charter) OKLAHOMA 73-1395733 (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification No.) 6100 NORTH WESTERN AVENUE OKLAHOMA CITY, OKLAHOMA 73118 (Address of principal executive offices) (Zip Code) (405) 848-8000 Registrant's telephone number, including area code Securities registered pursuant to Section 12(b) of the Act: <TABLE> <CAPTION> NAME OF EACH EXCHANGE TITLE OF EACH CLASS ON WHICH REGISTERED -------------------------------------------- ------------------------- <S> <C> Common Stock, par value $.01 New York Stock Exchange 7.875% Senior Notes due 2004 New York Stock Exchange 9.625% Senior Notes due 2005 New York Stock Exchange 9.125% Senior Notes due 2006 New York Stock Exchange 8.5% Senior Notes due 2012 New York Stock Exchange 7% Cumulative Convertible Preferred Stock, par value $.01 New York Stock Exchange </TABLE> Securities registered pursuant to Section 12(g) of the Act: NONE Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. YES [X] NO [ ] Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [X] The aggregate market value of Common Stock held by non-affiliates on March 26, 1999 was $103,439,199. At such date, there were 96,720,308 shares of Common Stock issued and outstanding. DOCUMENTS INCORPORATED BY REFERENCE PORTIONS OF THE REGISTRANT'S DEFINITIVE PROXY STATEMENT FOR THE 1999 ANNUAL MEETING OF SHAREHOLDERS ARE INCORPORATED BY REFERENCE IN PART III - --------------------------------------------------------------------------------
2 PART I ITEM 1. BUSINESS GENERAL Chesapeake Energy Corporation ("Chesapeake" or the "Company") is an independent oil and gas company primarily engaged in the exploration, acquisition, development and production of onshore natural gas reserves in the United States and Canada. Chesapeake began operations in 1989, completed an initial public offering in 1993, and trades on the New York Stock Exchange under the symbol CHK. The Company's principal offices are located at 6100 North Western Avenue, Oklahoma City, Oklahoma 73118 (telephone 405/848-8000). Chesapeake currently owns interests in approximately 5,300 producing oil and gas wells concentrated in three primary operating areas: the Mid-Continent region consisting of Oklahoma, southwestern Kansas and the Texas Panhandle; the Gulf Coast region consisting primarily of the Austin Chalk Trend in Texas and Louisiana and the Tuscaloosa Trend in Louisiana; and the Helmet area of northeastern British Columbia. During 1998 the Company produced 130.3 Bcfe, of which 72% was natural gas, making Chesapeake one of the top 20 public independent oil and gas companies in the United States as measured by production. The following table sets forth the Company's estimated proved reserves, the related present value (discounted at 10%) of the proved reserves (based on weighted average prices at December 31, 1998 of $10.48 per barrel of oil and $1.68 per Mcf of gas), and the estimated capital expenditures required to develop the Company's proved undeveloped reserves at December 31, 1998: <TABLE> <CAPTION> ESTIMATED PERCENT PRESENT CAPEX TO GAS OF VALUE DEVELOP OIL GAS EQUIVALENT PROVED (DISC. @10%) PUD'S (MBBL) (MMCF) (MMCFE) RESERVES ($ IN 000'S) ($ IN 000'S) ------------ ------------ ------------ ------------ ------------ ------------ <S> <C> <C> <C> <C> <C> <C> Mid-Continent ........... 11,009 558,754 624,811 57% $ 347,937 $ 72,398 Canada .................. 33 231,773 231,969 21 156,843 28,298 Gulf Coast .............. 3,836 128,419 151,434 14 111,135 34,120 Other areas ............. 7,715 36,845 83,134 8 45,076 9,674 ------------ ------------ ------------ ------------ ------------ ------------ Total ............... 22,593 955,791 1,091,348 100% $ 660,991 $ 144,490 ============ ============ ============ ============ ============ ============ </TABLE> From inception through mid-1997, Chesapeake's primary business strategy was growth through the drillbit. In 1997, however, disappointing drilling results in the Louisiana Austin Chalk Trend, combined with the industry's rapidly escalating drilling costs and falling oil prices, caused management to change the Company's business strategy. As a result of this change, in late 1997 and 1998 the Company significantly reduced its capital expenditures for exploration drilling and acreage acquisition and focused on the acquisition of long-lived natural gas properties in the Mid-Continent and Canada that contain numerous low risk development opportunities. During 1998, the Company acquired approximately 750 Bcfe primarily in eight separate transactions. The total consideration given for the acquisitions was 30.8 million shares of Company common stock, $280 million in cash, the assumption of $205 million in debt, and the incurrence of approximately $20 million of other acquisition related costs. The oil and gas industry is characterized by volatile product prices. During late 1998, inflation-adjusted prices for oil reached lows not seen in 50 years. Also, a second consecutive mild winter and the resulting high inventory of natural gas in storage have caused gas prices to fall. These low oil and gas prices, combined with the Company's high level of indebtedness, have caused the Company to focus on decreasing operating and general and administrative costs and reducing drilling capital expenditures to a level that can be financed from operating cash flow, including proceeds from the sale of non-core, low-value oil properties. The Company's strategy for 1999 is to maintain appropriate liquidity levels while concentrating on further developing its core natural gas assets. 2
3 DRILLING ACTIVITY The following table sets forth the wells drilled by the Company during the periods indicated. In the table, "gross" refers to the total wells in which the Company has a working interest and "net" refers to gross wells multiplied by the Company's working interest therein. <TABLE> <CAPTION> SIX MONTHS YEAR ENDED ENDED YEAR ENDED JUNE 30, DECEMBER 31, DECEMBER 31, ----------------------------------------- 1998 1997 1997 1996 ------------------- ------------------- ------------------- ------------------- GROSS NET GROSS NET GROSS NET GROSS NET -------- -------- -------- -------- -------- -------- -------- -------- <S> <C> <C> <C> <C> <C> <C> <C> <C> Development: Productive .......... 169 97.5 55 24.4 90 55.0 111 49.5 Non-productive ...... 10 5.1 1 0.3 2 0.2 4 1.6 -------- -------- -------- -------- -------- -------- -------- -------- Total ............... 179 102.6 56 24.7 92 55.2 115 51.1 ======== ======== ======== ======== ======== ======== ======== ======== Exploratory: Productive .......... 47 23.7 28 15.5 71 46.1 29 16.5 Non-productive ...... 16 8.9 2 0.9 8 5.7 4 1.4 -------- -------- -------- -------- -------- -------- -------- -------- Total ............... 63 32.6 30 16.4 79 51.8 33 17.9 ======== ======== ======== ======== ======== ======== ======== ======== </TABLE> Included in the above table for 1998, the Company drilled 11 (3.6 net) productive development wells and one (.4 net) non-productive development wells in Canada. Also during 1998, the Company drilled one (.3 net) productive exploratory wells and seven (2.1 net) non-productive exploratory wells in Canada. WELL DATA At December 31, 1998, the Company had interests in 5,304 (2,405 net) producing wells, of which 219 (96 net) were classified as primarily oil producing wells and 5,085 (2,309 net) were classified as primarily gas producing wells. VOLUMES, REVENUE, PRICES AND PRODUCTION COSTS The following table sets forth certain information regarding the production volumes, revenue, average prices received and average production costs associated with the Company's sale of oil and gas for the periods indicated: <TABLE> <CAPTION> SIX MONTHS YEAR ENDED ENDED YEAR ENDED JUNE 30, DECEMBER 31, DECEMBER 31, ------------------------------- 1998 1997 1997 1996 -------------- -------------- -------------- -------------- <S> <C> <C> <C> <C> NET PRODUCTION: Oil (MBbl) .................................. 5,976 1,857 2,770 1,413 Gas (MMcf) .................................. 94,421 27,326 62,005 51,710 Gas equivalent (MMcfe) ...................... 130,277 38,468 78,625 60,190 OIL AND GAS SALES ($ IN 000'S): Oil ......................................... $ 75,877 $ 34,523 $ 57,974 $ 25,224 Gas ......................................... 181,010 61,134 134,946 85,625 -------------- -------------- -------------- -------------- Total oil and gas sales ............. $ 256,887 $ 95,657 $ 192,920 $ 110,849 ============== ============== ============== ============== AVERAGE SALES PRICE: Oil ($ per Bbl) ............................. $ 12.70 $ 18.59 $ 20.93 $ 17.85 Gas ($ per Mcf) ............................. $ 1.92 $ 2.24 $ 2.18 $ 1.66 Gas equivalent ($ per Mcfe) ................. $ 1.97 $ 2.49 $ 2.45 $ 1.84 OIL AND GAS COSTS ($ PER Mcfe): Production expenses and taxes ............... $ .45 $ .27 $ .19 $ .14 General and administrative .................. $ .15 $ .15 $ .11 $ .08 Depreciation, depletion and amortization of oil and gas properties....................... $ 1.13 $ 1.57 $ 1.31 $ .85 </TABLE> Included in the above table are the results of Canadian operations during 1998. The average sales price for the Company's Canadian gas production was $1.03 during 1998 and the Canadian production expenses and taxes were $0.24 per Mcf. 3
4 DEVELOPMENT, EXPLORATION AND ACQUISITION EXPENDITURES The following table sets forth certain information regarding the costs incurred by the Company in its development, exploration and acquisition activities during the periods indicated: <TABLE> <CAPTION> SIX MONTHS YEAR ENDED ENDED YEAR ENDED JUNE 30, DECEMBER 31, DECEMBER 31, ---------------------------- 1998 1997 1997 1996 ------------- ------------ ------------ ------------ ($ IN THOUSANDS) <S> <C> <C> <C> <C> Development costs ................................ $ 150,537 $ 120,628 $ 187,736 $ 138,188 Exploration costs ................................ 68,672 40,534 136,473 39,410 Acquisition costs: Unproved properties ............................ 26,369 25,516 140,348 138,188 Proved properties .............................. 740,280 39,245 -- 24,560 Sales of oil and gas properties .................. (15,712) -- -- -- Capitalized internal costs ....................... 5,262 2,435 3,905 1,699 Proceeds from sale of leasehold, equipment and other .......................................... (296) (1,861) (3,095) (6,167) ------------- ------------ ------------ ------------ Total .................................. $ 975,112 $ 226,497 $ 465,367 $ 335,878 ============= ============ ============ ============ </TABLE> ACREAGE The following table sets forth as of December 31, 1998 the gross and net acres of both developed and undeveloped oil and gas leases which the Company holds. "Gross" acres are the total number of acres in which the Company owns a working interest. "Net" acres refer to gross acres multiplied by the Company's fractional working interest. Acreage numbers are stated in thousands and do not include options for additional leasehold held by the Company, but not yet exercised. <TABLE> <CAPTION> TOTAL DEVELOPED DEVELOPED UNDEVELOPED AND UNDEVELOPED ------------------- ------------------- ------------------- GROSS NET GROSS NET GROSS NET -------- -------- -------- -------- -------- -------- <S> <C> <C> <C> <C> <C> <C> Mid-Continent ......... 1,576 621 835 304 2,411 925 Gulf Coast ............ 451 280 1,333 1,084 1,784 1,364 Canada ................ 82 32 569 233 651 265 Other areas ........... 60 30 1,134 683 1,194 713 -------- -------- -------- -------- -------- -------- Total ....... 2,169 963 3,871 2,304 6,040 3,267 ======== ======== ======== ======== ======== ======== </TABLE> MARKETING The Company's oil production is sold under market sensitive or spot price contracts. The Company's natural gas production is sold to purchasers under varying percentage-of-proceeds and percentage-of-index contracts. By the terms of these contracts, the Company receives a percentage of the resale price received by the purchaser for sales of residue gas and natural gas liquids recovered after gathering and processing the Company's gas. The residue gas and natural gas liquids sold by these purchasers are sold primarily based on spot market prices. The revenue received by the Company from the sale of natural gas liquids is included in natural gas sales. During 1998, the following two customers individually accounted for 10% or more of the Company's total oil and gas sales: <TABLE> <CAPTION> PERCENT OF OIL AMOUNT AND GAS ($ IN THOUSANDS) SALES ---------------- -------------- <S> <C> <C> Koch Oil Company............................................................. $ 30,564 12% Aquila Southwest Pipeline Corporation........................................ $ 28,946 11% </TABLE> Management believes that the loss of either of the above customers would not have a material adverse effect on the Company's results of operations or its financial position. Chesapeake Energy Marketing, Inc. ("CEMI"), a wholly-owned subsidiary, provides oil and natural gas marketing services, including commodity price structuring, contract administration and nomination services for the Company, its partners and other oil and natural gas producers in geographical areas in which the Company is active. 4
5 HEDGING ACTIVITIES Periodically the Company utilizes hedging strategies to hedge the price of a portion of its future oil and gas production. These strategies include (i) swap arrangements that establish an index-related price above which the Company pays the counterparty and below which the Company is paid by the counterparty, (ii) the purchase of index-related puts that provide for a "floor" price below which the counterparty pays the Company the amount by which the price of the commodity is below the contracted floor, (iii) the sale of index-related calls that provide for a "ceiling" price above which the Company pays the counterparty the amount by which the price of the commodity is above the contracted ceiling, and (iv) basis protection swaps, which are arrangements that guarantee the price differential of oil or gas from a specified delivery point or points. Results from commodity hedging transactions are reflected in oil and gas sales to the extent related to the Company's oil and gas production. The Company only enters into commodity hedging transactions related to the Company's oil and gas production volumes or CEMI's physical purchase or sale commitments. Gains or losses on crude oil and natural gas hedging transactions are recognized as price adjustments in the months of related production. As of December 31, 1998, the Company had the following natural gas swap arrangements designed to hedge a portion of the Company's domestic gas production for periods after December 1998: <TABLE> <CAPTION> NYMEX-INDEX VOLUME STRIKE PRICE MONTHS (MMBTU) (PER MMBTU) - ------ ------------- ------------- <S> <C> <C> February 1999.................................................................... 4,300,000 $1.968 March 1999....................................................................... 4,600,000 1.968 April 1999....................................................................... 4,500,000 1.968 May 1999......................................................................... 4,600,000 1.968 June 1999........................................................................ 1,200,000 1.950 July 1999........................................................................ 1,240,000 1.950 August 1999...................................................................... 1,240,000 1.950 September 1999................................................................... 1,200,000 1.950 </TABLE> During 1998, the Company closed transactions for natural gas previously hedged for the period April 1999 through November 1999 for net proceeds of $0.5 million. Subsequent to December 31, 1998, the Company entered into additional natural gas swap arrangements for 6,100,000 MMBtu at a strike price of $1.875 for the period from June 1999 through September 1999. Such swap arrangements, along with those listed above and other miscellaneous transactions, were closed as of March 15, 1999, resulting in net proceeds of $4.7 million. As of December 31, 1998, the Company had the following natural gas swap arrangements designed to hedge a portion of the Company's Canadian gas production for periods after December 1998: <TABLE> <CAPTION> INDEX-STRIKE VOLUME PRICE MONTHS (MMBTU) (PER MMBTU) - ------ ------------- ------------- <S> <C> <C> January 1999..................................................................... 589,000 $1.60 February 1999.................................................................... 532,000 1.60 March 1999....................................................................... 589,000 1.60 April 1999....................................................................... 570,000 1.60 May 1999......................................................................... 589,000 1.60 June 1999........................................................................ 570,000 1.60 July 1999........................................................................ 589,000 1.60 August 1999...................................................................... 589,000 1.60 September 1999................................................................... 570,000 1.60 </TABLE> If the swap arrangements listed above had been settled on December 31, 1998, the Company would have incurred a loss of $0.8 million. 5
6 As of December 31, 1998, the Company had the following oil swap arrangements for periods after December 1998: <TABLE> <CAPTION> NYMEX HEATING OIL MINUS MONTHLY NYMEX CRUDE OIL VOLUME INDEX STRIKE PRICE MONTHS (BBLS) (PER BBL) - ------ --------------- ---------------- <S> <C> <C> January 1999............................................................. 217,000 $ 2.957 February 1999............................................................ 196,000 2.957 March 1999............................................................... 155,000 2.900 </TABLE> If the swap arrangements listed above had been settled on December 31, 1998, the Company would have incurred a loss of $0.2 million. Subsequent to December 31, 1998, the Company settled the swap arrangements listed above for the periods of January 1999 and February 1999 resulting in a $0.4 million loss. In addition to commodity hedging transactions related to the Company's oil and gas production, CEMI periodically enters into various hedging transactions designed to hedge against physical purchase and sale commitments made by CEMI. Gains or losses on these transactions are recorded as adjustments to oil and gas marketing sales in the consolidated statements of operations and are not considered by management to be material. The Company also utilizes hedging strategies to manage fixed-interest rate exposure. Through the use of a swap arrangement, the Company believes it can benefit from stable or falling interest rates and reduce its current interest expense. For the year ended December 31, 1998, the Company's interest rate swap resulted in a $0.7 million reduction of interest expense. RISK FACTORS Substantial Debt Levels Could Affect Operations. As of December 31, 1998, we had long-term indebtedness of $920 million and short-term bank indebtedness of $25 million. Additionally, the Company had a working capital deficit of $13 million and stockholders' equity was a deficit of $249 million. Our ability to meet our debt service requirements throughout the life of the senior notes and our ability to meet our preferred stock obligations will depend on our future performance, which will be subject to oil and gas prices, our production levels of oil and gas, general economic conditions, and financial, business and other factors affecting our operations. Our level of indebtedness may have the following effects on our future operations: o a substantial portion of our cash flow from operations may be dedicated to the payment of interest on indebtedness and will not be available for other purposes, o restrictions in our debt instruments limit our ability to borrow additional funds or to dispose of assets and may affect our flexibility in planning for, and reacting to, changes in the energy industry, and o our ability to obtain additional capital in the future may be impaired. The short-term indebtedness described above was incurred under our commercial bank facility which matures in August 1999. Although we believe this facility will be renewed, we can offer no assurances that we will be able to renew the bank facility on favorable terms. As a result of our high level of indebtedness and poor conditions in the energy industry, Standard & Poor's Corporation and Moody's Investors Service, in late 1998, reduced the credit ratings on our senior notes to "B" and "B3", respectively. These ratings remain under credit review with negative implications. Low credit ratings could negatively impact our ability to access capital markets. 6
7 The Volatility of Oil and Gas Prices Creates Uncertainties. Our revenues, operating results and future rate of growth are highly dependent on the prices we receive for our oil and gas. Historically, the markets for oil and gas have been volatile and may continue to be volatile in the future. Various factors which are beyond our control will affect prices of oil and gas. These factors include: o worldwide and domestic supplies of oil and gas, o the ability of the members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls, o political instability or armed conflict in oil-producing regions, o the price and level of foreign imports, o the level of consumer demand, o the price and availability of alternative fuels, o the availability of pipeline capacity, o weather conditions, and o domestic and foreign governmental regulations and taxes. We are unable to predict the long-term effects of these and other conditions on the prices of oil and gas. Lower oil and gas prices may reduce the amount of oil and gas we produce, which may adversely affect our revenues and operating income. Because our 1999 business strategy is to generally match our capital expenditures for drilling activities to cash flow from operations, significant reductions in oil and gas prices may require us to reduce our capital expenditures. Reducing drilling will make it more difficult for us to replace the reserves we produce. We Must Replace Reserves to Sustain Production. As is customary in the oil and gas exploration and production industry, our future success depends largely upon our ability to find, develop or acquire additional oil and gas reserves that are economically recoverable. Unless we replace the reserves we produce through successful development, exploration or acquisition, our proved reserves will decline. Approximately 30% by volume, or 22% by value, of our total estimated proved reserves at December 31, 1998 were undeveloped. By their nature, undeveloped reserves are less certain. Recovery of such reserves will require significant capital expenditures and successful drilling operations. We cannot assure that the Company can successfully find and produce reserves economically in the future. Significant Capital Expenditures Will be Required to Exploit Reserves. We have made and intend to make substantial capital expenditures in connection with the exploration, development and production of our oil and gas properties. Historically, we have funded our capital expenditures through a combination of internally generated funds, equity issuances and long-term debt financing arrangements and sale of non-core assets. From time to time, we have used short-term bank debt, generally as a working capital facility. Future cash flows are subject to a number of variables, such as the level of production from existing wells, prices of oil and gas, and our success in developing and producing new reserves and in selling non-core assets. If revenue were to decrease as a result of lower oil and gas prices or decreased production, and our access to capital were limited, we would have a reduced ability to replace our reserves. If our cash flow from operations is not sufficient to fund our capital expenditure budget, there can be no assurance that additional debt or equity financing will be available to meet these requirements. We May Have Additional Full-Cost Ceiling Writedowns if Oil and Gas Prices Decline Further or if Drilling Results are Unfavorable. The Company reported full-cost ceiling writedowns of $826 million, $110 million, and $236 million during the year ended December 31, 1998, the six month transition period ended December 31, 1997 (the "Transition Period"), and the fiscal year ended June 30, 1997, respectively. These writedowns were caused by significant declines in oil and gas prices during all three periods and by poor drilling results in 1997 and during the Transition Period. Additionally, significant declines in prices can cause proved undeveloped reserves to become uneconomic, and long-lived production to become "economically truncated", further reducing proved reserves and increasing any writedown. Such economic truncation resulted in the Company's reserves being approximately 100 Bcfe less at 7
8 December 31, 1998 than they would have been using pricing in effect as of December 31, 1997. The Company's reserve values were calculated using weighted average prices at December 31, 1998 of $10.48 per barrel of oil and $1.68 per Mcf of natural gas. If prices in future periods are below the prices used at December 31, 1998, future impairment charges will likely be incurred. Although the Company has taken steps to reduce drilling risk, reduce operating costs, and reduce investment in unproved leasehold, these steps may not be sufficient to enhance future economic results or prevent additional leasehold impairment and full-cost ceiling writedowns, which are highly dependent on future oil and gas prices. Drilling and Oil and Gas Operations Present Unique Risks. Drilling activities are subject to many risks, including well blowouts, cratering, uncontrollable flows of oil, natural gas or well fluids, fires, formations with abnormal pressures, pollution, releases of toxic gases and other environmental hazards and risk, any of which could result in substantial losses. In addition, we incur the risk that we will not encounter any commercially productive reservoirs through our drilling operations. We cannot assure you that the new wells we drill will be productive or that we will recover all or any portion of our investment in wells drilled. Drilling for oil and gas may involve unprofitable efforts, not only from dry wells, but from wells that are productive but do not produce enough reserves to return a profit after drilling, operating and other costs. Existing Debt Covenants Restrict Our Operations. The indentures which govern our long-term debt contain covenants which restrict our ability, and the ability of our subsidiaries other than CEMI, to engage in the following activities: o incurring additional debt, o creating liens, o paying dividends and making other restricted payments, o merging or consolidating with any other entity, o selling, assigning, transferring, leasing or otherwise disposing of all or substantially all of our assets, and o guaranteeing any indebtedness. At December 31, 1998, the Company did not meet a debt incurrence test contained in two of the senior note indentures. Thus, we will be unable to incur unsecured non-bank debt until there is significant improvement in oil and gas prices and/or our production levels. Additionally, the Company will not be able to resume the payment of dividends on its common and preferred stock until it meets the debt incurrence test. Canadian Operations Present the Risks Associated with Conducting Business Outside the U.S. A portion of our business is conducted in Canada. You may review the amounts of revenue, operating losses and identifiable assets attributable to our Canadian operations in Note 8 of the Notes to our Consolidated Financial Statements in Item 8. Also, Note 11 of the Consolidated Financial Statements provides disclosures about our Canadian oil and gas producing activities. Our operations in Canada are subject to the risks associated with operating outside of the United States. These risks include the following: o adverse local political or economic developments, o exchange controls, o currency fluctuations, o royalty and tax increases, o retroactive tax claims, o negotiations of contracts with governmental entities, and o import and export regulations. In addition, in the event of a dispute, we may be required to litigate the dispute in Canadian courts since we may not be able to sue foreign persons in a United States court. 8
9 Pending Legal Proceedings Could Have A Material Adverse Effect. The Company is a defendant in two purported class actions based on federal and state securities fraud claims. In addition, we are defending claims of patent infringement in another pending action. While no prediction can be made as to the outcome of these matters or the amount of damages that might be awarded, if any, an adverse result in any of them could be material to our financial results. See Item 3. Legal Proceedings. The Loss of Either the CEO or the COO Could Adversely Affect Operations. Our operations are dependent upon our Chief Executive Officer, Aubrey K. McClendon, and our Chief Operating Officer, Tom L. Ward. The unexpected loss of the services of either of these executive officers could have a detrimental effect on our operations. The Company maintains $20 million key man life insurance policies on the life of each of Messrs. McClendon and Ward. Transactions with Executive Officers May Create Conflicts of Interest. Messrs. McClendon and Ward have rights to participate in wells we drill during any succeeding quarter, and they participated in every well we have drilled through December 31, 1998. As a result of their participation, they routinely have significant accounts payable to the Company for joint interest billings. As of December 31, 1998, Messrs. McClendon and Ward had payables to the Company of $2.8 million and $2.4 million, respectively, in connection with such participation. Additionally, Messrs. McClendon and Ward have loans due on December 31, 1999 to CEMI in the principal amounts of $4.9 million and $5.0 million (as of December 31, 1998), respectively. Such loans, which were first made in July 1998, are collateralized and carry an annual interest rate of 9.125%. As of March 30, 1999, Messrs. McClendon and Ward's loans have been reduced to $4.3 million and $4.6 million, respectively. The existence of these loans and the rights to participate in wells we drill could present a conflict of interest with respect to Messrs. McClendon and Ward. The Ownership of A Significant Percentage of Stock by Insiders Could Influence the Outcome of Shareholder Votes. At March 26, 1999, our Board of Directors and senior management beneficially owned an aggregate of 27,923,997 shares of common stock (including outstanding vested options), which represented approximately 28% of our outstanding shares. The ownership of Messrs. McClendon and Ward and their children's trusts accounted for 25% of the outstanding common stock. As a result, Messrs. McClendon and Ward, together with other officers and directors of the Company, are in a position to significantly influence matters requiring the vote or consent of our shareholders. The Company Could be Adversely Affected if Our Computer Systems or Those of Our Vendors Are Not Year 2000 Compliant. Year 2000 issues exist when dates are recorded in computers using two digits, rather than four, and are then used for arithmetic operations, comparisons or sorting. A two-digit recording may recognize a date using "00" as 1900 rather than 2000, which could cause our computer systems to perform inaccurate computations. Year 2000 issues relate not only to our systems, but also to those used by our suppliers. We anticipate that system replacements and modifications will resolve any Year 2000 issues that may exist with our suppliers or their suppliers. However, we cannot guarantee that such replacements or modifications will be completed successfully or on time and, as a result, any failure to complete such modifications on time could materially affect our financial and operating results in a negative way. Please read the additional discussion regarding the Year 2000 issue and the potential impact on our business in the section entitled "Management's Discussion and Analysis of Financial Condition and Results of Operations - Year 2000" later in this Form 10-K for additional information. 9
10 REGULATION General Numerous departments and agencies, federal, state and local, issue rules and regulations binding on the oil and gas industry, some of which carry substantial penalties for failure to comply. The regulatory burden on the oil and gas industry increases the Company's cost of doing business and, consequently, affects its profitability. Exploration and Production The Company's operations are subject to various types of regulation at the federal, state and local levels. Such regulation includes requiring permits for the drilling of wells, maintaining bonding requirements in order to drill or operate wells and regulating the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, the plugging and abandoning of wells and the disposal of fluids used or obtained in connection with operations. The Company's operations are also subject to various conservation regulations. These include the regulation of the size of drilling and spacing units and the density of wells which may be drilled and the unitization or pooling of oil and gas properties. In this regard, some states (such as Oklahoma) allow the forced pooling or integration of tracts to facilitate exploration while other states (such as Texas) rely on voluntary pooling of lands and leases. In areas where pooling is voluntary, it may be more difficult to form units and, therefore, more difficult to develop a prospect if the operator owns less than 100% of the leasehold. In addition, state conservation laws establish maximum rates of production from oil and gas wells, generally prohibit the venting or flaring of gas and impose certain requirements regarding the ratability of production. The effect of these regulations is to limit the amount of oil and gas the Company can produce from its wells and to limit the number of wells or the locations at which the Company can drill. The extent of any impact on the Company of such restrictions cannot be predicted. Environmental and Occupational Regulation General. The Company's activities are subject to existing federal, state and local laws and regulations governing environmental quality and pollution control. It is anticipated that, absent the occurrence of an extraordinary event, compliance with existing federal, state and local laws, rules and regulations concerning the protection of the environment and human health will not have a material effect upon the operations, capital expenditures, earnings or the competitive position of the Company. The Company cannot predict what effect additional regulation or legislation, enforcement policies thereunder and claims for damages for injuries to property, employees, other persons and the environment resulting from the Company's operations could have on its activities. Activities of the Company with respect to the exploration, development and production of oil and natural gas are subject to stringent environmental regulation by state and federal authorities including the United States Environmental Protection Agency ("EPA"). Such regulation has increased the cost of planning, designing, drilling, operating and in some instances, abandoning wells. In most instances, the regulatory requirements relate to the handling and disposal of drilling and production waste products and waste created by water and air pollution control procedures. Although the Company believes that compliance with environmental regulations will not have a material adverse effect on operations or earnings, risks of substantial costs and liabilities are inherent in oil and gas operations, and there can be no assurance that significant costs and liabilities, including criminal penalties, will not be incurred. Moreover, it is possible that other developments, such as stricter environmental laws and regulations, and claims for damages for injuries to property or persons resulting from the Company's operations could result in substantial costs and liabilities. Waste Disposal. The Company currently owns or leases, and has in the past owned or leased, numerous properties that for many years have been used for the exploration and production of oil and gas. Although the Company has utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons or other wastes may have been disposed of or released on or under the properties owned or leased by the Company or on or under other locations where such wastes have been taken for disposal. In addition, many of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons or other wastes was not under the Company's control. State and federal laws applicable to oil and natural gas wastes and properties have gradually become more strict. Under such laws, the Company could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators) 10
11 or property contamination (including groundwater contamination) or to perform remedial plugging operations to prevent future contamination. The Company generates wastes, including hazardous wastes, that are subject to the federal Resource Conservation and Recovery Act ("RCRA") and comparable state statutes. The EPA and various state agencies have limited the disposal options for certain hazardous and nonhazardous wastes and are considering the adoption of stricter disposal standards for nonhazardous wastes. Furthermore, certain wastes generated by the Company's oil and natural gas operations that are currently exempt from treatment as hazardous wastes may in the future be designated as hazardous wastes, and therefore be subject to considerably more rigorous and costly operating and disposal requirements. Superfund. The Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA"), also known as the "Superfund" law, imposes liability, without regard to fault or the legality of the original conduct, on certain classes of persons with respect to the release of a "hazardous substance" into the environment. These persons include the owner and operator of a site and persons that disposed of or arranged for the disposal of the hazardous substances found at a site. CERCLA also authorizes the EPA and, in some cases, third parties to take actions in response to threats to the public health or the environment and to seek to recover from responsible classes of persons the costs of such action. In the course of its operations, the Company may have generated and may generate wastes that fall within CERCLA's definition of "hazardous substances". The Company may also be or have been an owner of sites on which "hazardous substances" have been released. The Company may be responsible under CERCLA for all or part of the costs to clean up sites at which such wastes have been released. To date, however, neither the Company nor, to its knowledge, its predecessors or successors have been named a potentially responsible party under CERCLA or similar state superfund laws affecting property owned or leased by the Company. Air Emissions. The operations of the Company are subject to local, state and federal regulations for the control of emissions of air pollution. Legal and regulatory requirements in this area are increasing, and there can be no assurance that significant costs and liabilities will not be incurred in the future as a result of new regulatory developments. In particular, regulations promulgated under the Clean Air Act Amendments of 1990 may impose additional compliance requirements that could affect the Company's operations. However, it is impossible to predict accurately the effect, if any, of the Clean Air Act Amendments on the Company at this time. The Company may in the future be subject to civil or administrative enforcement actions for failure to comply strictly with air regulations or permits. These enforcement actions are generally resolved by payment of monetary fines and correction of any identified deficiencies. Alternatively, regulatory agencies could require the Company to forego construction or operation of certain air emission sources. OSHA. The Company is subject to the requirements of the federal Occupational Safety and Health Act ("OSHA") and comparable state statutes. The OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act and similar state statutes require the Company to organize information about hazardous materials used, released or produced in its operations. Certain of this information must be provided to employees, state and local governmental authorities and local citizens. The Company is also subject to the requirements and reporting set forth in OSHA workplace standards. The Company provides safety training and personal protective equipment to its employees. OPA and Clean Water Act. Federal regulations require certain owners or operators of facilities that store or otherwise handle oil, such as the Company, to prepare and implement spill prevention control plans, countermeasure plans and facilities response plans relating to the possible discharge of oil into surface waters. The Oil Pollution Act of 1990 ("OPA") amends certain provisions of the federal Water Pollution Control Act of 1972, commonly referred to as the Clean Water Act ("CWA"), and other statutes as they pertain to the prevention of and response to oil spills into navigable waters. The OPA subjects owners of facilities to strict joint and several liability for all containment and cleanup costs and certain other damages arising from a spill, including, but not limited to, the costs of responding to a release of oil to surface waters. The CWA provides penalties for any discharges of petroleum product in reportable quantities and imposes substantial liability for the costs of removing a spill. State laws for the control of water pollution also provide varying civil and criminal penalties and liabilities in the case of releases of 11
12 petroleum or its derivatives into surface waters or into the ground. Regulations are currently being developed under OPA and state laws concerning oil pollution prevention and other matters that may impose additional regulatory burdens on the Company. In addition, the CWA and analogous state laws require permits to be obtained to authorize discharges into surface waters or to construct facilities in wetland areas. With respect to certain of its operations, the Company is required to maintain such permits or meet general permit requirements. The EPA has adopted regulations concerning discharges of storm water runoff. This program requires covered facilities to obtain individual permits, participate in a group permit or seek coverage under an EPA general permit. The Company believes that with respect to existing properties it has obtained, or is included under, such permits and with respect to future operations it will be able to obtain, or be included under, such permits, where necessary. Compliance with such permits is not expected to have a material effect on the Company. NORM. Oil and gas exploration and production activities have been identified as generators of concentrations of low-level naturally-occurring radioactive materials ("NORM"). NORM regulations have recently been adopted in several states. The Company is unable to estimate the effect of these regulations, although based upon the Company's preliminary analysis to date, the Company does not believe that its compliance with such regulations will have a material adverse effect on its operations or financial condition. Safe Drinking Water Act. The Company's operations involve the disposal of produced saltwater and other nonhazardous oilfield wastes by reinjection into the subsurface. Under the Safe Drinking Water Act ("SDWA"), oil and gas operators, such as the Company, must obtain a permit for the construction and operation of underground Class II injection wells. To protect against contamination of drinking water, periodic mechanical integrity tests are often required to be performed by the well operator. The Company has obtained such permits for the Class II wells it operates. The Company also has disposed of wastes in facilities other than those owned by the Company which are commercial Class II injection wells. Toxic Substances Control Act. The Toxic Substances Control Act ("TSCA") was enacted to control the adverse effects of newly manufactured and existing chemical substances. Under the TSCA, the EPA has issued specific rules and regulations governing the use, labeling, maintenance, removal from service and disposal of PCB items, such as transformers and capacitors used by oil and gas companies. The Company may own such PCB items but does not believe compliance with TSCA has or will have a material adverse effect on the Company's operations or financial condition. TITLE TO PROPERTIES Title to properties is subject to royalty, overriding royalty, carried, net profits, working and other similar interests and contractual arrangements customary in the oil and gas industry, to liens for current taxes not yet due and to other encumbrances. As is customary in the industry in the case of undeveloped properties, only cursory investigation of record title is made at the time of acquisition. Drilling title opinions are usually prepared before commencement of drilling operations. From time to time, the Company's title to oil and gas properties is challenged through legal proceedings. The Company is routinely involved in litigation involving title to certain of its oil and gas properties, none of which management believes will be materially adverse to the Company, individually or in the aggregate. OPERATING HAZARDS AND INSURANCE The oil and gas business involves a variety of operating risks, including the risk of fire, explosions, blow-outs, pipe failure, abnormally pressured formations and environmental hazards such as oil spills, gas leaks, ruptures or discharges of toxic gases, the occurrence of any of which could result in substantial losses to the Company due to injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory investigation and penalties and suspension of operations. The Company's horizontal and Deep Tuscaloosa drilling activities involve greater risk of mechanical problems than conventional vertical drilling operations. 12
13 The Company maintains a $50 million oil and gas lease operator policy that insures the Company against certain sudden and accidental risks associated with drilling, completing and operating its wells. There can be no assurance that this insurance will be adequate to cover any losses or exposure to liability. The Company also carries comprehensive general liability policies and a $60 million umbrella policy. The Company and its subsidiaries carry workers' compensation insurance in all states in which they operate and a $35 million employment practice liability policy. While the Company believes these policies are customary in the industry, they do not provide complete coverage against all operating risks. EMPLOYEES The Company had 481 full-time employees as of December 31, 1998 and reduced this level to 453 as of March 15, 1999. No employees are represented by organized labor unions. The Company considers its employee relations to be good. FACILITIES The Company owns 13 buildings totaling approximately 86,500 square feet and nine acres of land in an office complex in Oklahoma City that comprise its headquarters' offices. The Company also owns field offices in Lindsay, Waynoka and Weatherford, Oklahoma and leases office space in Garden City, Hays and Wichita, Kansas; Oklahoma City, Oklahoma; Big Lake, College Station, Fritch and Navasota, Texas; Lafayette, Louisiana; and in Calgary, Alberta, Canada. The offices in Garden City, Wichita, College Station and Lafayette have been or will be closed in the near future and the space sub-leased or terminated. GLOSSARY The terms defined in this section are used throughout this Form 10-K. Bcf. Billion cubic feet. Bcfe. Billion cubic feet of gas equivalent. Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in reference to crude oil or other liquid hydrocarbons. Btu. British thermal unit, which is the heat required to raise the temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit. Commercial Well; Commercially Productive Well. An oil and gas well which produces oil and gas in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes. Developed Acreage. The number of acres which are allocated or assignable to producing wells or wells capable of production. Development Well. A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive. Dry Hole; Dry Well. A well found to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well. Exploratory Well. A well drilled to find and produce oil or gas in an unproved area, to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir or to extend a known reservoir. Farmout. An assignment of an interest in a drilling location and related acreage conditional upon the drilling of a well on that location. 13
14 Formation. A succession of sedimentary beds that were deposited under the same general geologic conditions. Full-Cost Pool. The full-cost pool consists of all costs associated with property acquisition, exploration, and development activities for a company using the full-cost method of accounting. Additionally, any internal costs that can be directly identified with acquisition, exploration and development activities are included. Any costs related to production, general corporate overhead or similar activities are not included. Gross Acres or Gross Wells. The total acres or wells, as the case may be, in which a working interest is owned. Horizontal Wells. Wells which are drilled at angles greater than 70 from vertical. MBbl. One thousand barrels of crude oil or other liquid hydrocarbons. MBtu. One thousand Btus. Mcf. One thousand cubic feet. Mcfe. One thousand cubic feet of gas equivalent. MMBbl. One million barrels of crude oil or other liquid hydrocarbons. MMBtu. One million Btus. MMcf. One million cubic feet. MMcfe. One million cubic feet of gas equivalent. Net Acres or Net Wells. The sum of the fractional working interest owned in gross acres or gross wells. Present Value. When used with respect to oil and gas reserves, present value means the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development costs, using prices and costs in effect at the determination date, without giving effect to non-property related expenses such as general and administrative expenses, debt service and future income tax expense or to depreciation, depletion and amortization, discounted using an annual discount rate of 10%. Productive Well. A well that is producing oil or gas or that is capable of production. Proved Developed Reserves. Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Proved Reserves. The estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved Undeveloped Location. A site on which a development well can be drilled consistent with spacing rules for purposes of recovering proved undeveloped reserves. Proved Undeveloped Reserves. Reserves that are expected to be recovered from new wells drilled to known reservoir on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Royalty Interest. An interest in an oil and gas property entitling the owner to a share of oil or gas production free of costs of production. 14
15 Tcf. One trillion cubic feet. Tcfe. One trillion cubic feet of gas equivalent. Undeveloped Acreage. Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and gas regardless of whether such acreage contains proved reserves. Working Interest. The operating interest which gives the owner the right to drill, produce and conduct operating activities on the property and a share of production. 15
16 ITEM 2. PROPERTIES PRIMARY OPERATING AREAS The Company's strategy is to focus its acquisition and development efforts in three areas: (i) the Mid-Continent (consisting of Oklahoma, southwestern Kansas and the Texas Panhandle), (ii) the onshore Gulf Coast in Texas and Louisiana, and (iii) the Helmet area in northeastern British Columbia. In addition, the Company will selectively pursue exploration projects such as the Deep Tuscaloosa in Louisiana and the Deep Wilcox in Wharton County, Texas. Mid-Continent Region. The Company's Mid-Continent proved reserves of 625 Bcfe represented 57% of the Company's total proved reserves as of December 31, 1998 and this area produced 64 Bcfe, or 49% of the Company's 1998 production. During 1998, the Company invested approximately $63 million to drill 165 gross (96.1 net) wells in the Mid-Continent. The Company has budgeted approximately $50 million for the Mid-Continent during 1999, representing approximately 56% of the Company's total budget for exploration and development activities during the year. The Company anticipates the Mid-Continent will contribute approximately 67 Bcfe of production during 1999, or 54% of expected total production. Gulf Coast. The Company's Gulf Coast proved reserves, consisting of the Austin Chalk Trend in Texas and Louisiana and the Tuscaloosa Trend in Louisiana, represented 151 Bcfe or 14% of the Company's total proved reserves as of December 31, 1998. During 1998, the Gulf Coast assets produced 52 Bcfe, or 40% of the Company's total production. The Company anticipates the Gulf Coast will contribute approximately 38 Bcfe of production during 1999, or 31% of expected total production. During 1998, the Company invested approximately $109 million to drill 37 gross (17.8 net) wells in the Gulf Coast. For 1999, the Company has budgeted approximately $6 million for Texas Austin Chalk and Louisiana Austin Chalk drilling and $15 million for Tuscaloosa exploratory drilling activities. In the aggregate, these Gulf Coast expenditures represent approximately 23% of the Company's total budget for exploration and development activities in 1999. Helmet Area. During fiscal 1996 and 1997, the Company began to evaluate the possibility of developing a third core area of operations to complement its activities in the Mid-Continent and Gulf Coast regions. Management believed that the North American gas market would significantly tighten and as a result, Canadian natural gas prices, which have significantly lagged U.S. natural gas prices during the past 15 years, would increase in the future compared to U.S. gas prices. During 1998, the Company entered into two transactions which established a significant presence in a major gas field in northeastern British Columbia. The Company's Canadian proved reserves of 232 Bcfe represented 21% of the Company's total proved reserves at December 31, 1998. During 1998, production from Canada was 8 Bcfe, or 6% of the Company's total production. The Company has budgeted $15 million to drill seven net wells in 1999 and expects production of 20 Bcfe, or 16% of the Company's estimated total production for 1999. OTHER OPERATING AREAS Permian Basin. In 1995 the Company initiated drilling activity in the Permian Basin in the Lovington area of Lea County, New Mexico. In this project, the Company is utilizing 3-D seismic technology to search for prospects that management believes have been overlooked in this portion of the Permian Basin because of inconclusive results provided by traditional 2-D seismic technology. During 1998, the Company drilled seven wells in the Lovington area, four of which were successfully completed and three were unsuccessful. The Company has budgeted approximately $0.8 million to drill one gross (0.8 net) well in this area during 1999. 16
17 Wharton County, Texas. In 1997, the Company acquired approximately 25,000 net acres in Wharton County, Texas. This exploration project is seeking gas production from the shallower Frio and Yegua sands and from the Deep Wilcox at depths of up to 19,000 feet. The Company participated with a 55% interest in a 85,000 acre 3-D seismic program with Coastal Oil & Gas Corporation, Seagull Energy Corporation and other industry partners during 1998 to delineate potential future drillsites in the prospect. During 1998, the Company drilled its first well in the prospect, which was abandoned as a dry hole. Williston Basin. In 1996, the Company began acquiring leasehold in the Williston Basin, located in eastern Montana and western North Dakota, and as of December 31, 1998 owned approximately 0.9 million gross (0.6 million net) acres. During the Transition Period, the Company drilled and successfully completed six wells targeting the Red River formation on the northern portion of its leasehold. During 1998, the Company invested approximately $4.2 million to drill three gross (2.8 net) wells in the Williston Basin. The Company does not plan to drill any wells during 1999 in the Williston Basin unless oil prices increase significantly. OIL AND GAS RESERVES The tables below set forth information as of December 31, 1998 with respect to the Company's estimated net proved reserves, the estimated future net revenue therefrom and the present value thereof at such date. Williamson Petroleum Consultants, Inc., Ryder Scott Company Petroleum Engineers and H.J. Gruy and Associates, Inc. evaluated 63%, 12% and 1%, respectively, of the Company's combined discounted future net revenues from the Company's estimated proved reserves at December 31, 1998. The remaining properties were evaluated internally by the Company's engineers. All estimates were prepared based upon a review of production histories and other geologic, economic, ownership and engineering data developed by the Company. The present value of estimated future net revenue shown is not intended to represent the current market value of the estimated oil and gas reserves owned by the Company. <TABLE> <CAPTION> ESTIMATED PROVED RESERVES OIL GAS TOTAL AS OF DECEMBER 31, 1998 (MBBL) (MMCF) (MMCFE) -------------------------- ------------- ------------- ------------- <S> <C> <C> <C> Proved developed ................................................ 18,036 658,943 767,160 Proved undeveloped .............................................. 4,557 296,848 324,188 ------------- ------------- ------------- Total proved .................................................... 22,593 955,791 1,091,348 ============= ============= ============= </TABLE> <TABLE> <CAPTION> ESTIMATED FUTURE NET REVENUE PROVED PROVED TOTAL AS OF DECEMBER 31, 1998(a) DEVELOPED UNDEVELOPED PROVED -------------------------- ------------- ------------- ------------- ($ IN THOUSANDS) <S> <C> <C> <C> Estimated future net revenue .................................... $ 864,109 $ 344,532 $ 1,208,641 Present value of future net revenue ............................. $ 513,566 $ 147,425 $ 660,991 </TABLE> - ---------- (a) Estimated future net revenue represents estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development costs, using prices and costs in effect at December 31, 1998. The amounts shown do not give effect to non-property related expenses, such as general and administrative expenses, debt service and future income tax expense or to depreciation, depletion and amortization. The prices used in the external and internal reports yield weighted average prices of $10.48 per barrel of oil and $1.68 per Mcf of gas. The future net revenue attributable to the Company's estimated proved undeveloped reserves of $345 million at December 31, 1998, and the $147 million present value thereof, have been calculated assuming that the Company will expend approximately $144 million to develop these reserves. The amount and timing of these expenditures will depend on a number of factors, including actual drilling results, product prices and the availability of capital. No estimates of proved reserves comparable to those included herein have been included in reports to any federal agency other than the Securities and Exchange Commission. The Company's interest used in calculating proved reserves and the estimated future net revenue therefrom was determined after giving effect to the assumed 17
18 maximum participation by other parties to the Company's farmout and participation agreements. The prices used in calculating the estimated future net revenue attributable to proved reserves do not reflect market prices for oil and gas production sold subsequent to December 31, 1998. There can be no assurance that all of the estimated proved reserves will be produced and sold at the assumed prices or that existing contracts will be honored or judicially enforced. There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond the control of the Company. The reserve data set forth herein represent only estimates. Reserve engineering is a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact way, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, estimates made by different engineers often vary. In addition, results of drilling, testing and production subsequent to the date of an estimate may justify revision of such estimates, and such revisions may be material. Accordingly, reserve estimates are often different from the actual quantities of oil and gas that are ultimately recovered. Furthermore, the estimated future net revenue from proved reserves and the present value thereof are based upon certain assumptions, including prices, future production levels and cost, that may not prove correct. Predictions about prices and future production levels are subject to great uncertainty, and the foregoing uncertainties are particularly true as to proved undeveloped reserves, which are inherently less certain than proved developed reserves and which comprise a significant portion of the Company's proved reserves. See Item 1 and Note 11 of Notes to Consolidated Financial Statements included in Item 8 for a description of the Company's primary and other operating areas, production and other information regarding its oil and gas properties. ITEM 3. LEGAL PROCEEDINGS The Company is subject to ordinary routine litigation incidental to its business. In addition, the following matters are pending: Securities Litigation. On January 13, 1998, a consolidated class action complaint styled In re Chesapeake Energy Corporation Securities Litigation was filed in the U.S. District Court for the Western District of Oklahoma. It consolidated 12 pending purported class actions filed in August and September 1997. The action is brought on behalf of purchasers of the Company's common stock and common stock options between January 25, 1996 and June 27, 1997. The defendants are the Company and the following officers and directors: Aubrey K. McClendon, Tom L. Ward, Marcus C. Rowland, Shannon T. Self, Walter C. Wilson, Henry J. Hood, Steven C. Dixon, J. Mark Lester and Ronald A. Lefaive. The complaint alleges violations of Sections 10(b) and 20(a) of the Securities Exchange Act of 1934 and Rule 10b-5 thereunder. The plaintiffs assert that the defendants made material misrepresentations and failed to disclose material facts about the success of the Company's exploration and drilling activities in the Louisiana Trend. The complaint alleges the lack of disclosure artificially inflated the price of the Company's common stock during the period beginning January 25, 1996 and ending on June 27, 1997, when the Company issued a press release announcing disappointing drilling results in the Louisiana Trend and a full-cost ceiling writedown to be reflected in its June 30, 1997 financial statements. The plaintiffs further allege that certain of the named individual defendants sold the Company's common stock during the class period when they knew or should have known adverse nonpublic information. The plaintiffs seek a determination that the suit is a proper class action and damages in an unspecified amount, together with interest and costs of litigation, including attorneys' fees. The Company and the individual defendants believe that these claims are without merit and on March 16, 1998 filed a motion to dismiss. To date, the U.S. District Court has not ruled on this motion. No estimate of loss or range of estimate of loss, if any, can be made at this time. Bayard Drilling Technologies, Inc. ("Bayard"). On July 30, 1998, the plaintiffs in Yuan, et al. v. Bayard, et al. filed an Amended Class Action Complaint in the U.S. District Court for the Western District of Oklahoma alleging violations of Sections 11 and 12 of the Securities Act of 1933 and Section 408 of the Oklahoma Securities Act by the Company and others. The action was brought purportedly on behalf of investors who purchased Bayard common stock in, or traceable to, Bayard's initial public offering in November 1997. The defendants include officers and directors of Bayard who signed the registration statement, selling shareholders (including the Company) and underwriters of the 18
19 offering. Total proceeds of the offering were $254 million, of which the Company received net proceeds of $90 million. In May 1998, two additional purported class actions filed in January and February 1998 in the District Court for Oklahoma County, Oklahoma were dismissed without prejudice pursuant to stipulation of all parties. On May 12, 1998, the plaintiffs in the dismissed cases became co-lead plaintiffs in Yuan v. Bayard, et al. Plaintiffs allege that the Company, which owned 30.1% of Bayard's outstanding common stock prior to the offering, was a controlling person of Bayard. Plaintiffs also allege that the Company had established an interlocking financial relationship with Bayard and was a customer of Bayard's drilling services under allegedly below-market terms. Plaintiffs also note the fact that Messrs. McClendon, Ward and Rowland, executive officers and directors of the Company, were formerly directors of Bayard. Plaintiffs assert that the Bayard prospectus contained material omissions and misstatements relating to (i) the Company's financial "problems" and their impact on Bayard's operating results, (ii) increased costs associated with Bayard's growth strategy, (iii) undisclosed pending related-party transactions between Bayard and third parties other than the Company, (iv) Bayard's planned use of offering proceeds and (v) Bayard's capital expenditures and liquidity. The alleged defective disclosures are claimed to have resulted in a decline in Bayard's share price following the public offering. Plaintiffs seek a determination that the suit is a proper class action and damages in an unspecified amount or rescission, together with interest and costs of litigation, including attorneys' fees. The Company believes the claims against it in this action are without merit. On September 11, 1998, the Company and the other named defendants filed a motion to dismiss. No estimate of loss or range of estimate of loss, if any, can be made at this time. Bayard has subsequently agreed to merge into a wholly-owned, newly created, special purpose subsidiary of Nabors Industries, Inc. UPRC Patent Suit. On October 15, 1996, Union Pacific Resources Company ("UPRC") filed suit against the Company in the U.S. District Court for the Northern District of Texas, Fort Worth Division, alleging (i) infringement and inducing infringement of UPRC's claims to a patent for an invention involving a method of maintaining a borehole in a stratigraphic zone during drilling, (ii) tortious interference with contracts between UPRC and certain of its former employees regarding the confidentiality of proprietary information of UPRC and (iii) misappropriation of such proprietary information. On May 20, 1998, two orders were entered granting the Company summary judgment on several issues. The court ruled as a matter of law that UPRC's tort claims for misappropriation of trade secrets and tortious interference with business relations are barred by the statute of limitations. Further, the court found that UPRC's claim for inducement to infringe its patent for a drillbit steering method is barred as to any wells drilled by the Company prior to August 14, 1995. The only issues remaining in the case involve the validity, potential infringement and value, if any, of UPRC's patent. UPRC's claims against the Company in UPRC v. Chesapeake Energy Corporation, et al. are based on services provided to the Company by a third party vendor controlled by former UPRC employees. UPRC is seeking injunctive relief, damages of an unspecified amount, including actual, enhanced, consequential and punitive damages, interest, costs and attorneys' fees. The Company believes that it has meritorious defenses to UPRC's allegations and has petitioned the court to declare the UPRC patent invalid. Various motions for summary judgment filed by both parties are pending. While no prediction can be made as to the outcome of the matter or the amount of damages that might be awarded, if any, damage estimates have been made in reports of experts filed in the proceeding. Experts for UPRC claim that damages could be as much as $18 million, while Company experts state that the amount should not exceed $25,000, in each case based on the expert's view of a reasonable royalty for use of the patent. The case has been set for trial in June 1999 on the issue of liability. 19
20 ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS Not applicable PART II ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS PRICE RANGE OF COMMON STOCK The common stock trades on the New York Stock Exchange under the symbol "CHK". The following table sets forth, for the periods indicated, the high and low sales prices per share (adjusted for a 2-for-1 stock split on December 31, 1996) of the common stock as reported by the New York Stock Exchange: <TABLE> <CAPTION> COMMON STOCK ----------------- HIGH LOW ------ ------ <S> <C> <C> Fiscal year ended June 30, 1997: First Quarter..................................................................... $34.00 $21.00 Second Quarter.................................................................... 34.13 25.69 Third Quarter..................................................................... 31.50 19.88 Fourth Quarter.................................................................... 22.38 9.25 Transition Period ended December 31, 1997: First Quarter..................................................................... 11.50 6.31 Second Quarter.................................................................... 13.44 6.81 Fiscal year ended December 31, 1998: First Quarter..................................................................... 7.75 5.50 Second Quarter.................................................................... 6.00 3.88 Third Quarter..................................................................... 4.06 1.13 Fourth Quarter.................................................................... 2.63 0.75 </TABLE> At March 26, 1999 there were 1,025 holders of record of common stock and approximately 28,000 beneficial owners. DIVIDENDS The Company paid quarterly dividends of $0.02 per common share from July 1997 to July 1998. In September 1998 the Board of Directors determined that because of low oil and natural gas prices the payment of cash dividends on the common stock should be cancelled. The payment of future cash dividends, if any, will be reviewed periodically by the Board of Directors and will depend upon, among other things, the Company's financial condition, funds from operations, the level of its capital and development expenditures, its future business prospects and any contractual restrictions. Two of the indentures governing the Company's outstanding senior notes contain restrictions on the Company's ability to declare and pay dividends. Under these indentures, the Company may not pay any cash dividends on its common or preferred stock if (i) a default or an event of default has occurred and is continuing at the time of or immediately after giving effect to the dividend payment, (ii) the Company would not be able to incur at least $1 of additional indebtedness under the terms of the indentures, or (iii) immediately after giving effect to the dividend payment, the aggregate of all dividends and other restricted payments declared or made after the respective issue dates of the notes exceeds the sum of specified income, proceeds from the issuance of stock and debt by the Company and other amounts from the quarter in which the respective note issuances occurred to the quarter immediately preceding the date of the dividend payment. As of December 31, 1998, the Company did not meet the debt incurrence or the restricted payment tests under these indentures. 20
21 ITEM 6. SELECTED FINANCIAL DATA The following table sets forth selected consolidated financial data of the Company for each of the four fiscal years ended June 30, 1997, the six month transition period ended December 31, 1997, the six months ended December 31, 1996 and the twelve months ended December 31, 1998 and 1997. The data is derived from the consolidated financial statements of the Company. Acquisitions made by the Company during the first and second quarters of 1998 materially affect the comparability of the selected financial data for 1997 and 1998. Each of the acquisitions was accounted for using the purchase method. The table should be read in conjunction with "Management's Discussion and Analysis of Financial Condition and Results of Operations" and the consolidated financial statements, including the notes thereto, appearing in Items 7 and 8 of this report. 21
22 <TABLE> <CAPTION> YEAR ENDED SIX MONTHS ENDED DECEMBER 31, DECEMBER 31, ------------------------------ ------------------------------ 1998 1997 1997 1996 ------------- ------------- ------------- ------------- ($ IN THOUSANDS, EXCEPT PER SHARE DATA) <S> <C> <C> <C> <C> STATEMENT OF OPERATIONS DATA: Revenues: Oil and gas sales ......................... $ 256,887 $ 198,410 $ 95,657 $ 90,167 Oil and gas marketing sales ............... 121,059 104,394 58,241 30,019 Oil and gas service operations ............ -- -- -- -- ------------- ------------- ------------- ------------- Total revenues ....................... 377,946 302,804 153,898 120,186 ------------- ------------- ------------- ------------- Operating costs: Production expenses ....................... 51,202 14,737 7,560 4,268 Production taxes .......................... 8,295 4,590 2,534 1,606 Oil and gas marketing expenses ............ 119,008 103,819 58,227 29,548 Oil and gas service operations ............ -- -- -- -- Impairment of oil and gas properties ...... 826,000 346,000 110,000 -- Impairment of other assets ................ 55,000 -- -- -- Oil and gas depreciation, depletion and amortization ............ 146,644 127,429 60,408 36,243 Depreciation and amortization of other assets ............................ 8,076 4,360 2,414 1,836 General and administrative ................ 19,918 10,910 5,847 3,739 ------------- ------------- ------------- ------------- Total operating costs ................ 1,234,143 611,845 246,990 77,240 ------------- ------------- ------------- ------------- Income (loss) from operations ................ (856,197) (309,041) (93,092) 42,946 ------------- ------------- ------------- ------------- Other income (expense): Interest and other income ................. 3,926 87,673 78,966 2,516 Interest expense .......................... (68,249) (29,782) (17,448) (6,216) ------------- ------------- ------------- ------------- (64,323) 57,891 61,518 (3,700) ------------- ------------- ------------- ------------- Income (loss) before income taxes and extraordinary item .................. (920,520) (251,150) (31,574) 39,246 Provision (benefit) for income taxes ......... -- (17,898) -- 14,325 ------------- ------------- ------------- ------------- Income (loss) before extraordinary item ...... (920,520) (233,252) (31,574) 24,921 Extraordinary item: Loss on early extinguishment of debt, net of applicable income taxes .... (13,334) (177) -- (6,443) ------------- ------------- ------------- ------------- Net income (loss) ............................ (933,854) (233,429) (31,574) 18,478 Preferred stock dividends .................... (12,077) -- -- -- ------------- ------------- ------------- ------------- Net income (loss) available to common shareholders ..................... $ (945,931) $ (233,429) $ (31,574) $ 18,478 ============= ============= ============= ============= Earnings (loss) per common share- basic: Income (loss) before extraordinary item .................................... $ (9.83) $ (3.30) $ (0.45) $ 0.40 Extraordinary item ........................... (0.14) -- $ -- (0.10) ------------- ------------- ------------- ------------- Net income (loss) ............................ $ (9.97) $ (3.30) $ (0.45) $ 0.30 ============= ============= ============= ============= Earnings (loss) per common share- assuming dilution: Income (loss) before extraordinary item ...... $ (9.83) $ (3.30) $ (0.45) $ 0.38 Extraordinary item ........................... (0.14) -- -- (0.10) ------------- ------------- ------------- ------------- Net income (loss) ............................ $ (9.97) $ (3.30) $ (0.45) $ 0.28 ============= ============= ============= ============= Cash dividends declared per common share ........................ $ 0.04 $ 0.06 $ 0.04 $ -- CASH FLOW DATA: Cash provided by operating activities before changes in working capital ......................... $ 117,500 $ 152,196 $ 67,872 $ 76,816 Cash provided by operating activities .................... 94,639 181,345 139,157 41,901 Cash used in investing activities ............ 548,050 476,209 136,504 184,149 Cash provided by (used in) financing activities .................... 363,797 277,985 (2,810) 231,349 Effect of exchange rate changes on cash ......................... (4,726) -- -- -- BALANCE SHEET DATA (at end of period): Total assets ................................. $ 812,615 $ 952,784 $ 952,784 $ 860,597 Long-term debt, net of current maturities .............................. 919,076 508,992 508,992 220,149 Stockholders' equity (deficit) ............... (248,568) 280,206 280,206 484,062 </TABLE> <TABLE> <CAPTION> YEAR ENDED JUNE 30, ---------------------------------------------------------------- 1997 1996 1995 1994 ------------- ------------- ------------- ------------- ($ IN THOUSANDS, EXCEPT PER SHARE DATA) <S> <C> <C> <C> <C> STATEMENT OF OPERATIONS DATA: Revenues: Oil and gas sales ......................... $ 192,920 $ 110,849 $ 56,983 $ 22,404 Oil and gas marketing sales ............... 76,172 28,428 -- -- Oil and gas service operations ............ -- 6,314 8,836 6,439 ------------- ------------- ------------- ------------- Total revenues ....................... 269,092 145,591 65,819 28,843 ------------- ------------- ------------- ------------- Operating costs: Production expenses ....................... 11,445 6,340 3,379 2,141 Production taxes .......................... 3,662 1,963 877 1,506 Oil and gas marketing expenses ............ 75,140 27,452 -- -- Oil and gas service operations ............ -- 4,895 7,747 5,199 Impairment of oil and gas properties ...... 236,000 -- -- -- Impairment of other assets ................ -- -- -- -- Oil and gas depreciation, depletion and amortization ............ 103,264 50,899 25,410 8,141 Depreciation and amortization of other assets ............................ 3,782 3,157 1,765 1,871 General and administrative ................ 8,802 4,828 3,578 3,135 ------------- ------------- ------------- ------------- Total operating costs ................ 442,095 99,534 42,756 21,993 ------------- ------------- ------------- ------------- Income (loss) from operations ................ (173,003) 46,057 23,063 6,850 ------------- ------------- ------------- ------------- Other income (expense): Interest and other income ................. 11,223 3,831 1,524 981 Interest expense .......................... (18,550) (13,679) (6,627) (2,676) ------------- ------------- ------------- ------------- (7,327) (9,848) (5,103) (1,695) ------------- ------------- ------------- ------------- Income (loss) before income taxes and extraordinary item .................. (180,330) 36,209 17,960 5,155 Provision (benefit) for income taxes ......... (3,573) 12,854 6,299 1,250 ------------- ------------- ------------- ------------- Income (loss) before extraordinary item ...... (176,757) 23,355 11,661 3,905 Extraordinary item: Loss on early extinguishment of debt, net of applicable income taxes .... (6,620) -- -- -- ------------- ------------- ------------- ------------- Net income (loss) ............................ (183,377) 23,355 11,661 3,905 Preferred stock dividends .................... -- -- -- -- ------------- ------------- ------------- ------------- Net income (loss) available to common shareholders ..................... $ (183,377) $ 23,355 $ 11,661 $ 3,905 ============= ============= ============= ============= Earnings (loss) per common share- basic: Income (loss) before extraordinary item .................................... $ (2.69) $ 0.43 $ 0.22 $ 0.08 Extraordinary item ........................... (0.10) -- -- -- ------------- ------------- ------------- ------------- Net income (loss) ............................ $ (2.79) $ 0.43 $ 0.22 $ 0.08 ============= ============= ============= ============= Earnings (loss) per common share- assuming dilution: Income (loss) before extraordinary item ...... $ (2.69) $ 0.40 $ 0.21 $ 0.08 Extraordinary item ........................... (0.10) -- -- -- ------------- ------------- ------------- ------------- Net income (loss) ............................ $ (2.79) $ 0.40 $ 0.21 $ 0.08 ============= ============= ============= ============= Cash dividends declared per common share ........................ $ 0.02 $ -- $ -- $ -- CASH FLOW DATA: Cash provided by operating activities before changes in working capital ......................... $ 161,140 $ 88,431 $ 45,903 $ 15,527 Cash provided by operating activities .................... 84,089 120,972 54,731 19,423 Cash used in investing activities ............ 523,854 344,389 112,703 29,211 Cash provided by (used in) financing activities .................... 512,144 219,520 97,282 21,162 Effect of exchange rate changes on cash ......................... -- -- -- -- BALANCE SHEET DATA (at end of period): Total assets ................................. $ 949,068 $ 572,335 $ 276,693 $ 125,690 Long-term debt, net of current maturities .............................. 508,950 268,431 145,754 47,878 Stockholders' equity (deficit) ............... 286,889 177,767 44,975 31,260 </TABLE> 22
23 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS OVERVIEW Although the Company's oil and gas revenues, production, and proved reserves reached record levels during the year ended December 31, 1998 (the "Current Year"), significant declines in oil and gas prices as of December 31, 1998 resulted in downward revisions in estimates of the Company's proved oil and gas reserves and the related present value of the estimated future net revenues from its proved reserves. The Company recorded an $826 million oil and gas property writedown and a net loss of $934 million during the Current Year. In response to disappointing drilling results in Louisiana and changes occurring in oil and natural gas markets, the Company significantly revised its business strategy during the six months ended December 31, 1997 (the "Transition Period"). These revisions included (i) reducing the size and risk of its exploratory drilling program, especially in the Louisiana Trend, (ii) acquiring significant volumes of long-lived natural gas reserves, particularly in the Mid-Continent region of the U.S., and (iii) building a larger inventory of lower risk drilling opportunities through acquisitions and joint ventures. Further, the Company reduced its capital expenditure budget for exploration and development to more closely match anticipated cash flow from operations. As part of this revised strategy, the Company acquired various proved oil and gas reserves through merger or through purchases of oil and gas properties. During the Current Year, the Company acquired approximately 750 Bcfe of proved reserves primarily in eight major transactions. Of these transactions, three were closed in the first quarter of 1998, and five were closed during the second quarter of 1998. These acquisitions increased oil and gas production volumes and revenues, decreased DD&A per Mcfe, and increased production expenses during the Current Year. Long-term debt and interest expense also increased as a result of the financing required to fund these acquisitions. The total consideration given for the acquisitions was 30.8 million shares of Company common stock, $280 million of cash, the assumption of $205 million of debt, and the incurrence of approximately $20 million of other acquisition related costs. The Company incurred an $826 million impairment of oil and gas properties in the Current Year. The writedown was caused by a combination of several factors, including the acquisitions completed by the Company during the Current Year, which were accounted for using the purchase method, and the significant decreases in oil and gas prices throughout the Current Year. Oil and gas prices used to value the Company's proved reserves decreased from $17.62 per Bbl of oil and $2.29 per Mcf of gas at December 31, 1997, to $10.48 per Bbl of oil and $1.68 per Mcf of gas at December 31, 1998. Higher drilling and completion costs and the evaluation of certain leasehold, seismic and other exploration-related costs that were previously unevaluated were the remaining contributing factors which led to the writedown in the Current Year. During the Current Year, the Company participated in 242 gross (135.2 net) wells, 156 of which were Company operated. A summary of the Company's drilling activities and capital expenditures by primary operating area is as follows ($ in thousands): <TABLE> <CAPTION> CAPITAL EXPENDITURES - OIL AND GAS PROPERTIES ---------------------------------------------------------------------------- GROSS NET SALE OF WELLS WELLS DRILLING LEASEHOLD SUB-TOTAL ACQUISITION PROPERTIES TOTAL ---------- ---------- ---------- ---------- ---------- ----------- ---------- ---------- <S> <C> <C> <C> <C> <C> <C> <C> <C> Mid-Continent ........... 165 96.1 $ 63,431 $ 4,779 $ 68,210 $ 662,104 $ (15,712) $ 714,602 Gulf Coast .............. 37 17.8 109,122 13,921 123,043 -- -- 123,043 Canada .................. 20 6.4 10,011 2,535 12,546 78,176 -- 90,722 All other areas ......... 20 14.9 41,611 5,134 46,745 -- -- 46,745 ---------- ---------- ---------- ---------- ---------- ---------- ---------- ---------- Total ............... 242 135.2 $ 224,175 $ 26,369 $ 250,544 $ 740,280 $ (15,712) $ 975,112 ========== ========== ========== ========== ========== ========== ========== ========== </TABLE> The Company's proved reserves increased 144% to an estimated 1,091 Bcfe at December 31, 1998, an increase of 643 Bcfe from the 448 Bcfe of estimated proved reserves at December 31, 1997 (see Note 11 of Notes to Consolidated Financial Statements in Item 8). 23
24 The Company's strategy for 1999 is to continue developing its natural gas assets by drilling, but at a significantly reduced pace. The Company has reduced its capital expenditure budget (before any acquisitions) to approximately $90 million and has reduced the Gulf Coast drilling component significantly. Furthermore, the Company has increased its use of 3-D seismic to assist in reducing exploratory risks and increasing economic returns from its drilling programs. The Company has conducted, participated in, or is actively pursuing more than 25 3-D seismic programs to evaluate the Company's acreage inventory. The following table sets forth certain operating data of the Company for the periods presented: <TABLE> <CAPTION> YEAR ENDED SIX MONTHS ENDED DECEMBER 31, DECEMBER 31, YEAR ENDED JUNE 30, ----------------------- ----------------------- ----------------------- 1998 1997 1997 1996 1997 1996 ---------- ---------- ---------- ---------- ---------- ---------- <S> <C> <C> <C> <C> <C> <C> NET PRODUCTION DATA: Oil (MBbl) ................................... 5,976 3,511 1,857 1,116 2,770 1,413 Gas (MMcf) ................................... 94,421 59,236 27,326 30,095 62,005 51,710 Gas equivalent (MMcfe) ....................... 130,277 80,302 38,468 36,791 78,625 60,190 OIL AND GAS SALES ($ in 000's): Oil .......................................... $ 75,877 $ 68,079 $ 34,523 $ 24,418 $ 57,974 $ 25,224 Gas .......................................... 181,010 130,331 61,134 65,749 134,946 85,625 ---------- ---------- ---------- ---------- ---------- ---------- Total oil and gas sales .............. $ 256,887 $ 198,410 $ 95,657 $ 90,167 $ 192,920 $ 110,849 ========== ========== ========== ========== ========== ========== AVERAGE SALES PRICE: Oil ($ per Bbl) .............................. $ 12.70 $ 19.39 $ 18.59 $ 21.88 $ 20.93 $ 17.85 Gas ($ per Mcf) .............................. $ 1.92 $ 2.20 $ 2.24 $ 2.18 $ 2.18 $ 1.66 Gas equivalent ($ per Mcfe) .................. $ 1.97 $ 2.47 $ 2.49 $ 2.45 $ 2.45 $ 1.84 OIL AND GAS COSTS ($ per Mcfe): Production expenses and taxes ................ $ .45 $ .24 $ .27 $ .16 $ .19 $ .14 General and administrative ................... $ .15 $ .14 $ .15 $ .10 $ .11 $ .08 Depreciation, depletion and amortization ..... $ 1.13 $ 1.59 $ 1.57 $ .99 $ 1.31 $ .85 NET WELLS DRILLED: Horizontal wells ............................. 20 69 27 34 76 42 Vertical wells ............................... 116 32 14 13 31 27 NET WELLS AT END OF PERIOD ..................... 2,405 401 401 210 270 187 </TABLE> RESULTS OF OPERATIONS Year Ended December 31, 1998 and 1997 General. In the Current Year, the Company realized a net loss of $933.9 million, or a loss of $9.97 per common share, on total revenues of $381.9 million. This compares to a net loss of $233.4 million, or a loss of $3.30 per common share, on total revenues of $390.5 million during the year ended December 31, 1997 (the "Prior Year"). The loss in the Current Year was caused primarily by an $826.0 million oil and gas property writedown recorded under the full-cost method of accounting and a $55.0 million writedown of other assets. See "Impairment of Oil and Gas Properties" and "Impairment of Other Assets". Oil and Gas Sales. During the Current Year, oil and gas sales increased 29% to $256.9 million versus $198.4 million for the Prior Year. The increase in oil and gas sales resulted primarily from growth in production volumes. For the Current Year, the Company produced 130.3 Bcfe at a weighted average price of $1.97 per Mcfe, compared to 80.3 Bcfe produced in the Prior Year at a weighted average price of $2.47 per Mcfe. The following table shows the Company's production by region for the Current Year and the Prior Year: <TABLE> <CAPTION> FOR THE YEAR ENDED DECEMBER 31, -------------------------------------------------- 1998 1997 ----------------------- ----------------------- MMCFE PERCENT MMCFE PERCENT ---------- ---------- ---------- ---------- <S> <C> <C> <C> <C> Mid-Continent .................................... 64,038 49% 17,685 22% Gulf Coast ....................................... 52,463 40 60,662 76 Canada ........................................... 7,746 6 -- -- All other areas .................................. 6,030 5 1,955 2 ---------- ---------- ---------- ---------- Total production ........................... 130,277 100% 80,302 100% ========== ========== ========== ========== </TABLE> 24
25 Natural gas production represented approximately 72% of the Company's total production volume on an equivalent basis in the Current Year, compared to 74% in the Prior Year. This decrease in gas production as a percentage of total production was primarily the result of new production in the Louisiana Trend, which tends to produce more oil than gas. In 1999, the Company's production is estimated to be approximately 80% gas. For the Current Year, the Company realized an average price per barrel of oil of $12.70, compared to $19.39 in the Prior Year. Gas price realizations decreased from $2.20 per Mcf in the Prior Year to $1.92 per Mcf in the Current Year. The Company's hedging activities resulted in an increase in oil and gas revenues of $11.8 million in the Current Year and a decrease in oil and gas revenues of $4.6 million in the Prior Year. Oil and Gas Marketing Sales. The Company realized $121.1 million in oil and gas marketing sales for third parties in the Current Year, with corresponding oil and gas marketing expenses of $119.0 million, for a net margin of $2.1 million. This compares to sales of $104.4 million, expenses of $103.8 million, and a margin of $0.6 million in the Prior Year. Production Expenses and Taxes. Production expenses and taxes, which include lifting costs, production taxes and ad valorem taxes, increased to $59.5 million in the Current Year, compared to $19.3 million in the Prior Year. These increases were primarily the result of increased production and increased operating costs. On a unit of production basis, production expenses and taxes increased to $0.45 per Mcfe compared to $0.24 per Mcfe in the Prior Year due primarily to the higher per unit operating costs associated with many of the oil and gas properties acquired during the Current Year. The Company expects that production expenses per Mcfe will generally remain the same in 1999. Impairment of Oil and Gas Properties. The Company utilizes the full-cost method to account for its investment in oil and gas properties. Under this method, all costs of acquisition, exploration and development of oil and gas reserves (including such costs as leasehold acquisition costs, geological and geophysical expenditures, certain capitalized internal costs, dry hole costs and tangible and intangible development costs) are capitalized as incurred. These oil and gas property costs, along with the estimated future capital expenditures to develop proved undeveloped reserves, are depleted and charged to operations using the unit-of-production method based on the ratio of current production to proved oil and gas reserves as estimated by the Company's independent engineering consultants and Company engineers. Costs directly associated with the acquisition and evaluation of unproved properties are excluded from the amortization computation until it is determined whether or not proved reserves can be assigned to the property or whether impairment has occurred. The excess of capitalized costs of oil and gas properties, net of accumulated depreciation, depletion and amortization and related deferred income taxes, over the discounted future net revenues of proved oil and gas properties is charged to operations. The Company incurred an impairment of oil and gas properties charge of $826 million in the Current Year. The writedown was caused by a combination of several factors, including the acquisitions completed by the Company during the Current Year, which were accounted for using the purchase method, and the significant decreases in oil and gas prices throughout the Current Year. Oil and gas prices used to value the Company's proved reserves decreased from $17.62 per Bbl of oil and $2.29 per Mcf of gas at December 31, 1997, to $10.48 per Bbl of oil and $1.68 per Mcf of gas at December 31, 1998. Higher drilling and completion costs and the evaluation of certain leasehold, seismic and other exploration-related costs that were previously unevaluated were the remaining factors which contributed to the writedown in the Current Year. Impairment of Other Assets. The Company incurred a $55 million impairment charge during the Current Year. Of this amount, $30 million relates to the Company's investment in preferred stock of Gothic Energy Corporation, and the remainder was related to certain of the Company's gas processing and transportation assets located in Louisiana. No such charge was recorded in the Prior Year. Oil and Gas Depreciation, Depletion and Amortization. Depreciation, depletion and amortization ("DD&A") of oil and gas properties for the Current Year was $146.6 million, $19.2 million higher than the Prior Year's expense of $127.4 million. The average DD&A rate per Mcfe, which is a function of capitalized costs, future development costs, and the related underlying reserves in the periods presented, decreased to $1.13 in the Current Year ($1.17 in 25
26 U.S. and $0.43 in Canada) compared to $1.59 in the Prior Year. The Company expects the 1999 DD&A rate to be approximately $0.75 per Mcfe. Depreciation and Amortization of Other Assets. Depreciation and amortization ("D&A") of other assets increased to $8.1 million in the Current Year, compared to $4.4 million in the Prior Year. This increase was caused by increased investments in depreciable buildings and equipment and increased amortization of debt issuance costs as a result of the issuance of senior notes in April 1998. General and Administrative. General and administrative ("G&A") expenses, which are net of capitalized internal payroll and non-payroll expenses (see Note 11 of Notes to Consolidated Financial Statements), were $19.9 million in the Current Year, up 83% from $10.9 million in the Prior Year. The increase in the Current Year compared to the Prior Year is due primarily to increased personnel expenses required by the Company's growth and industry wage inflation. The Company capitalized $5.3 million and $5.3 million of internal costs in the Current Year and Prior Year, respectively, directly related to the Company's oil and gas exploration and development efforts. The Company anticipates that G&A costs for 1999 will decline as a result of reduced staffing levels. Interest and Other Income. Interest and other income for the Current Year were $3.9 million compared to $87.7 million in the Prior Year. During the Prior Year, the Company realized a gain on the sale of its Bayard common stock of $73.8 million, the most significant component of interest and other income. Interest Expense. Interest expense increased to $68.2 million in the Current Year, compared to $29.8 million in the Prior Year. The increase was due primarily to the issuance of $500 million of senior notes in April 1998. In addition to the interest expense reported, the Company capitalized $6.5 million of interest during the Current Year, compared to $10.4 million capitalized in the Prior Year. The Company anticipates that capitalized interest for 1999 will decrease to between $2 million and $3 million. Provision (Benefit) for Income Taxes. The Company recorded no income taxes in the Current Year compared to an income tax benefit of $17.9 million in the Prior Year, before consideration of the $3.7 million tax benefit associated with an extraordinary loss from the early extinguishment of debt. At December 31, 1998, the Company had U.S. and Canadian net operating loss carryforwards of approximately $571 million and $1 million, respectively, for regular federal income taxes which will expire in future years beginning in 2007. Management believes that it cannot be demonstrated at this time that it is more likely than not that the deferred income tax assets, comprised primarily of the net operating loss carryforward, will be realizable in future years, and therefore a valuation allowance of $459 million has been recorded. No deferred tax benefit related to the exercise of employee stock options was allocated to additional paid-in capital in the Current Year. The Company does not expect to record any net income tax expense in 1999 based on information available at this time. Six Months Ended December 31, 1997 and 1996 General. For the Transition Period, the Company realized a net loss of $31.6 million, or $0.45 per common share, on total revenues of $232.9 million. This compares to net income of $18.5 million, or $0.28 per common share, on total revenues of $122.7 million in the six months ended December 31, 1996 (the "Prior Period"). The loss in the Transition Period was caused by a $110.0 million asset writedown recorded under the full-cost method of accounting, partially offset by a gain of $73.8 million from the sale of Bayard stock. See "Impairment of Oil and Gas Properties". Oil and Gas Sales. During the Transition Period, oil and gas sales increased 6% to $95.7 million versus $90.2 million for the Prior Period. The increase in oil and gas sales resulted primarily from growth in production volumes. For the Transition Period, the Company produced 38.5 Bcfe at a weighted average price of $2.49 per Mcfe, compared to 36.8 Bcfe produced in the Prior Period at a weighted average price of $2.45 per Mcfe. 26
27 The following table shows the Company's production by region for the Transition Period and the Prior Period: <TABLE> <CAPTION> FOR THE SIX MONTHS ENDED DECEMBER 31, ----------------------------------------- 1997 1996 ------------------- ------------------- MMCFE PERCENT MMCFE PERCENT -------- -------- --------- ------- <S> <C> <C> <C> <C> Mid-Continent................................................. 8,852 23% 8,980 24% Gulf Coast.................................................... 26,220 68 26,243 71 All other areas............................................... 3,396 9 1,568 5 -------- -------- --------- ------- Total production.............................................. 38,468 100% 36,791 100% ======== ======== ========= ======= </TABLE> Natural gas production represented approximately 71% of the Company's total production volume on an equivalent basis in the Transition Period, compared to 82% in the Prior Period. This decrease in gas production as a percentage of total production was primarily the result of new production in the Louisiana Trend, which tends to produce more oil than gas. For the Transition Period, the Company realized an average price per barrel of oil of $18.59, compared to $21.88 in the Prior Period. Gas price realizations increased slightly from $2.18 per Mcf in the Prior Period to $2.24 per Mcf in the Transition Period. The Company's hedging activities resulted in decreases in oil and gas revenues of $4.3 million and $7.1 million in the Transition Period and Prior Period, respectively. Oil and Gas Marketing Sales. The Company realized $58.2 million in oil and gas marketing sales for third parties in the Transition Period, with corresponding oil and gas marketing expenses of $58.2 million. This compares to sales of $30.0 million, expenses of $29.5 million, and a margin of $0.5 million in the Prior Period. Production Expenses and Taxes. Production expenses and taxes, which include lifting costs, production taxes and excise taxes, increased to $10.1 million in the Transition Period, compared to $5.9 million in the Prior Period. These increases were primarily the result of increased operating costs and increased production. On a unit of production basis, production expenses and taxes increased to $0.27 per Mcfe compared to $0.16 per Mcfe in the Prior Period. Impairment of Oil and Gas Properties. The Company incurred an impairment of oil and gas properties charge of $110.0 million for the Transition Period. This writedown was caused by several factors, including oil prices declining from $18.38 at June 30, 1997 to $17.62 at December 31, 1997, and drilling and completion costs continuing to escalate during the Transition Period. Higher costs caused the Company's capital spending to exceed budgeted amounts during the Transition Period and also increased the estimated future capital expenditures to be incurred to develop the Company's proved undeveloped reserves. The Company's results from wells completed during the Transition Period in the Louisiana Trend continued to be inconsistent and production performance from various properties in the Navasota River and Independence areas were lower than projected at June 30, 1997. As a result of the above factors, the Company recorded a downward revision to its proved reserves of 38 net Bcfe in the Austin Chalk Trend as of December 31, 1997. Excluding the purchase of additional leasehold, the Company incurred approximately $85 million in capital expenditures in the Louisiana Trend during the Transition Period, of which approximately $67 million were incurred in the Masters Creek area. Approximately $16 million of the drilling costs were incurred on Company operated wells that had not been completed at December 31, 1997. In the Masters Creek area, the Company completed operations on 11 wells during the Transition Period. Although 10 of the 11 wells were commercially productive, the drilling costs incurred through December 31, 1997 of approximately $58 million for the 10 wells were higher than anticipated and assigned reserves were lower than expected. The lower reserve quantities were due in part to lower oil prices at December 31, 1997. In addition, the Company transferred approximately $11 million of previously unevaluated leasehold costs from all areas of the Louisiana Trend to the amortization base of the full-cost pool during the Transition Period. In connection with the Company's acquisition of AnSon Production Corporation ("AnSon") in December 1997, which was accounted for using the purchase method, the purchase price of approximately $43 million was allocated 27
28 to the fair value of assets acquired. Based upon reserve estimates as of December 31, 1997, the portion of the purchase price which was allocated to evaluated oil and gas properties exceeded the associated discounted future net revenues from AnSon's estimated proved reserves by approximately $14 million. Oil and Gas Depreciation, Depletion and Amortization. DD&A of oil and gas properties for the Transition Period was $60.4 million, $24.2 million higher than the Prior Period's expense of $36.2 million. The expense in the Transition Period was computed prior to the writedown from the impairment of oil and gas properties charge. The average DD&A rate per Mcfe increased to $1.57 in the Transition Period compared to $0.99 in the Prior Period. Depreciation and Amortization of Other Assets. D&A of other assets increased to $2.4 million in the Transition Period, compared to $1.8 million in the Prior Period. This increase was caused by increased investments in depreciable buildings and equipment and increased amortization of debt issuance costs as a result of the issuance of senior notes in March 1997. General and Administrative. G&A expenses, which are net of capitalized internal payroll and non-payroll expenses (see Note 11 of Notes to Consolidated Financial Statements), were $5.8 million in the Transition Period, up 56% from $3.7 million in the Prior Period. The increase in the Transition Period compared to the Prior Period results primarily from increased personnel expenses required by the Company's growth and industry wage inflation. The Company capitalized $2.4 million of internal costs in the Transition Period directly related to the Company's oil and gas exploration and development efforts, compared to $1.1 million in the Prior Period. Interest and Other Income. Interest and other income for the Transition Period was $79.0 million compared to $2.5 million in the Prior Period. During the Transition Period, the Company realized a gain on the sale of its Bayard common stock of $73.8 million, the most significant component of interest and other income. Interest Expense. Interest expense increased to $17.4 million in the Transition Period, compared to $6.2 million in the Prior Period. The increase was due primarily to the issuance of $300 million of senior notes in March 1997. In addition to the interest expense reported, the Company capitalized $5.1 million of interest during the Transition Period, compared to $7.6 million capitalized in the Prior Period. Provision (Benefit) for Income Taxes. The Company recorded no income taxes for the Transition Period, compared to income tax expense of $14.3 million in the Prior Period, before consideration of the $3.7 million tax benefit associated with an extraordinary loss from the early extinguishment of debt. At December 31, 1997, the Company had a net operating loss carryforward of approximately $337 million for regular federal income taxes which will expire in future years beginning in 2007. Management believed that it could not be demonstrated at that time that it was more likely than not that the deferred income tax assets, comprised primarily of the net operating loss carryforward, would be realizable in future years, and therefore a valuation allowance of $77.9 million was recorded. No deferred tax benefit related to the exercise of employee stock options was allocated to additional paid-in capital in the Transition Period. Fiscal Years Ended June 30, 1997 and 1996 General. For the fiscal year ended June 30, 1997, the Company realized a net loss of $183.4 million, or $2.79 per common share, on total revenues of $280.3 million. This compares to net income of $23.4 million, or $0.40 per common share, on total revenues of $149.4 million in 1996. The loss in fiscal 1997 resulted from a $236 million asset writedown recorded in the fourth quarter under the full-cost method of accounting. See "Impairment of Oil and Gas Properties". Oil and Gas Sales. During fiscal 1997, oil and gas sales increased 74% to $192.9 million versus $110.8 million for fiscal 1996. The increase in oil and gas sales resulted primarily from strong growth in production volumes and significantly higher average oil and gas prices. For fiscal 1997, the Company produced 78.6 Bcfe at a weighted average price of $2.45 per Mcfe, compared to 60.2 Bcfe produced in fiscal 1996 at a weighted average price of $1.84 per Mcfe. This represents production growth of 31% for fiscal 1997 compared to fiscal 1996. 28
29 The following table shows the Company's production by region for fiscal 1997 and fiscal 1996: <TABLE> <CAPTION> FOR THE YEAR ENDED JUNE 30, --------------------------------------------------- 1997 1996 ----------------------- ----------------------- MMCFE PERCENT MMCFE PERCENT --------- ---------- ---------- --------- <S> <C> <C> <C> <C> Mid-Continent................................................. 17,370 22% 10,420 17% Gulf Coast.................................................... 57,377 73 47,234 78 Other areas................................................... 3,878 5 2,536 5 --------- ---------- ---------- --------- Total production.............................................. 78,625 100% 60,190 100% ========= ========== ========== ========= </TABLE> Natural gas production represented approximately 79% of the Company's total production volume on an equivalent basis in fiscal 1997. This compares to 86% in fiscal 1996 and 79% in fiscal 1995. This decrease in gas production as a percentage of total production in fiscal 1997 was the result of drilling in the Louisiana Trend, which tends to produce more oil than gas. For fiscal 1997, the Company realized an average price per barrel of oil of $20.93, compared to $17.85 in fiscal 1996. The Company markets its oil on monthly average equivalent spot price contracts and typically receives a premium to the price posted for West Texas Intermediate crude oil. Gas price realizations increased from fiscal 1996 to 1997 from $1.66 per Mcf to $2.18 per Mcf, or 31%, generally as the result of market conditions. The Company's gas price realizations in fiscal 1997 were also higher due to the increase in Louisiana Trend gas production, which generally receives premium prices at least equivalent to Henry Hub indexes due to the high Btu content and favorable market location of the production. The Company's hedging activities resulted in decreases in oil and gas revenues of $7.4 million and $5.9 million in fiscal 1997 and 1996, respectively. Oil and Gas Marketing Sales. In December 1995, the Company entered into the oil and gas marketing business by acquiring a subsidiary to provide natural gas marketing services, including commodity price structuring, contract administration and nomination services, for the Company, its partners and other oil and natural gas producers in geographical areas in which the Company is active. The Company realized $76.2 million in oil and gas marketing sales for third parties in fiscal 1997, with corresponding oil and gas marketing expenses of $75.1 million, resulting in a gross margin of $1.1 million. This compares to sales of $28.4 million, expenses of $27.5 million, and a margin of $0.9 million in fiscal 1996. Oil and Gas Service Operations. On June 30, 1996, Peak USA Energy Services, Ltd., a limited partnership ("Peak"), was formed by Peak Oilfield Services Company (a joint venture between Cook Inlet Region, Inc. and Nabors Industries, Inc.) and Chesapeake for the purpose of purchasing the Company's oilfield service assets and providing rig moving, transportation and related site construction services to the Company and others in the industry. The Company sold its service company assets to Peak for $6.4 million, and simultaneously invested $2.5 million in exchange for a 33.3% partnership interest in Peak. This transaction resulted in recognition of a $1.8 million pre-tax gain during the fourth fiscal quarter of 1996 (reported in interest and other revenues). A deferred gain from the sale of service company assets of $0.9 million was recorded as a reduction in the Company's investment in Peak and was amortized to income over the estimated useful lives of the Peak assets. The Company's investment in Peak was accounted for using the equity method, and resulted in $0.5 million of income being included in interest and other revenues in fiscal 1997. The Company sold its partnership interest in Peak in June 1998. Revenues from oil and gas service operations were $6.3 million in fiscal 1996. The related costs and expenses of these operations were $4.9 million for the year ended June 30, 1996. The gross profit margin was 22% in fiscal 1996. The gross profit margin derived from these operations is a function of drilling activities in the period, costs of materials and supplies and the mix of operations between lower margin trucking operations versus higher margin labor oriented service operations. 29
30 Production Expenses and Taxes. Production expenses and taxes, which include lifting costs, production taxes and excise taxes, increased to $15.1 million in fiscal 1997, compared to $8.3 million in fiscal 1996. This increase was primarily the result of increased production. On a unit production basis, production expenses and taxes increased to $0.19 per Mcfe, compared to $0.14 per Mcfe in fiscal 1996. During fiscal 1996, a high proportion of the Company's production was from the Giddings Field, much of which qualified for Texas severance tax exemptions. Impairment of Oil and Gas Properties. Prior to January 1997, the Company had completed operations on one exploratory well in each of three separate areas outside Masters Creek in the Louisiana Trend. Between April 1997 and July 1997, the Company completed operations on 10 Company operated exploratory wells located outside Masters Creek in the Louisiana Trend that resulted in the addition of only 0.5 Bcfe of proved reserves. Cumulative well costs on these non-Masters Creek properties were approximately $43 million as of June 30, 1997. Of the 10 wells, one was completed on April 15, 1997, one on May 3, 1997 and eight after June 1, 1997. Based upon this information and similar data which had become available from outside operated properties in these non-Masters Creek areas of the Louisiana Trend, management determined that a significant portion of its leasehold in the Louisiana Trend outside of Masters Creek was impaired. During the quarters ended March 31, 1997 and June 30, 1997, the Company transferred $7.6 million and $86.3 million, respectively, of non-Masters Creek Louisiana Trend leasehold costs to the amortization base of the full-cost pool. The weighted average oil and gas prices used to value the Company's proved reserves declined from $20.90 per Bbl and $2.41 per Mcf at June 30, 1996 to $18.38 per Bbl and $2.12 per Mcf at June 30, 1997. Drilling and equipment costs escalated rapidly in the fourth quarter of fiscal 1997 due primarily to higher day rates for drilling rigs, thus increasing the estimated future capital expenditures to be incurred to develop the Company's proved undeveloped reserves. The oil and gas price declines and the increased costs to drill and equip wells caused the Company to eliminate 35 gross proved undeveloped locations in the Knox Field which contained an estimated 45 net Bcfe of proved undeveloped reserves. Similar factors, combined with unfavorable drilling and production results, eliminated approximately 93 Bcfe of proved reserves in the Giddings and Louisiana Trend areas. In the Independence area of the Giddings Field of Texas, a single well completed in late March 1997, which the Company had estimated to contain 15.7 Bcfe of Company reserves at March 31, 1997, was significantly and adversely affected by another operator's offset well which damaged the reservoir and reduced the Company's estimated ultimate recovery to 8.0 Bcfe of reserves. In late June 1997, management reviewed its March 31, 1997 internal estimates of proved reserves and related present value and, after giving effect to the fourth quarter 1997 drilling and production results, oil and gas prices, higher drilling and completion costs, and additional leasehold acquisition costs and delay rentals, determined that the Company had less reserve potential than had previously been estimated. As a result, management estimated that at June 30, 1997 the Company would have capitalized costs of oil and gas properties which would exceed its full-cost ceiling by approximately $150 million to $200 million. On June 27, 1997, the Company issued a press release which included this estimate. Subsequently, based on the Company's final year-end estimates of its proved reserves and related estimated future net revenues, which took into account additional drilling and production results, management determined that as of June 30, 1997, its capitalized costs exceeded its full-cost ceiling by approximately $236 million. No such writedown was experienced by the Company in fiscal 1996. Oil and Gas Depreciation, Depletion and Amortization. DD&A of oil and gas properties for fiscal 1997 was $103.3 million, $52.4 million higher than fiscal 1996's expense of $50.9 million. The expense in fiscal 1997 excluded the effects of the asset writedown. The average DD&A rate per Mcfe, which is a function of capitalized costs, future development costs, and the related underlying reserves in the periods presented, increased to $1.31 in fiscal 1997 compared to $0.85 in fiscal 1996. Depreciation and Amortization of Other Assets. D&A of other assets increased to $3.8 million in fiscal 1997, compared to $3.2 million in fiscal 1996. This increase in fiscal 1997 was caused by an increase in D&A as a result of increased investments in depreciable buildings and equipment and increased amortization of debt issuance costs as a result of the issuance of senior notes in May 1995, April 1996 and March 1997. 30
31 General and Administrative. G&A expenses, which are net of capitalized internal payroll and non-payroll expenses (see Note 11 of Notes to Consolidated Financial Statements), were $8.8 million in fiscal 1997, up 83% from $4.8 million in fiscal 1996. The increase in fiscal 1997 compared to fiscal 1996 is due primarily to increased personnel expenses required by the Company's growth and industry wage inflation. The Company capitalized $3.9 million of internal costs in fiscal 1997 directly related to the Company's oil and gas exploration and development efforts, compared to $1.7 million in 1996. Interest and Other Income. Interest and other income for fiscal 1997 was $11.2 million compared to $3.8 million in fiscal 1996. During fiscal 1997, the Company realized $8.7 million in interest, $1.6 million of other investment income, $0.5 million from its investment in Peak, and $0.4 million in other income. During fiscal 1996, the Company realized $3.7 million of interest and other investment income and a $1.8 million gain related to the sale of certain service company assets, offset by a $1.7 million loss due to natural gas basis changes in April 1996 as a result of the Company's hedging activities. Interest Expense. Interest expense increased to $18.6 million in fiscal 1997 as compared to $13.7 million in 1996. Interest expense in the fourth quarter of fiscal 1997 was $8.7 million, reflecting the issuance of $300 million of senior notes in March 1997. In addition to the interest expense reported, the Company capitalized $12.9 million of interest during fiscal 1997, compared to $6.4 million capitalized in fiscal 1996. Provision (Benefit) for Income Taxes. The Company recorded an income tax benefit of $3.6 million for fiscal 1997, before consideration of the $3.8 million tax benefit associated with the extraordinary loss from the early extinguishment of debt, compared to income tax expense of $12.9 million in 1996. All of the income tax expense in 1996 was deferred due to tax net operating losses and carryovers resulting from the Company's drilling program. The Company's loss before income taxes and extraordinary item of $180.3 million created a tax benefit for financial reporting purposes of $67.7 million. However, due to limitations on the recognition of deferred tax assets, the total tax benefit was reduced to $3.6 million. At June 30, 1997, the Company had a net operating loss carryforward of approximately $300 million for regular federal income taxes which will expire in future years beginning in 2007. Management believed that it could not be demonstrated at that time that it was more likely than not that the deferred income tax assets, comprised primarily of the net operating loss carryforward, would be realizable in future years, and therefore a valuation allowance of $64.1 million was recorded in fiscal 1997. A deferred tax benefit related to the exercise of employee stock options of approximately $4.8 million was allocated directly to additional paid-in capital in 1997, compared to $7.9 million in 1996. LIQUIDITY AND CAPITAL RESOURCES For the Years Ended December 31, 1998 and 1997 Cash Flows from Operating Activities. Cash provided by operating activities (inclusive of changes in working capital) decreased to $94.6 million in the Current Year, compared to $181.3 million in the Prior Year. This decrease of $86.7 million was due primarily to reduced operating income resulting from significant decreases in average oil and gas prices between periods, as well as significant increases in G&A expenses and interest expense. Cash Flows from Investing Activities. Cash used in investing activities increased to $548.1 million in the Current Year, compared to $476.2 million in the Prior Year. This increase was due primarily to the $279.9 million used to acquire certain oil and gas properties and companies with oil and gas reserves during the Current Year. However, the increase in cash used to acquire oil and gas properties was partially offset by reduced expenditures during the Current Year for exploratory and developmental drilling. During the Current Year and Prior Year, the Company invested $260 million and $471 million, respectively, for exploratory and developmental drilling. Also during the Current Year, the Company sold its 19.9% stake in Pan East Petroleum Corp. to Poco Petroleums, Ltd. 31
32 for approximately $21.2 million. During the Prior Year the Company received net proceeds from the sale of its investment in Bayard common stock of approximately $73.8 million. Cash Flows from Financing Activities. Cash provided by financing activities increased to $363.8 million in the Current Year, compared to $278.0 million in the Prior Year. During the Current Year, the Company retired $85 million of debt assumed at the completion of the DLB Oil & Gas, Inc. acquisition, $120 million of debt assumed at the completion of the Hugoton Energy Corporation acquisition, $90 million of senior notes, and $170 million of borrowings made under its commercial bank credit facilities. During the Current Year, the Company issued $500 million in senior notes and $230 million in preferred stock. During the Prior Year, the Company issued $300 million of senior notes. For the Six Months Ended December 31, 1997 and 1996 Cash Flows from Operating Activities. Cash provided by operating activities (inclusive of changes in components of working capital) increased to $139.2 million in the Transition Period, compared to $41.9 million in the Prior Period. The primary reason for the increase was significant changes in the components of current assets and liabilities, specifically $92 million of short-term investments which were converted into cash during the Transition Period. Cash Flows from Investing Activities. Cash used in investing activities decreased to $136.5 million in the Transition Period, compared to $184.1 million in the Prior Period. This decrease in cash used in investing activities was due primarily to the $90.4 million received from the sale of the Company's investment in Bayard common stock during the Transition Period, offset by other investments. Approximately $189.8 million was expended by the Company in the Transition Period for development and exploration of oil and gas properties, as compared to $186.8 million in the Prior Period. In the Transition Period, other property and equipment additions were $27.0 million primarily as a result of its $11.9 million investment in the Louisiana Chalk Gathering System and Masters Creek Gas Plant as well as additional investments in its Oklahoma City office complex. Cash Flows from Financing Activities. Cash used in financing activities was $2.8 million during the Transition Period, compared to cash provided by financing activities of $231.3 million during the Prior Period. The decrease was due primarily to the proceeds received from the issuance of common stock during the Prior Period of $288.1 million, which was partially offset by the net payments on long-term borrowings of $56.8 million during the Prior Period. For the Fiscal Years Ended June 30, 1997 and 1996 Cash Flows from Operating Activities. Cash provided by operating activities (inclusive of changes in components of working capital) decreased to $84.1 million in fiscal 1997, compared to $121.0 million in fiscal 1996. The primary reason for the decrease from fiscal 1996 to 1997 was significant changes in the components of current assets and liabilities, specifically $102.9 million of short-term investments at June 30, 1997. Cash Flows from Investing Activities. Significantly higher cash was used in fiscal 1997 for development, exploration and acquisition of oil and gas properties compared to fiscal 1996. Approximately $524 million was expended by the Company in fiscal 1997 (net of proceeds from sale of leasehold, equipment and other), compared to $344 million in fiscal 1996. Net cash proceeds received by the Company for sales of oil and gas equipment, leasehold and other decreased to approximately $3.1 million in fiscal 1997, compared to $6.2 million in fiscal 1996. In fiscal 1997, other property and equipment additions were $34 million primarily as a result of its $16.8 million investment in the Louisiana Chalk Gathering System and Masters Creek Gas Plant as well as additional investments in its Oklahoma City office complex. Cash Flows from Financing Activities. On December 2, 1996, the Company completed a public offering of 8,972,000 shares of common stock at a price of $33.63 per share resulting in net proceeds to the Company of approximately $288.1 million. Approximately $55.0 million of the proceeds was used to defease the Company's 32
33 $47.5 million senior notes due 2001, and $11.2 million of the proceeds was used to retire all amounts outstanding under the Company's commercial bank credit facilities. On March 17, 1997, the Company concluded the sale of $150 million of 7.875% senior notes due 2004, and $150 million of 8.5% senior notes due 2012, which offering resulted in net proceeds to the Company of approximately $292.6 million. The 7.875% senior notes were issued at 99.92% of par and the 8.5% senior notes were issued at 99.414% of par. The 7.875% senior notes and the 8.5% senior notes are redeemable at the option of the Company at any time at the redemption or make-whole prices set forth in the respective indentures. In fiscal 1996, cash flows from financing activities were $219.5 million, largely as the result of the issuance of 5,989,500 shares of common stock (net proceeds to the Company of approximately $99.4 million) and $120 million of 9.125% senior notes due 2006. Financial Flexibility and Liquidity The Company had a working capital deficit of $13 million at December 31, 1998 and a cash balance of $30 million. The Company has a $50 million revolving bank credit facility, which matures in August 1999, with an initial committed borrowing base of $50 million. As of December 31, 1998, the Company had borrowed $25 million under this facility, which was included in the working capital deficit as a short-term obligation. Borrowings under the facility are secured by certain producing oil and gas properties and bear interest at a rate of 7.75% per annum as of December 31, 1998. The senior note indentures contain various restrictions for the Company and its restricted subsidiaries to incur additional indebtedness. As of December 31, 1998, the Company estimates that secured commercial bank indebtedness of $115 million could have been incurred within these restrictions. This restriction does not apply to borrowings incurred by CEMI, an unrestricted subsidiary. The senior note indentures also limit the Company's ability to make restricted payments (as defined), including the payment of preferred stock dividends, unless certain tests are met. As of December 31, 1998, the Company was unable to meet the requirements to incur additional unsecured indebtedness, and consequently was not able to pay cash dividends on its 7% cumulative convertible preferred stock on February 1, 1999. Subsequent payments will be subject to the same restrictions and are dependent upon variables that are beyond the Company's ability to predict. This restriction does not affect the Company's ability to borrow under or expand its secured commercial bank facility. If the Company fails to pay dividends for six quarterly periods, the holders of preferred stock would be entitled to elect two additional members to the Board. Debt ratings for the senior notes are B3 by Moody's Investors Service and B by Standard & Poor's Corporation as of March 19, 1999, and both have placed the Company on review with negative implications. There are no scheduled principal payments required on any of the senior notes until March 2004. The Company believes it has adequate resources, including cash on hand, budgeted cash flow from operations and proceeds from miscellaneous asset sales, to fund its capital expenditure budget for exploration and development activities during 1999, which are currently estimated to be approximately $90 million. The Company anticipates proceeds from miscellaneous asset sales will be approximately $45 million during 1999. However, continued low oil and gas prices or unfavorable drilling results could cause the Company to further reduce its drilling program, which is largely discretionary. YEAR 2000 Project. The Company has placed a high priority on proactively resolving computer or embedded chip problems related to the "Year 2000" which may have adverse material effects on its continuing operations or cash flow. This problem would be caused by the inability of a component (software, hardware or equipment with embedded microprocessors) to correctly process date data in and between the 20th and 21st centuries, and therefore fail to properly perform its intended functions and/or to exchange correct date data with other components. This problem 33
34 would most typically be caused by erroneous date calculations, which result from using two digits to signify a year (century implied), handling leap years incorrectly or the use of "special" values that can be confused with legitimate calendar dates. The scope of the Year 2000 project includes conducting an inventory of the Company's software, hardware and "embedded systems" equipment, assessing potential for failure and the associated risk, prioritizing the need for remedial actions, identifying an appropriate action, then implementing and testing. In addition, the Company is taking a similar approach to mitigating risks associated with the Year 2000 readiness of material business partners (vendors, suppliers, customers, etc.). The project will also identify contingency plans to cope with unexpected events resulting from Year 2000 issues. Beginning in mid-1997, the Company began an assessment of its core financial and operational software systems. Three critical systems were identified with date sensitivities: oil and gas financial accounting, production accounting and land/lease administration. A Year 2000 compliant release of the oil and gas financial accounting package in use at the Company is available and has been scheduled for implementation during the third quarter of 1999. The production accounting system in use at the Company is also scheduled for upgrade to a Year 2000 compliant version during the first half of 1999. The timing of these upgrades have been scheduled to be concurrent with the respective vendors' support requirements and to take advantage of additional feature or performance enhancements. A project has been underway since early 1997 to implement a completely revamped version of the land/lease administration package in use at the Company to provide significantly increased functionality and reliability. The terms of this development arrangement stipulated Year 2000 compliance. Preliminary versions of the system have been installed and are being tested. As part of the testing, Year 2000 compliance will be assured. Assessment continues for lower priority software systems. In addition, the Year 2000 compliant AS/400, on which the accounting package resides, was upgraded to provide additional capacity in late 1997. Operating system upgrades will be implemented in the near future for the Windows NT based servers to complete their remediation. Other activities either already underway or scheduled include testing of desktop PCs, assessment of material business partners and inventory of embedded systems in field locations. The following table summarizes the current overall status of the project with anticipated completion dates: <TABLE> <CAPTION> PHASE ASSESSMENT/ REMEDIATION/ COMPONENT INVENTORY PRIORITIZATION CONTINGENCY ------------------------------ ------------- -------------- ------------- <S> <C> <C> <C> Software March 1999 May 1999 September 1999 Hardware March 1999 April 1999 June 1999 Business partners March 1999 May 1999 June 30, 1999 Embedded systems (non-IT systems) May 1999 June 1999 September 1999 </TABLE> In addition to the above, during the third quarter of 1999 the Company will develop an overall contingency plan to assure continued operations which will include precautionary measures. Cost. To date, the Company has incurred minimal consulting costs for Year 2000 project planning and scope definition. The Company plans to acquire a Year 2000 assessment and testing suite in early 1999 for approximately $50,000 and to use contract staff to assist in the financial systems upgrade at a projected cost of $70,000. For currently identified software systems requiring a Year 2000 upgrade, the vendor is providing that upgrade under the terms of existing maintenance agreements, and thus no additional license or upgrade fees are required. In all cases these upgrades had been previously scheduled to maintain desired vendor support and no upgrade project schedule has been accelerated to achieve Year 2000 compliance, nor has any project been deferred because of Year 2000 concerns or efforts. An accurate cost cannot be determined prior to conclusion of the Assessment/Prioritization phase, but it is expected total project expenditures, including the use of outside consultants, should not exceed $1 million. This does not include any costs which may be assessed by joint venture partners on properties not operated by the Company. Risks/Contingency. The failure to remediate critical systems (software, hardware or embedded systems), or the failure of a material business partner to resolve critical Year 2000 issues, could have a serious adverse impact on the 34
35 ability of the Company to continue operations and meet obligations. At the current time, it is believed that any interruption in operation will be minor and short-lived and will pose no safety or environmental risks. However, until all assessment phases have been completed, it is impossible to accurately identify the risks, quantify potential impacts or establish a contingency plan. The Company has not yet clearly identified the most reasonably likely worst case scenario if the Company and material business partners do not achieve Year 2000 compliance on a timely basis. The Company currently intends to complete its contingency planning by September 30, 1999, with testing and training to take place early in the fourth quarter. RECENTLY ISSUED ACCOUNTING STANDARDS On June 15, 1998, the Financial Accounting Standards Board issued FAS No. 133, Accounting for Derivative Instruments and Hedging Activities ("FAS 133"). FAS 133 establishes a new model for accounting for derivatives and hedging activities and supersedes and amends a number of existing standards. FAS 133 is effective for all fiscal quarters of fiscal years beginning after June 15, 1999. FAS 133 standardizes the accounting for derivative instruments by requiring that all derivatives be recognized as assets and liabilities and measured at fair value. The accounting for changes in the fair value of derivatives (gains and losses) depends on (i) whether the derivative is designated and qualifies as a hedge, and (ii) the type of hedging relationship that exists. Changes in the fair value of derivatives that are not designated as hedges or that do not meet the hedge accounting criteria in FAS 133 are required to be reported in earnings. In addition, all hedging relationships must be designated, reassessed and documented pursuant to the provisions of FAS 133. The Company has not yet determined the impact that adoption of FAS 133 will have on the financial statements. FORWARD LOOKING STATEMENTS This Form 10-K 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. All statements other than statements of historical facts included in this Form 10-K, including, without limitation, statements regarding oil and gas reserve estimates, planned capital expenditures, expected oil and gas production, the Company's financial position, business strategy and other plans and objectives for future operations, expected future expenses, realization of deferred tax assets, and Year 2000 compliance efforts, are forward-looking statements. Although the Company believes that the expectations reflected in such forward-looking statements are reasonable, it can give no assurance that such expectations will prove to have been correct. Factors that could cause actual results to differ materially from those expected by the Company, including, without limitation, factors discussed under Risk Factors in Item 1 of this Form 10-K, are substantial indebtedness, impairment of asset value, need to replace reserves, substantial capital requirements, ability to supplement capital resources with asset sales, fluctuations in the prices of oil and gas, uncertainties inherent in estimating quantities of oil and gas reserves, projecting future rates of production and the timing of development expenditures, competition, operating risks, restrictions imposed by lenders, liquidity and capital requirements, the effects of governmental and environmental regulation, pending patent and securities litigation, adverse changes in the market for the Company's oil and gas production and the Company's ability to successfully address Year 2000 issues. Readers are cautioned not to place undue reliance on these forward-looking statements, which speak only as of the date hereof. The Company undertakes no obligation to release publicly the result of any revisions to these forward-looking statements that may be made to reflect events or circumstances after the date hereof, including, without limitation, changes in the Company's business strategy or planned capital expenditures, or to reflect the occurrence of unanticipated events. ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK COMMODITY PRICE RISK The Company's results of operations are highly dependent upon the prices received for oil and natural gas production. 35
36 Periodically the Company utilizes hedging strategies to hedge the price of a portion of its future oil and gas production. These strategies include (i) swap arrangements that establish an index-related price above which the Company pays the counterparty and below which the Company is paid by the counterparty, (ii) the purchase of index-related puts that provide for a "floor" price below which the counterparty pays the Company the amount by which the price of the commodity is below the contracted floor, (iii) the sale of index-related calls that provide for a "ceiling" price above which the Company pays the counterparty the amount by which the price of the commodity is above the contracted ceiling, and (iv) basis protection swaps, which are arrangements that guarantee the price differential of oil or gas from a specified delivery point or points. Results from commodity hedging transactions are reflected in oil and gas sales to the extent related to the Company's oil and gas production. The Company only enters into commodity hedging transactions related to the Company's oil and gas production volumes or CEMI's physical purchase or sale commitments. Gains or losses on crude oil and natural gas hedging transactions are recognized as price adjustments in the months of related production. As of December 31, 1998, the Company had the following natural gas swap arrangements designed to hedge a portion of the Company's domestic gas production for periods after December 1998: <TABLE> <CAPTION> NYMEX-INDEX VOLUME STRIKE PRICE MONTHS (MMBTU) (PER MMBTU) - ------ ------------- ------------- <S> <C> <C> February 1999.................................................................... 4,300,000 $ 1.968 March 1999....................................................................... 4,600,000 1.968 April 1999....................................................................... 4,500,000 1.968 May 1999......................................................................... 4,600,000 1.968 June 1999........................................................................ 1,200,000 1.950 July 1999........................................................................ 1,240,000 1.950 August 1999...................................................................... 1,240,000 1.950 September 1999................................................................... 1,200,000 1.950 </TABLE> During 1998, the Company closed transactions for natural gas previously hedged for the period April 1999 through November 1999 for net proceeds of $0.5 million. Subsequent to December 31, 1998, the Company entered into additional natural gas swap arrangements for 6,100,000 MMBtu at a strike price of $1.875 for the period from June 1999 through September 1999. Such swap arrangements, along with those listed above and other miscellaneous transactions, were closed as of March 15, 1999, resulting in net proceeds of $4.7 million. As of December 31, 1998, the Company had the following natural gas swap arrangements designed to hedge a portion of the Company's Canadian gas production for periods after December 1998: <TABLE> <CAPTION> VOLUME INDEX STRIKE PRICE MONTHS (MMBTU) (PER MMBTU) - ------ --------------- ----------------- <S> <C> <C> January 1999........................................................... 589,000 $ 1.60 February 1999.......................................................... 532,000 1.60 March 1999............................................................. 589,000 1.60 April 1999............................................................. 570,000 1.60 May 1999............................................................... 589,000 1.60 June 1999.............................................................. 570,000 1.60 July 1999.............................................................. 589,000 1.60 August 1999............................................................ 589,000 1.60 September 1999......................................................... 570,000 1.60 </TABLE> If the swap arrangements listed above had been settled on December 31, 1998, the Company would have incurred a loss of $0.8 million. 36
37 As of December 31, 1998, the Company had the following oil swap arrangements for periods after December 1998: <TABLE> <CAPTION> NYMEX HEATING OIL MINUS MONTHLY NYMEX CRUDE OIL VOLUME INDEX STRIKE PRICE MONTHS (BBLS) (PER BBL) - ------ --------------- ---------------- <S> <C> <C> January 1999........................................................... 217,000 $ 2.957 February 1999.......................................................... 196,000 2.957 March 1999............................................................. 155,000 2.900 </TABLE> If the swap arrangements listed above had been settled on December 31, 1998, the Company would have incurred a loss of $0.2 million. Subsequent to December 31, 1998, the Company settled the swap arrangements listed above for the periods of January 1999 and February 1999 resulting in a $0.4 million loss. In addition to commodity hedging transactions related to the Company's oil and gas production, CEMI periodically enters into various hedging transactions designed to hedge against physical purchase commitments made by CEMI. Gains or losses on these transactions are recorded as adjustments to Oil and Gas Marketing Sales in the consolidated statements of operations and are not considered by management to be material. INTEREST RATE RISK The Company also utilizes hedging strategies to manage fixed-interest rate exposure. Through the use of a swap arrangement, the Company believes it can benefit from stable or falling interest rates and reduce its current interest expense. For the year ended December 31, 1998, the Company's interest rate swap resulted in a $0.7 million reduction of interest expense. The table below presents principal cash flows and related weighted average interest rates by expected maturity dates. As of December 31, 1998, the carrying amounts of short-term borrowings are representative of fair values because of the short-term maturity of these instruments. The fair value of the long-term debt has been estimated based on quoted market prices. <TABLE> <CAPTION> DECEMBER 31, 1998 ---------------------------------------------------------------------------------------- EXPECTED FISCAL YEAR OF MATURITY ---------------------------------------------------------------------------------------- 1999 2000 2001 2002 2003 THEREAFTER TOTAL FAIR VALUE -------- ------- ------- ------- ------- ---------- -------- ---------- <S> <C> <C> <C> <C> <C> <C> <C> <C> LIABILITIES: ($ IN MILLIONS) Short-term debt - variable rate ........ $ 25 $ -- $ -- $ -- $ -- $ -- $ 25 $ 25 Average interest rate ................ 7.75% -- -- -- -- -- Long-term debt, including current portion - fixed rate ................. $ -- $ -- $ -- $ -- $ -- $ 920 $ 920 $ 655 Average interest rate ................ -- -- -- -- -- 9.1% </TABLE> 37
38 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA INDEX TO CONSOLIDATED FINANCIAL STATEMENTS <TABLE> <CAPTION> PAGE ---- <S> <C> Consolidated Financial Statements: Report of Independent Accountants for the Year Ended December 31, 1998, for the Six Months Ended December 31, 1997 and for the Years Ended June 30, 1997 and 1996.......................................... 39 Consolidated Balance Sheets at December 31, 1998 and 1997 and at June 30, 1997................................ 40 Consolidated Statements of Operations for the Year Ended December 31, 1998, for the Six Months Ended December 31, 1997 and for the Years Ended June 30, 1997 and 1996.......................................... 41 Consolidated Statements of Cash Flows for the Year Ended December 31, 1998, for the Six Months Ended December 31, 1997 and for the Years Ended June 30, 1997 and 1996.......................................... 42 Consolidated Statements of Stockholders' Equity (Deficit) and Comprehensive Income (Loss) for the Year Ended December 31, 1998, for the Six Months Ended December 31, 1997 and for the Years Ended June 30, 1997 and 1996..................................................................................... 44 Notes to Consolidated Financial Statements..................................................................... 45 Financial Statement Schedules: Schedule II - Valuation and Qualifying Accounts................................................................ 77 </TABLE> 38
39 REPORT OF INDEPENDENT ACCOUNTANTS To the Board of Directors and Stockholders of Chesapeake Energy Corporation In our opinion, the consolidated financial statements listed in the accompanying index present fairly, in all material respects, the financial position of Chesapeake Energy Corporation and its subsidiaries (the "Company") at December 31, 1998 and 1997, and at June 30, 1997, and the results of their operations and their cash flows for the year ended December 31, 1998, for the six months ended December 31, 1997, and for the years ended June 30, 1997 and 1996, in conformity with generally accepted accounting principles. In addition, in our opinion, the financial statement schedules listed in the accompanying index presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedules are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with generally accepted auditing standards which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for the opinion expressed above. PRICEWATERHOUSECOOPERS LLP Oklahoma City, Oklahoma March 18, 1999 39
40 CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS ASSETS <TABLE> <CAPTION> DECEMBER 31, JUNE 30, -------------------------- ----------- 1998 1997 1997 ----------- ----------- ----------- ($ IN THOUSANDS) <S> <C> <C> <C> CURRENT ASSETS: Cash and cash equivalents ................................................. $ 29,520 $ 123,860 $ 124,017 Restricted cash ........................................................... 5,754 -- -- Short-term investments .................................................... -- 12,570 104,485 Accounts receivable: Oil and gas sales ....................................................... 13,835 10,654 10,906 Oil and gas marketing sales ............................................. 19,636 20,493 19,939 Joint interest and other, net of allowances of $3,209,000, $691,000 and $387,000, respectively ............................................ 27,373 38,781 25,311 Related parties ......................................................... 15,455 4,246 7,401 Inventory ................................................................. 5,325 5,493 4,854 Other ..................................................................... 1,101 1,624 692 ----------- ----------- ----------- Total Current Assets ............................................... 117,999 217,721 297,605 ----------- ----------- ----------- PROPERTY AND EQUIPMENT: Oil and gas properties, at cost based on full-cost accounting: Evaluated oil and gas properties ........................................ 2,142,943 1,095,363 865,516 Unevaluated properties .................................................. 52,687 125,155 128,505 Less: accumulated depreciation, depletion and amortization .......................................................... (1,574,282) (602,391) (431,983) ----------- ----------- ----------- 621,348 618,127 562,038 Other property and equipment .............................................. 79,718 67,633 50,379 Less: accumulated depreciation and amortization ........................... (37,075) (6,573) (5,051) ----------- ----------- ----------- Total Property and Equipment ....................................... 663,991 679,187 607,366 ----------- ----------- ----------- OTHER ASSETS ................................................................ 30,625 55,876 44,097 ----------- ----------- ----------- TOTAL ASSETS ................................................................ $ 812,615 $ 952,784 $ 949,068 =========== =========== =========== </TABLE> LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT) <TABLE> <S> <C> <C> <C> CURRENT LIABILITIES: Notes payable and current maturities of long-term debt .................... $ 25,000 $ -- $ 1,380 Accounts payable .......................................................... 36,854 81,775 86,817 Accrued liabilities and other ............................................. 46,572 42,733 28,701 Revenues and royalties due others ......................................... 22,858 28,972 29,428 ----------- ----------- ----------- Total Current Liabilities .......................................... 131,284 153,480 146,326 ----------- ----------- ----------- LONG-TERM DEBT, NET ......................................................... 919,076 508,992 508,950 ----------- ----------- ----------- REVENUES AND ROYALTIES DUE OTHERS ........................................... 10,823 10,106 6,903 ----------- ----------- ----------- CONTINGENCIES AND COMMITMENTS (NOTE 4) STOCKHOLDERS' EQUITY (DEFICIT): Preferred Stock, $.01 par value, 10,000,000 shares authorized; 4,600,000, 0 and 0 shares of 7% cumulative convertible stock issued and outstanding at December 31, 1998 and 1997, and June 30, 1997, respectively, entitled in liquidation to $230 million .... 230,000 -- -- Common Stock, par value of $.01, 250,000,000 shares authorized; 105,213,750, 74,298,061 and 70,276,975 shares issued and outstanding at December 31, 1998 and 1997, and June 30, 1997, respectively .......... 1,052 743 703 Paid-in capital ........................................................... 682,263 460,770 432,991 Accumulated earnings (deficit) ............................................ (1,127,195) (181,270) (146,805) Accumulated other comprehensive income (loss) ............................. (4,726) (37) -- Less: treasury stock, at cost; 8,503,300, 0 and 0 shares at December 31, 1998 and 1997, and June 30, 1997, respectively ............... (29,962) -- -- ----------- ----------- ----------- Total Stockholders' Equity (Deficit) ............................... (248,568) 280,206 286,889 ----------- ----------- ----------- TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT) ........................ $ 812,615 $ 952,784 $ 949,068 =========== =========== =========== </TABLE> The accompanying notes are an integral part of these consolidated financial statements. 40
41 CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF OPERATIONS <TABLE> <CAPTION> YEAR ENDED SIX MONTHS ENDED YEAR ENDED JUNE 30, DECEMBER 31, DECEMBER 31, -------------------------- 1998 1997 1997 1996 ----------- ----------- ----------- ----------- ($ IN THOUSANDS, EXCEPT PER SHARE DATA) <S> <C> <C> <C> <C> REVENUES: Oil and gas sales ............................................... $ 256,887 $ 95,657 $ 192,920 $ 110,849 Oil and gas marketing sales ..................................... 121,059 58,241 76,172 28,428 Oil and gas service operations .................................. -- -- -- 6,314 ----------- ----------- ----------- ----------- Total Revenues ................................................ 377,946 153,898 269,092 145,591 ----------- ----------- ----------- ----------- OPERATING COSTS: Production expenses ............................................. 51,202 7,560 11,445 6,340 Production taxes ................................................ 8,295 2,534 3,662 1,963 Oil and gas marketing expenses .................................. 119,008 58,227 75,140 27,452 Oil and gas service operations .................................. -- -- -- 4,895 Impairment of oil and gas properties ............................ 826,000 110,000 236,000 -- Impairment of other assets ...................................... 55,000 -- -- -- Oil and gas depreciation, depletion and amortization ............ 146,644 60,408 103,264 50,899 Depreciation and amortization of other assets ................... 8,076 2,414 3,782 3,157 General and administrative ...................................... 19,918 5,847 8,802 4,828 ----------- ----------- ----------- ----------- Total Operating Costs ......................................... 1,234,143 246,990 442,095 99,534 ----------- ----------- ----------- ----------- INCOME (LOSS) FROM OPERATIONS ..................................... (856,197) (93,092) (173,003) 46,057 ----------- ----------- ----------- ----------- OTHER INCOME (EXPENSE): Interest and other income ....................................... 3,926 78,966 11,223 3,831 Interest expense ................................................ (68,249) (17,448) (18,550) (13,679) ----------- ----------- ----------- ----------- (64,323) 61,518 (7,327) (9,848) ----------- ----------- ----------- ----------- INCOME (LOSS) BEFORE INCOME TAXES AND EXTRAORDINARY ITEM ............................................................ (920,520) (31,574) (180,330) 36,209 PROVISION (BENEFIT) FOR INCOME TAXES .............................. -- -- (3,573) 12,854 ----------- ----------- ----------- ----------- INCOME (LOSS) BEFORE EXTRAORDINARY ITEM ........................... (920,520) (31,574) (176,757) 23,355 EXTRAORDINARY ITEM: Loss on early extinguishment of debt, net of applicable income tax of $0 and $3,804,000, respectively .................................................. (13,334) -- (6,620) -- ----------- ----------- ----------- ----------- NET INCOME (LOSS) ................................................. (933,854) (31,574) (183,377) 23,355 PREFERRED STOCK DIVIDENDS ......................................... (12,077) -- -- -- ----------- ----------- ----------- ----------- NET INCOME (LOSS) AVAILABLE TO COMMON SHAREHOLDERS ................ $ (945,931) $ (31,574) $ (183,377) $ 23,355 =========== =========== =========== =========== EARNINGS (LOSS) PER COMMON SHARE: EARNINGS (LOSS) PER COMMON SHARE-BASIC: Income (loss) before extraordinary item ....................... $ (9.83) $ (0.45) $ (2.69) $ 0.43 Extraordinary item ............................................ (0.14) -- (0.10) -- ----------- ----------- ----------- ----------- Net income (loss) ............................................. $ (9.97) $ (0.45) $ (2.79) $ 0.43 =========== =========== =========== =========== EARNINGS (LOSS) PER COMMON SHARE-ASSUMING DILUTION: Income (loss) before extraordinary item ....................... $ (9.83) $ (0.45) $ (2.69) $ 0.40 Extraordinary item ............................................ (0.14) -- (0.10) -- ----------- ----------- ----------- ----------- Net income (loss) ............................................. $ (9.97) $ (0.45) $ (2.79) $ 0.40 =========== =========== =========== =========== WEIGHTED AVERAGE COMMON AND COMMON EQUIVALENT SHARES OUTSTANDING (IN 000'S): Basic ......................................................... 94,911 70,835 65,767 54,564 =========== =========== =========== =========== Assuming Dilution ............................................. 94,911 70,835 65,767 58,342 =========== =========== =========== =========== </TABLE> The accompanying notes are an integral part of these consolidated financial statements. 41
42 CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS <TABLE> <CAPTION> YEAR ENDED SIX MONTHS ENDED YEAR ENDED JUNE 30, DECEMBER 31, DECEMBER 31, ---------------------------- 1998 1997 1997 1996 ------------ ------------ ------------ ------------ ($ IN THOUSANDS) <S> <C> <C> <C> <C> CASH FLOWS FROM OPERATING ACTIVITIES: NET INCOME (LOSS) ................................................ $ (933,854) $ (31,574) $ (183,377) $ 23,355 ADJUSTMENTS TO RECONCILE NET INCOME (LOSS) TO CASH PROVIDED BY OPERATING ACTIVITIES: Depreciation, depletion and amortization ....................... 152,204 62,028 105,591 52,768 Impairment of oil and gas assets ............................... 826,000 110,000 236,000 -- Impairment of other assets ..................................... 55,000 -- -- Deferred taxes ................................................. -- -- (3,573) 12,854 Amortization of loan costs ..................................... 2,516 794 1,455 1,288 Amortization of bond discount .................................. 98 41 217 563 Bad debt expense ............................................... 1,589 40 299 114 Gain on sale of Bayard stock ................................... -- (73,840) -- -- Gain on sale of fixed assets ................................... (90) (209) (1,593) (2,511) Extraordinary loss ............................................. 13,334 -- 6,620 -- Equity in (earnings) losses from investments ................... 703 592 (499) -- ------------ ------------ ------------ ------------ Cash provided by operating activities before changes in current assets and liabilities ....................................... 117,500 67,872 161,140 88,431 ------------ ------------ ------------ ------------ CHANGES IN ASSETS AND LIABILITIES: (Increase) decrease in short-term investments .................. 12,027 92,127 (102,858) 622 (Increase) decrease in accounts receivable ..................... 12,191 (7,173) (19,987) (3,524) (Increase) decrease in inventory ............................... 168 (1,584) (1,467) 78 (Increase) decrease in other current assets .................... 7,637 (1,519) 1,466 (1,525) Increase (decrease) in accounts payable, accrued liabilities and other ........................................ (46,785) (11,044) 48,085 25,834 Increase (decrease) in current and non-current revenues and royalties due others ..................................... (8,099) 478 (2,290) 11,056 ------------ ------------ ------------ ------------ Changes in assets and liabilities ............................ (22,861) 71,285 (77,051) 32,541 ------------ ------------ ------------ ------------ Cash provided by operating activities ........................ 94,639 139,157 84,089 120,972 ------------ ------------ ------------ ------------ CASH FLOWS FROM INVESTING ACTIVITIES: Exploration and development of oil and gas properties .......... (260,006) (189,755) (468,462) (342,045) Acquisitions of oil and gas companies and properties, net of cash acquired ................................................ (279,924) -- -- -- Investment in preferred stock of Gothic Energy Corporation ..... (39,500) -- -- -- Proceeds from sale of oil and gas equipment, leasehold and other ........................................................ 16,008 2,503 3,095 6,167 Net proceeds from sale of Bayard stock ......................... -- 90,380 -- -- Repayment of note receivable ................................... 2,000 18,000 -- -- Proceeds from sale of investment in PanEast .................... 21,245 -- -- Other proceeds from sales ...................................... 3,600 17 6,428 698 Long-term loans made to third parties .......................... -- -- (20,000) -- Investment in oil field service company ........................ -- (200) (3,048) -- Investment in gas marketing company, net of cash acquired ...... -- -- -- (363) Other investments .............................................. -- (30,434) (8,000) -- Other property and equipment additions ......................... (11,473) (27,015) (33,867) (8,846) ------------ ------------ ------------ ------------ Cash used in investing activities ............................ (548,050) (136,504) (523,854) (344,389) ------------ ------------ ------------ ------------ CASH FLOWS FROM FINANCING ACTIVITIES: Proceeds from issuance of common stock ......................... -- -- 288,091 99,498 Proceeds from long-term borrowings ............................. 658,750 -- 342,626 166,667 Payments on long-term borrowings ............................... (474,166) -- (119,581) (48,634) Dividends paid on common stock ................................. (5,592) (2,810) -- -- Dividends paid on preferred stock .............................. (8,050) -- -- -- Proceeds from issuance of preferred stock ...................... 222,663 -- -- -- Purchase of treasury stock ..................................... (29,962) -- -- -- Cash received from exercise of stock options ................... -- 322 1,387 1,989 Other financing ................................................ 154 (322) (379) -- ------------ ------------ ------------ ------------ Cash provided by (used in) financing activities .............. 363,797 (2,810) 512,144 219,520 ------------ ------------ ------------ ------------ EFFECT OF EXCHANGE RATE CHANGES ON CASH .......................... (4,726) -- -- -- ------------ ------------ ------------ ------------ Net increase (decrease) in cash and cash equivalents ............. (94,340) (157) 72,379 (3,897) Cash and cash equivalents, beginning of period ................... 123,860 124,017 51,638 55,535 ------------ ------------ ------------ ------------ Cash and cash equivalents, end of period ......................... $ 29,520 $ 123,860 $ 124,017 $ 51,638 ============ ============ ============ ============ </TABLE> The accompanying notes are an integral part of these consolidated financial statements. 42
43 CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS -- (CONTINUED) <TABLE> <CAPTION> YEAR ENDED SIX MONTHS ENDED YEAR ENDED JUNE 30, DECEMBER 31, DECEMBER 31, --------------------- 1998 1997 1997 1996 ------------- ------------- --------- --------- ($ IN THOUSANDS) <S> <C> <C> <C> <C> SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION CASH PAYMENTS FOR: Interest, net of capitalized interest ......................... $ 59,881 $ 17,367 $ 12,919 $ 10,751 Income taxes .................................................. $ -- $ 500 $ -- $ -- DETAILS OF ACQUISITION OF ANSON PRODUCTION CORPORATION: Fair value of assets acquired ................................. $ -- $ 43,000 $ -- $ -- Accrued liability for estimated cash consideration ............ $ -- $ (15,500) $ -- $ -- Stock issued (3,792,724 shares) ............................... $ -- $ (27,500) $ -- $ -- DETAILS OF ACQUISITION OF DLB OIL & GAS, INC.: Fair value of assets acquired ................................. $ 136,500 $ -- $ -- $ -- Cash consideration ............................................ $ (17,500) $ -- $ -- $ -- Stock issued (5,000,000 shares) ............................... $ (30,000) $ -- $ -- $ -- Debt assumed .................................................. $ (85,000) $ -- $ -- $ -- Acquisition costs paid ........................................ $ (4,000) $ -- $ -- $ -- DETAILS OF ACQUISITION OF HUGOTON ENERGY CORPORATION: Fair value of assets acquired ................................. $ 343,371 $ -- $ -- $ -- Stock options granted ......................................... $ (2,050) $ -- $ -- $ -- Stock issued (25,790,146 shares) .............................. $ (206,321) $ -- $ -- $ -- Debt assumed .................................................. $ (120,000) $ -- $ -- $ -- Acquisition costs paid ........................................ $ (15,000) $ -- $ -- $ -- </TABLE> SUPPLEMENTAL SCHEDULE OF NON-CASH INVESTING AND FINANCING ACTIVITIES: The Company had a financing arrangement with a vendor to supply certain oil and gas equipment inventory, which was terminated during the Transition Period. The total amounts owed at June 30, 1997 and 1996 were $1,380,000 and $3,156,000, respectively. No cash consideration is exchanged for inventory under this financing arrangement until actual draws on the inventory are made. In fiscal 1997 and 1996, the Company recognized income tax benefits of $4,808,000 and $7,950,000, respectively, related to the disposition of stock options by directors and employees of the Company. The tax benefits were recorded as an adjustment to deferred income taxes and paid-in capital. Proceeds from the issuance of $500 million of 9.625% senior notes in April 1998, $300 million of senior notes ($150 million of 7.875% senior notes and $150 million of 8.5% senior notes) in March 1997, and $120 million of 9.125% senior notes in April 1996 are net of $11.7 million, $6.4 million and $3.9 million, respectively, in offering fees and expenses which were deducted from the actual cash received. On December 22, 1997, the Company declared a dividend of $0.02 per common share, or $1,486,000, which was paid on January 15, 1998. On June 13, 1997 the Company declared a dividend of $0.02 per common share, or $1,405,000, which was paid on July 15, 1997. The accompany notes are an integral part of these consolidated financial statements. 43
44 CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (DEFICIT) AND COMPREHENSIVE INCOME (LOSS) <TABLE> <CAPTION> YEAR ENDED SIX MONTHS ENDED YEAR ENDED JUNE 30, DECEMBER 31, DECEMBER 31, -------------------------- 1998 1997 1997 1996 ------------- ------------- ----------- ----------- ($ IN THOUSANDS) <S> <C> <C> <C> <C> PREFERRED STOCK: Balance, beginning of period ................................... $ -- $ -- $ -- $ -- Issuance of preferred stock .................................... 230,000 -- -- -- ------------- ------------- ----------- ----------- Balance, end of period ......................................... 230,000 -- -- -- ------------- ------------- ----------- ----------- COMMON STOCK: Balance, beginning of period ................................... 743 703 3,008 58 Issuance of 8,972,000 shares of common stock ................... -- -- 90 -- Issuance of 5,989,500 shares of common stock ................... -- -- -- 299 Exercise of stock options and warrants ......................... -- 2 12 79 Issuance of 3,792,724 shares of common stock to AnSon Production Corporation .......................... -- 38 -- -- Issuance of 25,790,146 shares of common stock to Hugoton Energy Corporation ................................... 258 -- -- -- Issuance of 5,000,000 shares of common stock to DLB Oil and Gas, Inc. ........................................ 50 -- -- -- Change in par value and other .................................. 1 -- (2,407) 2,572 ------------- ------------- ----------- ----------- Balance, end of period ......................................... 1,052 743 703 3,008 ------------- ------------- ----------- ----------- PAID-IN CAPITAL: Balance, beginning of period ................................... 460,733 432,991 136,782 30,295 Exercise of stock options and warrants ......................... 153 320 1,375 1,910 Issuance of common stock ....................................... 236,013 27,459 301,593 105,516 Offering expenses and other .................................... (16,686) -- (13,974) (6,317) Stock options issued in Hugoton purchase ....................... 2,050 -- -- -- Tax benefit from exercise of stock options ..................... -- -- 4,808 7,950 Change in par value ............................................ -- -- 2,407 (2,572) ------------- ------------- ----------- ----------- Balance, end of period ......................................... 682,263 460,770 432,991 136,782 ------------- ------------- ----------- ----------- ACCUMULATED EARNINGS (DEFICIT): Balance, beginning of period ................................... (181,270) (146,805) 37,977 14,622 Net income (loss) .............................................. (933,854) (31,574) (183,377) 23,355 Dividends on common stock ...................................... (4,021) (2,891) (1,405) -- Dividends on preferred stock ................................... (8,050) -- -- -- ------------- ------------- ----------- ----------- Balance, end of period ......................................... (1,127,195) (181,270) (146,805) 37,977 ------------- ------------- ----------- ----------- ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS): Balance, beginning of period ................................... (37) -- -- -- Foreign currency translation adjustments ....................... (4,689) (37) -- -- ------------- ------------- ----------- ----------- Balance, end of period ......................................... (4,726) (37) -- -- ------------- ------------- ----------- ----------- TREASURY STOCK: Balance, beginning of period ................................... -- -- -- -- Purchases of treasury stock .................................... (29,962) -- -- -- ------------- ------------- ----------- ----------- Balance, end of period ......................................... (29,962) -- -- -- ------------- ------------- ----------- ----------- TOTAL STOCKHOLDERS' EQUITY (DEFICIT) ............................. $ (248,568) $ 280,206 $ 286,889 $ 177,767 ============= ============= =========== =========== COMPREHENSIVE INCOME (LOSS): Net income (loss) .............................................. $ (933,854) $ (31,574) $ (183,377) $ 23,355 Other comprehensive income (loss) - foreign currency translation adjustments ...................................... (4,689) (37) -- -- ------------- ------------- ----------- ----------- Comprehensive income (loss) .................................... $ (938,543) $ (31,611) $ (183,377) $ 23,355 ============= ============= =========== =========== </TABLE> The accompanying notes are an integral part of these consolidated financial statements. 44
45 CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Description of Company The Company is a petroleum exploration and production company engaged in the acquisition, exploration, and development of properties for the production of crude oil and natural gas from underground reservoirs. The Company's properties are located in Oklahoma, Texas, Louisiana, Kansas, Montana, Colorado, North Dakota, New Mexico and British Columbia, Canada. The Company changed its fiscal year end from June 30 to December 31 in 1997. The Company's results of operations and cash flows for the six months ended December 31, 1997 (the "Transition Period") are included in these consolidated financial statements. Principles of Consolidation The accompanying consolidated financial statements of Chesapeake Energy Corporation include the accounts of its direct and indirect wholly-owned subsidiaries (the "Company"). All significant intercompany accounts and transactions have been eliminated. Investments in companies and partnerships which give the Company significant influence, but not control, over the investee are accounted for using the equity method. Accounting Estimates The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the dates of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from those estimates. Cash Equivalents For purposes of the consolidated financial statements, the Company considers investments in all highly liquid debt instruments with maturities of three months or less at date of purchase to be cash equivalents. Investments in Securities The Company invests in various equity securities and short-term debt instruments including corporate bonds and auction preferreds, commercial paper and government agency notes. The Company has classified all of its short-term investments in equity and debt instruments as trading securities, which are carried at fair value with unrealized holding gains and losses included in earnings. At December 31, 1998 and 1997, the Company had an unrealized holding loss of $0 and $2.4 million, respectively, included in interest and other income. At June 30, 1997, the Company had an unrealized holding loss of $0.6 million included in interest and other income. At June 30, 1996 the Company had no trading securities. Investments in equity securities and limited partnerships that do not have readily determinable fair values are stated at cost and are included in noncurrent other assets. In determining realized gains and losses, the cost of securities sold is based on the average cost method. Inventory Inventory consists primarily of tubular goods and other lease and well equipment which the Company plans to utilize in its ongoing exploration and development activities and is carried at the lower of cost or market using the specific identification method. 45
46 Oil and Gas Properties The Company follows the full-cost method of accounting under which all costs associated with property acquisition, exploration and development activities are capitalized. The Company capitalizes internal costs that can be directly identified with its acquisition, exploration and development activities and does not include any costs related to production, general corporate overhead or similar activities (see Note 11). Capitalized costs are amortized on a composite unit-of-production method based on proved oil and gas reserves. As of December 31, 1998, approximately 76% of the Company's proved reserve value (based on SEC PV10%) was evaluated by independent petroleum engineers, with the balance evaluated by the Company's engineers. In addition, the company's engineers evaluate all properties quarterly. The average composite rates used for depreciation, depletion and amortization were $1.13 ($1.17 in U.S. and $0.43 in Canada) per equivalent Mcf in 1998, $1.57 per equivalent Mcf in the Transition Period and $1.31 and $0.85 per equivalent Mcf in fiscal 1997 and 1996, respectively. Proceeds from the sale of properties are accounted for as reductions to capitalized costs unless such sales involve a significant change in the relationship between costs and the value of proved reserves or the underlying value of unproved properties, in which case a gain or loss is recognized. The costs of unproved properties are excluded from amortization until the properties are evaluated. The Company reviews all of its unevaluated properties quarterly to determine whether or not and to what extent proved reserves have been assigned to the properties, and otherwise if impairment has occurred. Unevaluated properties are grouped by major producing area where individual property costs are not significant, and assessed individually when individual costs are significant. The Company reviews the carrying value of its oil and gas properties under the full-cost accounting rules of the Securities and Exchange Commission on a quarterly basis. Under these rules, capitalized costs, less accumulated amortization and related deferred income taxes, shall not exceed an amount equal to the sum of the present value of estimated future net revenues less estimated future expenditures to be incurred in developing and producing the proved reserves, less any related income tax effects. During 1998, capitalized costs of oil and gas properties exceeded the estimated present value of future net revenues from the Company's proved reserves, net of related income tax considerations, resulting in writedowns in the carrying value of oil and gas properties of $826 million. During the Transition Period, capitalized costs of oil and gas properties exceeded the estimated present value of future net revenues from the Company's proved reserves, net of related income tax considerations, resulting in a writedown in the carrying value of oil and gas properties of $110 million. During fiscal 1997, capitalized costs of oil and gas properties exceeded the estimated present value of future net revenues from the Company's proved reserves, net of related income tax considerations, resulting in a writedown in the carrying value of oil and gas properties of $236 million. Other Property and Equipment Other property and equipment consists primarily of gas gathering and processing facilities, vehicles, land, office buildings and equipment, and software. Major renewals and betterments are capitalized while the costs of repairs and maintenance are charged to expense as incurred. The costs of assets retired or otherwise disposed of and the applicable accumulated depreciation are removed from the accounts, and the resulting gain or loss is reflected in operations. 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. All other property and equipment are depreciated over the estimated useful lives of the assets, which range from five to seven years. Capitalized Interest During 1998, the Transition Period and fiscal 1997 and 1996, interest of approximately $6.5 million, $5.1 million, $12.9 million and $6.4 million was capitalized on significant investments in unproved properties that were not being currently depreciated, depleted, or amortized and on which exploration activities were in progress. 46
47 Service Operations Certain subsidiaries of the Company performed contract services on wells the Company operated as well as for third parties until June 30, 1996. Oil and gas service operations revenues and costs and expenses reflected in the accompanying consolidated statement of operations for fiscal 1996 include amounts derived from certain of the contractual services provided. The Company's economic interest in its oil and gas properties was not affected by the performance of these contractual services and all intercompany profits have been eliminated. On June 30, 1996, Peak USA Energy Services, Ltd., a limited partnership ("Peak"), was formed by Peak Oilfield Services Company (a joint venture between Cook Inlet Region, Inc. and Nabors Industries, Inc.) and the Company for the purpose of purchasing the Company's oilfield service assets and providing rig moving, transportation and related site construction services. The Company sold its service company assets to Peak for $6.4 million and simultaneously invested $2.5 million in exchange for a 33.3% partnership interest in Peak. This transaction resulted in recognition of a $1.8 million pre-tax gain during the fourth fiscal quarter of 1996 reported in interest and other. A deferred gain from the sale of service company assets of $0.9 million was amortized to income over the estimated useful lives of the Peak assets. The Company sold its partnership interest in Peak in June 1998. Income Taxes The Company has adopted Statement of Financial Accounting Standards No. 109, Accounting for Income Taxes ("SFAS 109"). SFAS 109 requires deferred tax liabilities or assets to be recognized for the anticipated future tax effects of temporary differences that arise as a result of the differences in the carrying amounts and the tax bases of assets and liabilities. Net Income (Loss) Per Share In February 1997, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 128, Earnings Per Share ("SFAS 128"). SFAS 128 requires presentation of "basic" and "diluted" earnings per share, as defined, on the face of the statement of operations for all entities with complex capital structures. SFAS 128 is effective for financial statements issued for periods ending after December 15, 1997 and requires restatement of all prior period earnings per share amounts. The Company has adopted SFAS 128 and has restated all prior periods presented. SFAS 128 requires a reconciliation of the numerators and denominators of the basic and diluted EPS computations. For 1998, the Transition Period and fiscal 1997, there was no difference between actual weighted average shares outstanding, which are used in computing basic EPS, and diluted weighted average shares, which are used in computing diluted EPS. Options to purchase 11.3 million, 8.3 million and 7.9 million shares of common stock at weighted average exercise prices of $1.86, $5.49 and $7.09 were outstanding during 1998, the Transition Period and fiscal 1997 but were not included in the computation of diluted EPS because the effect of these outstanding options would be antidilutive. A reconciliation for fiscal 1996 is as follows: <TABLE> <CAPTION> Income Shares Per Share (Numerator) (Denominator) Amount ----------- ------------- --------- <S> <C> <C> <C> FOR THE YEAR ENDED JUNE 30, 1996: BASIC EPS Income available to common stockholders.. $ 23,355 54,564 $ 0.43 ======= EFFECT OF DILUTIVE SECURITIES Employee stock options................... -- 3,778 -------- -------- DILUTED EPS Income available to common stockholders and assumed conversions............... $ 23,355 58,342 $ 0.40 ======== ======== ======= </TABLE> 47
48 Gas Imbalances -- Revenue Recognition Revenues from the sale of oil and gas production are recognized when title passes, net of royalties. The Company follows the "sales method" of accounting for its gas revenue whereby the Company recognizes sales revenue on all gas sold to its purchasers, regardless of whether the sales are proportionate to the Company's ownership in the property. A liability is recognized only to the extent that the Company has a net imbalance in excess of the remaining gas reserves on the underlying properties. The Company's net imbalance positions at December 31, 1998 and 1997 and June 30, 1997 were not material. Hedging The Company periodically uses certain instruments to hedge its exposure to price fluctuations on oil and natural gas transactions and interest rates. Recognized gains and losses on hedge contracts are reported as a component of the related transaction. Results of oil and gas hedging transactions are reflected in oil and gas sales to the extent related to the Company's oil and gas production, in oil and gas marketing sales to the extent related to the Company's marketing activities, and in interest expense to the extent so related. Debt Issue Costs Included in other assets are costs associated with the issuance of the Senior Notes. The remaining unamortized costs on these issuances of Senior Notes at December 31, 1998 totaled $19.7 million and are being amortized over the life of the Senior Notes. Comprehensive Income In 1998, the Company adopted SFAS No. 130, Reporting Comprehensive Income. This statement establishes rules for the reporting of comprehensive income and its components. Comprehensive income consists of net income and foreign currency translation adjustments and is presented in the Consolidated Statements of Stockholders' Equity (Deficit) and Comprehensive Income (Loss). The adoption of SFAS 130 had no impact on total stockholders' equity. Prior year financial statements have been reclassified to conform to the SFAS 130 requirements. All balance sheet accounts of foreign operations are translated into U.S. dollars at the year-end rate of exchange and statement of operations items are translated at the weighted average exchange rates for the year. Reclassifications Certain reclassifications have been made to the consolidated financial statements for the Transition Period and the years ended June 30, 1997 and 1996 to conform to the presentation used for the December 31, 1998 consolidated financial statements. 2. SENIOR NOTES On April 22, 1998, the Company issued $500 million principal amount of 9.625% Senior Notes due 2005 ("9.625% Senior Notes"). The 9.625% Senior Notes are redeemable at the option of the Company at any time on or after May 1, 2002 at the redemption prices set forth in the indenture or at the make-whole prices, as set forth in the indenture, if redeemed prior to May 1, 2002. The Company may also redeem at its option up to $167 million of the 9.625% Senior Notes at 109.625% of their principal amount with the proceeds of an equity offering completed prior to May 1, 2001. On March 17, 1997, the Company issued $150 million principal amount of 7.875% Senior Notes due 2004 ("7.875% Senior Notes"). The 7.875% Senior Notes are redeemable at the option of the Company at any time prior to 48
49 March 15, 2004 at the make-whole prices determined in accordance with the indenture. Also on March 17, 1997, the Company issued $150 million principal amount of 8.5% Senior Notes due 2012 ("8.5% Senior Notes"). The 8.5% Senior Notes are redeemable at the option of the Company at any time prior to March 15, 2004 at the make-whole prices determined in accordance with the indenture and, on or after March 15, 2004 at the redemption prices set forth therein. On April 9, 1996, the Company issued $120 million principal amount of 9.125% Senior Notes due 2006 ("9.125% Senior Notes"). The 9.125% Senior Notes are redeemable at the option of the Company at any time prior to April 15, 2001 at the make-whole prices determined in accordance with the indenture and, on or after April 15, 2001 at the redemption prices set forth therein. The Company may also redeem at its option at any time on or prior to April 15, 1999 up to $42 million of the 9.125% Senior Notes at 109.125% of the principal amount thereof with the proceeds of an equity offering. On May 25, 1995, the Company issued $90 million principal amount of 10.5% Senior Notes due 2002 ("10.5% Senior Notes"). In April 1998, the Company purchased all of its 10.5% Senior Notes for approximately $99 million. The early retirement of these notes resulted in an extraordinary charge of $13.3 million. The Company is a holding company and owns no operating assets and has no significant operations independent of its subsidiaries. The Company's obligations under the 9.625% Senior Notes, the 9.125% Senior Notes, the 7.875% Senior Notes and the 8.5% Senior Notes have been fully and unconditionally guaranteed, on a joint and several basis, by each of the Company's "Restricted Subsidiaries" (as defined in the respective indentures governing the Senior Notes) (collectively, the "Guarantor Subsidiaries"). Each of the Guarantor Subsidiaries is a direct or indirect wholly-owned subsidiary of the Company. The senior note indentures contain certain covenants, including covenants limiting the Company and the Guarantor Subsidiaries with respect to asset sales; restricted payments; 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 Company is obligated to repurchase the 9.625% and 9.125% Senior Notes in the event of a change of control or certain asset sales. The senior note indentures also limit the Company's ability to make restricted payments (as defined), including the payment of preferred stock dividends, unless certain tests are met. As of December 31, 1998, the Company was unable to meet the requirements to incur additional unsecured indebtedness, and consequently was not able to pay cash dividends on its 7% cumulative convertible preferred stock on February 1, 1999 (in the amount of $4,025,000). Subsequent payments will be subject to the same restrictions and are dependent upon variables that are beyond the Company's ability to predict. This restriction does not affect the Company's ability to borrow under or expand its secured commercial bank facility. If the Company fails to pay dividends for six quarterly periods, the holders of preferred stock would be entitled to elect two additional members to the Board. Set forth below are condensed consolidating financial statements of the Guarantor Subsidiaries, the Company's subsidiaries which are not guarantors of the Senior Notes (the "Non-Guarantor Subsidiaries") and the Company. Separate audited financial statements of each Guarantor Subsidiary have not been provided because management has determined that they are not material to investors. Chesapeake Energy Marketing, Inc. ("CEMI") was a Non-Guarantor Subsidiary for all periods presented, and the following were additional Non-Guarantor Subsidiaries: Chesapeake Acquisition Corporation during the Transition Period, Chesapeake Canada Corporation during fiscal 1997, and Chesapeake Gas Development Corporation during fiscal 1996. All of the Company's other subsidiaries were Guarantor Subsidiaries during these periods. 49
50 CONDENSED CONSOLIDATING BALANCE SHEET AS OF DECEMBER 31, 1998 ($ IN THOUSANDS) ASSETS <TABLE> <CAPTION> NON- GUARANTOR GUARANTOR SUBSIDIARIES SUBSIDIARIES COMPANY ELIMINATIONS CONSOLIDATED ------------ ------------ ----------- ------------ ------------ <S> <C> <C> <C> <C> <C> CURRENT ASSETS: Cash and cash equivalents ................... $ (11,565) $ 7,000 $ 39,839 $ -- $ 35,274 Short-term investments ...................... -- -- -- -- -- Accounts receivable ......................... 54,384 29,641 270 (7,996) 76,299 Inventory ................................... 4,919 406 -- -- 5,325 Other ....................................... 721 15 365 -- 1,101 ----------- ----------- ----------- ------------ ------------ Total Current Assets ................ 48,459 37,062 40,474 (7,996) 117,999 ----------- ----------- ----------- ------------ ------------ PROPERTY AND EQUIPMENT: Oil and gas properties ...................... 2,142,943 -- -- -- 2,142,943 Unevaluated leasehold ....................... 52,687 -- -- -- 52,687 Other property and equipment ................ 47,628 15,109 16,981 -- 79,718 Less: accumulated depreciation, depletion and amortization ............... (1,601,931) (8,036) (1,390) -- (1,611,357) ----------- ----------- ----------- ------------ ------------ Net Property and Equipment ........... 641,327 7,073 15,591 -- 663,991 ----------- ----------- ----------- ------------ ------------ INVESTMENTS IN SUBSIDIARIES AND INTERCOMPANY ADVANCES ....................... 473,578 -- 481,150 (954,728) -- ----------- ----------- ----------- ------------ ------------ OTHER ASSETS .................................. 10,610 560 19,455 -- 30,625 ----------- ----------- ----------- ------------ ------------ TOTAL ASSETS .................................. $ 1,173,974 $ 44,695 $ 556,670 $ (962,724) $ 812,615 =========== =========== =========== ============ ============ </TABLE> LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT) <TABLE> <CAPTION> <S> <C> <C> <C> <C> <C> CURRENT LIABILITIES: Notes payable and current maturities of long-term debt ............. $ 25,000 $ -- $ -- $ -- $ 25,000 Accounts payable and other .................. 80,786 15,992 17,529 (8,023) 106,284 ----------- ----------- ----------- ------------ ------------ Total Current Liabilities ........... 105,786 15,992 17,529 (8,023) 131,284 ----------- ----------- ----------- ------------ ------------ LONG-TERM DEBT ................................ -- -- 919,076 -- 919,076 ----------- ----------- ----------- ------------ ------------ REVENUES AND ROYALTIES DUE OTHERS ...................................... 10,823 -- -- -- 10,823 ----------- ----------- ----------- ------------ ------------ DEFERRED INCOME TAXES ......................... -- -- -- -- -- ----------- ----------- ----------- ------------ ------------ INTERCOMPANY PAYABLES ......................... 1,338,948 11,376 (1,350,351) 27 -- ----------- ----------- ----------- ------------ ------------ STOCKHOLDERS' EQUITY (DEFICIT): Common Stock ................................ 26 1 957 (17) 967 Other ....................................... (281,609) 17,326 969,459 (954,711) (249,535) ----------- ----------- ----------- ------------ ------------ (281,583) 17,327 970,416 (954,728) (248,568) ----------- ----------- ----------- ------------ ------------ TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT) ............................ $ 1,173,974 $ 44,695 $ 556,670 $ (962,724) $ 812,615 =========== =========== =========== ============ ============ </TABLE> 50
51 CONDENSED CONSOLIDATING BALANCE SHEET AS OF DECEMBER 31, 1997 ($ IN THOUSANDS) ASSETS <TABLE> <CAPTION> NON- GUARANTOR GUARANTOR SUBSIDIARIES SUBSIDIARIES COMPANY ELIMINATIONS CONSOLIDATED ------------ ------------ ------------ ------------- ------------- <S> <C> <C> <C> <C> <C> CURRENT ASSETS: Cash and cash equivalents .................. $ (589) $ 13,999 $ 110,450 $ -- $ 123,860 Short-term investments ..................... -- -- 12,570 -- 12,570 Accounts receivable ........................ 57,476 22,882 1,524 (7,708) 74,174 Inventory .................................. 4,918 575 -- -- 5,493 Other ...................................... 1,613 1 10 -- 1,624 ------------ ------------ ------------ ------------- ------------- Total Current Assets ............... 63,418 37,457 124,554 (7,708) 217,721 ------------ ------------ ------------ ------------- ------------- PROPERTY AND EQUIPMENT: Oil and gas properties ..................... 1,056,118 39,245 -- -- 1,095,363 Unevaluated leasehold ...................... 125,155 -- -- -- 125,155 Other property and equipment ............... 41,740 10,471 15,422 -- 67,633 Less: accumulated depreciation, depletion and amortization .............. (593,359) (14,650) (955) -- (608,964) ------------ ------------ ------------ ------------- ------------- Net property and equipment ........ 629,654 35,066 14,467 -- 679,187 ------------ ------------ ------------ ------------- ------------- INVESTMENTS IN SUBSIDIARIES AND INTERCOMPANY ADVANCES ...................... 91,883 39,830 903,713 (1,035,426) -- ------------ ------------ ------------ ------------- ------------- OTHER ASSETS ................................. 10,189 6,918 38,769 -- 55,876 ------------ ------------ ------------ ------------- ------------- TOTAL ASSETS ................................. $ 795,144 $ 119,271 $ 1,081,503 $ (1,043,134) $ 952,784 ============ ============ ============ ============= ============= </TABLE> LIABILITIES AND STOCKHOLDERS' EQUITY <TABLE> <CAPTION> <S> <C> <C> <C> <C> <C> CURRENT LIABILITIES: Notes payable and current maturities of long-term debt ............ $ -- $ -- $ -- $ -- $ -- Accounts payable and other ................. 104,259 29,649 27,280 (7,708) 153,480 ------------ ------------ ------------ ------------- ------------- Total Current Liabilities .......... 104,259 29,649 27,280 (7,708) 153,480 ------------ ------------ ------------ ------------- ------------- LONG-TERM DEBT ............................... -- -- 508,992 -- 508,992 ------------ ------------ ------------ ------------- ------------- REVENUES AND ROYALTIES DUE OTHERS ..................................... 10,106 -- -- -- 10,106 ------------ ------------ ------------ ------------- ------------- DEFERRED INCOME TAXES ........................ -- -- -- -- -- ------------ ------------ ------------ ------------- ------------- INTERCOMPANY PAYABLES ........................ 853,958 2,959 -- (856,917) -- ------------ ------------ ------------ ------------- ------------- STOCKHOLDERS' EQUITY: Common Stock ............................... 10 3 733 (3) 743 Other ...................................... (173,189) 86,660 544,498 (178,506) 279,463 ------------ ------------ ------------ ------------- ------------- (173,179) 86,663 545,231 (178,509) 280,206 ------------ ------------ ------------ ------------- ------------- TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY ..................................... $ 795,144 $ 119,271 $ 1,081,503 $ (1,043,134) $ 952,784 ============ ============ ============ ============= ============= </TABLE> 51
52 CONDENSED CONSOLIDATING BALANCE SHEET AS OF JUNE 30, 1997 ($ IN THOUSANDS) ASSETS <TABLE> <CAPTION> NON- GUARANTOR GUARANTOR SUBSIDIARIES SUBSIDIARIES COMPANY ELIMINATIONS CONSOLIDATED ------------ ------------ ------------ ------------- ------------- <S> <C> <C> <C> <C> <C> CURRENT ASSETS: Cash and cash equivalents .................. $ (6,534) $ 4,363 $ 126,188 $ -- $ 124,017 Short-term investments ..................... -- 4,324 100,161 -- 104,485 Accounts receivable ........................ 47,379 19,943 3,022 (6,787) 63,557 Inventory .................................. 4,795 59 -- -- 4,854 Other ...................................... 666 26 -- -- 692 ------------ ------------ ------------ ------------- ------------- Total Current Assets ............... 46,306 28,715 229,371 (6,787) 297,605 ------------ ------------ ------------ ------------- ------------- PROPERTY AND EQUIPMENT: Oil and gas properties ..................... 865,485 31 -- -- 865,516 Unevaluated leasehold ...................... 128,519 (14) -- -- 128,505 Other property and equipment ............... 28,653 6,737 14,989 -- 50,379 Less: accumulated depreciation, depletion and amortization .............. (436,276) -- (758) -- (437,034) ------------ ------------ ------------ ------------- ------------- Net Property and Equipment ......... 586,381 6,754 14,231 -- 607,366 ------------ ------------ ------------ ------------- ------------- INVESTMENTS IN SUBSIDIARIES AND INTERCOMPANY ADVANCES ...................... 5,650 (4,833) 680,439 (681,256) -- ------------ ------------ ------------ ------------- ------------- OTHER ASSETS ................................. 4,961 673 38,463 -- 44,097 ------------ ------------ ------------ ------------- ------------- TOTAL ASSETS ................................. $ 643,298 $ 31,309 $ 962,504 $ (688,043) $ 949,068 ============ ============ ============ ============= ============= </TABLE> LIABILITIES AND STOCKHOLDERS' EQUITY <TABLE> <CAPTION> <S> <C> <C> <C> <C> <C> CURRENT LIABILITIES: Notes payable and current maturities of long-term debt ............ $ 1,380 $ -- $ -- $ -- $ 1,380 Accounts payable and other ................. 122,241 17,527 11,965 (6,787) 144,946 ------------ ------------ ------------ ------------- ------------- Total Current Liabilities .......... 123,621 17,527 11,965 (6,787) 146,326 ------------ ------------ ------------ ------------- ------------- LONG-TERM DEBT ............................... -- -- 508,950 -- 508,950 ------------ ------------ ------------ ------------- ------------- REVENUES AND ROYALTIES DUE OTHERS ..................................... 6,903 -- -- -- 6,903 ------------ ------------ ------------ ------------- ------------- DEFERRED INCOME TAXES ........................ -- -- -- -- -- ------------ ------------ ------------ ------------- ------------- INTERCOMPANY PAYABLES ........................ 589,111 1,492 -- (590,603) -- ------------ ------------ ------------ ------------- ------------- STOCKHOLDERS' EQUITY: Common Stock ............................... 11 1 693 (2) 703 Other ...................................... (76,348) 12,289 440,896 (90,651) 286,186 ------------ ------------ ------------ ------------- ------------- (76,337) 12,290 441,589 (90,653) 286,889 ------------ ------------ ------------ ------------- ------------- TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY ..................................... $ 643,298 $ 31,309 $ 962,504 $ (688,043) $ 949,068 ============ ============ ============ ============= ============= </TABLE> 52
53 CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS ($ IN THOUSANDS) <TABLE> <CAPTION> NON- GUARANTOR GUARANTOR SUBSIDIARIES SUBSIDIARIES COMPANY ELIMINATIONS CONSOLIDATED ------------- ------------- ------------- ------------- ------------- <S> <C> <C> <C> <C> <C> FOR THE YEAR ENDED DECEMBER 31, 1998: REVENUES: Oil and gas sales .......................... $ 254,541 $ -- $ -- $ 2,346 $ 256,887 Oil and gas marketing sales ................ -- 225,195 -- (104,136) 121,059 ------------- ------------- ------------- ------------- ------------- Total Revenues ............................. 254,541 225,195 -- (101,790) 377,946 ------------- ------------- ------------- ------------- ------------- OPERATING COSTS: Production expenses and taxes .............. 59,497 -- -- -- 59,497 Oil and gas marketing expenses ............. -- 220,798 -- (101,790) 119,008 Impairment of oil and gas properties ....... 826,000 -- -- -- 826,000 Impairment of other assets ................. 47,000 8,000 -- -- 55,000 Oil and gas depreciation, depletion and amortization.............................. 146,644 -- -- -- 146,644 Other depreciation and amortization ........ 5,204 126 2,746 -- 8,076 General and administrative ................. 18,081 1,766 71 -- 19,918 ------------- ------------- ------------- ------------- ------------- Total Operating Costs ...................... 1,102,426 230,690 2,817 (101,790) 1,234,143 ------------- ------------- ------------- ------------- ------------- INCOME (LOSS) FROM OPERATIONS .............. (847,885) (5,495) (2,817) -- (856,197) ------------- ------------- ------------- ------------- ------------- OTHER INCOME (EXPENSE): Interest and other income .................. 649 2,259 100,886 (99,868) 3,926 Interest expense ........................... (96,214) (382) (71,521) 99,868 (68,249) ------------- ------------- ------------- ------------- ------------- (95,565) 1,877 29,365 -- (64,323) ------------- ------------- ------------- ------------- ------------- INCOME (LOSS) BEFORE INCOME TAXES AND EXTRAORDINARY ITEM ....................... (943,450) (3,618) 26,548 -- (920,520) INCOME TAX EXPENSE (BENEFIT) ............... -- -- -- -- -- ------------- ------------- ------------- ------------- ------------- NET INCOME (LOSS) BEFORE EXTRAORDINARY ITEM ....................... (943,450) (3,618) 26,548 -- (920,520) EXTRAORDINARY ITEM: Loss on early extinguishment of debt, net of applicable income tax ........... (2,164) -- (11,170) -- (13,334) ------------- ------------- ------------- ------------- ------------- NET INCOME (LOSS) .......................... $ (945,614) $ (3,618) $ 15,378 $ -- $ (933,854) ============= ============= ============= ============= ============= FOR THE SIX MONTHS ENDED DECEMBER 31, 1997: REVENUES: Oil and gas sales .......................... $ 93,384 $ 1,199 $ -- $ 1,074 $ 95,657 Oil and gas marketing sales ................ -- 101,689 -- (43,448) 58,241 ------------- ------------- ------------- ------------- ------------- Total Revenues ............................. 93,384 102,888 -- (42,374) 153,898 ------------- ------------- ------------- ------------- ------------- OPERATING COSTS: Production expenses and taxes .............. 9,905 189 -- -- 10,094 Oil and gas marketing expenses ............. -- 100,601 -- (42,374) 58,227 Impairment of oil and gas properties ....... 96,000 14,000 -- -- 110,000 Oil and gas depreciation, depletion and amortization............................. 59,758 650 -- -- 60,408 Other depreciation and amortization ........ 1,383 40 991 -- 2,414 General and administrative ................. 4,598 1,132 117 -- 5,847 ------------- ------------- ------------- ------------- ------------- Total Operating Costs ...................... 171,644 116,612 1,108 (42,374) 246,990 ------------- ------------- ------------- ------------- ------------- INCOME (LOSS) FROM OPERATIONS .............. (78,260) (13,724) (1,108) -- (93,092) ------------- ------------- ------------- ------------- ------------- OTHER INCOME (EXPENSE): Interest and other income .................. 515 192 110,751 (32,492) 78,966 Interest expense ........................... (27,481) (39) (22,420) 32,492 (17,448) ------------- ------------- ------------- ------------- ------------- (26,966) 153 88,331 -- 61,518 ------------- ------------- ------------- ------------- ------------- INCOME (LOSS) BEFORE INCOME TAXES AND EXTRAORDINARY ITEM ....................... (105,226) (13,571) 87,223 -- (31,574) INCOME TAX EXPENSE (BENEFIT) ............... -- -- -- -- -- ------------- ------------- ------------- ------------- ------------- NET INCOME (LOSS) BEFORE EXTRAORDINARY ITEM ....................... (105,226) (13,571) 87,223 -- (31,574) EXTRAORDINARY ITEM ......................... -- -- -- -- -- ------------- ------------- ------------- ------------- ------------- NET INCOME (LOSS) .......................... $ (105,226) $ (13,571) $ 87,223 $ -- $ (31,574) ============= ============= ============= ============= ============= </TABLE> 53
54 CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS ($ IN THOUSANDS) <TABLE> <CAPTION> NON- GUARANTOR GUARANTOR SUBSIDIARIES SUBSIDIARIES COMPANY ELIMINATIONS CONSOLIDATED ------------- ------------- ------------- ------------- ------------- <S> <C> <C> <C> <C> <C> FOR THE YEAR ENDED JUNE 30, 1997: REVENUES: Oil and gas sales ............................. $ 191,303 $ -- $ -- $ 1,617 $ 192,920 Oil and gas marketing sales ................... -- 145,942 -- (69,770) 76,172 ------------- ------------- ------------- ------------- ------------- Total Revenues ................................ 191,303 145,942 -- (68,153) 269,092 ------------- ------------- ------------- ------------- ------------- OPERATING COSTS: Production expenses and taxes ................. 15,107 -- -- -- 15,107 Oil and gas marketing expenses ................ -- 143,293 -- (68,153) 75,140 Impairment of oil and gas properties .......... 236,000 -- -- -- 236,000 Oil and gas depreciation, depletion and amortization................................. 103,264 -- -- -- 103,264 Other depreciation and amortization ........... 2,152 80 1,550 -- 3,782 General and administrative .................... 6,313 921 1,568 -- 8,802 ------------- ------------- ------------- ------------- ------------- Total Operating Costs ......................... 362,836 144,294 3,118 (68,153) 442,095 ------------- ------------- ------------- ------------- ------------- INCOME (LOSS) FROM OPERATIONS ................. (171,533) 1,648 (3,118) -- (173,003) ------------- ------------- ------------- ------------- ------------- OTHER INCOME (EXPENSE): Interest and other income ..................... 778 749 49,224 (39,528) 11,223 Interest expense .............................. (37,644) (10) (20,424) 39,528 (18,550) ------------- ------------- ------------- ------------- ------------- (36,866) 739 28,800 -- (7,327) ------------- ------------- ------------- ------------- ------------- INCOME (LOSS) BEFORE INCOME TAXES AND EXTRAORDINARY ITEM .......................... (208,399) 2,387 25,682 -- (180,330) INCOME TAX EXPENSE (BENEFIT) .................. (4,129) 47 509 -- (3,573) ------------- ------------- ------------- ------------- ------------- NET INCOME (LOSS) BEFORE EXTRAORDINARY ITEM .......................... (204,270) 2,340 25,173 -- (176,757) EXTRAORDINARY ITEM: Loss on early extinguishment of debt, net of applicable income tax..................... (769) -- (5,851) -- (6,620) ------------- ------------- ------------- ------------- ------------- NET INCOME (LOSS) ............................. $ (205,039) $ 2,340 $ 19,322 $ -- $ (183,377) ============= ============= ============= ============= ============= FOR THE YEAR ENDED JUNE 30, 1996: REVENUES: Oil and gas sales ............................. $ 103,712 $ 6,884 $ -- $ 253 $ 110,849 Gas marketing sales ........................... -- 34,973 -- (6,545) 28,428 Oil and gas service operations ................ 6,314 -- -- -- 6,314 ------------- ------------- ------------- ------------- ------------- Total Revenues ................................ 110,026 41,857 -- (6,292) 145,591 ------------- ------------- ------------- ------------- ------------- OPERATING COSTS: Production expenses and taxes ................. 7,557 746 -- -- 8,303 Gas marketing expenses ........................ -- 33,744 -- (6,292) 27,452 Oil and gas service operations ................ 4,895 -- -- -- 4,895 Oil and gas depreciation, depletion and amortization ................................ 48,333 2,566 -- -- 50,899 Other depreciation and amortization ........... 1,924 73 1,160 -- 3,157 General and administrative .................... 3,683 496 649 -- 4,828 ------------- ------------- ------------- ------------- ------------- Total Operating Costs ......................... 66,392 37,625 1,809 (6,292) 99,534 ------------- ------------- ------------- ------------- ------------- INCOME (LOSS) FROM OPERATIONS ................. 43,634 4,232 (1,809) -- 46,057 ------------- ------------- ------------- ------------- ------------- OTHER INCOME (EXPENSE): Interest and other income ..................... 1,917 238 1,676 -- 3,831 Interest expense .............................. (508) (711) (12,460) -- (13,679) ------------- ------------- ------------- ------------- ------------- 1,409 (473) (10,784) -- (9,848) ------------- ------------- ------------- ------------- ------------- INCOME (LOSS) BEFORE INCOME TAXES AND EXTRAORDINARY ITEM ......................... 45,043 3,759 (12,593) -- 36,209 INCOME TAX EXPENSE (BENEFIT) .................. 15,990 1,335 (4,471) -- 12,854 ------------- ------------- ------------- ------------- ------------- NET INCOME (LOSS) BEFORE EXTRAORDINARY ITEM ........................ 29,053 2,424 (8,122) -- 23,355 EXTRAORDINARY ITEM ............................ -- -- -- -- -- ------------- ------------- ------------- ------------- ------------- NET INCOME (LOSS) ............................. $ 29,053 $ 2,424 $ (8,122) $ -- $ 23,355 ============= ============= ============= ============= ============= </TABLE> 54
55 CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS ($ IN THOUSANDS) <TABLE> <CAPTION> GUARANTOR NON-GUARANTOR SUBSIDIARIES SUBSIDIARIES COMPANY ELIMINATIONS CONSOLIDATED ------------ ------------ ------------ ------------ ------------ <S> <C> <C> <C> <C> <C> FOR THE YEAR ENDED DECEMBER 31, 1998: CASH FLOWS FROM OPERATING ACTIVITIES ............ $ 66,960 $ (13,137) $ 40,816 $ -- $ 94,639 ------------ ------------ ------------ ------------ ------------ CASH FLOWS FROM INVESTING ACTIVITIES: Oil and gas properties ........................ (539,930) -- -- -- (539,930) Proceeds from sale of assets .................. 16,008 -- 3,600 -- 19,608 Investment in preferred stock of Gothic Energy Corporation ................................ (39,500) -- -- -- (39,500) Repayment of long-term loan ................... 2,000 -- -- -- 2,000 Proceeds from sale of PanEast Petroleum Corporation ................................ -- -- 21,245 -- 21,245 Other additions ............................... (2,510) 8,408 (17,371) -- (11,473) ------------ ------------ ------------ ------------ ------------ (563,932) 8,408 7,474 -- (548,050) ------------ ------------ ------------ ------------ ------------ CASH FLOWS FROM FINANCING ACTIVITIES: Proceeds from long-term borrowings ............ -- -- 658,750 -- 658,750 Payments on long-term borrowings .............. -- -- (474,166) -- (474,166) Cash received from issuance of preferred stock -- -- 222,663 -- 222,663 Cash paid for purchase of treasury stock ...... -- -- (29,962) -- (29,962) Dividends paid on common stock and preferred stock ............................ -- -- (13,642) -- (13,642) Exercise of stock options ..................... -- -- 154 -- 154 Intercompany advances, net .................... 476,663 6,035 (482,698) -- -- Effect of exchange rate changes on cash ....... (4,726) -- -- -- (4,726) ------------ ------------ ------------ ------------ ------------ 471,937 6,035 (118,901) -- 359,071 ------------ ------------ ------------ ------------ ------------ Net increase (decrease) in cash and cash equivalents ................................... (25,035) 1,306 (70,611) -- (94,340) Cash, beginning of period ....................... (284) 13,694 110,450 -- 123,860 ------------ ------------ ------------ ------------ ------------ Cash, end of period ............................. $ (25,319) $ 15,000 $ 39,839 $ -- $ 29,520 ============ ============ ============ ============ ============ FOR THE SIX MONTHS ENDED DECEMBER 31, 1997: CASH FLOWS FROM OPERATING ACTIVITIES ...... $ 28,598 $ (10,842) $ 121,401 $ -- $ 139,157 ------------ ------------ ------------ ------------ ------------ CASH FLOWS FROM INVESTING ACTIVITIES: Oil and gas properties .................. (189,772) 17 -- -- (189,755) Proceeds from sale of assets ............ 2,520 -- -- -- 2,520 Investment in service operations ........ (200) -- -- -- (200) Other investments ....................... (26,472) -- 99,380 -- 72,908 Other additions ......................... (22,864) 1,340 (453) -- (21,977) ------------ ------------ ------------ ------------ ------------ (236,788) 1,357 98,927 -- (136,504) ------------ ------------ ------------ ------------ ------------ CASH FLOWS FROM FINANCING ACTIVITIES: Dividends paid on common stock .......... -- -- (2,810) -- (2,810) Exercise of stock options ............... -- -- 322 -- 322 Other financing ......................... -- (322) -- -- (322) Intercompany advances, net .............. 214,135 19,443 (233,578) -- -- ------------ ------------ ------------ ------------ ------------ 214,135 19,121 (236,066) -- (2,810) ------------ ------------ ------------ ------------ ------------ Net increase (decrease) in cash and cash equivalents ............................. 5,945 9,636 (15,738) -- (157) Cash, beginning of period ................. (6,534) 4,363 126,188 -- 124,017 ------------ ------------ ------------ ------------ ------------ Cash, end of period ....................... $ (589) $ 13,999 $ 110,450 $ -- $ 123,860 ============ ============ ============ ============ ============ </TABLE> 55
56 CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS ($ IN THOUSANDS) <TABLE> <CAPTION> GUARANTOR NON-GUARANTOR SUBSIDIARIES SUBSIDIARIES COMPANY ELIMINATIONS CONSOLIDATED ------------- ------------- ------------- ------------- ------------- <S> <C> <C> <C> <C> <C> FOR THE YEAR ENDED JUNE 30, 1997: CASH FLOWS FROM OPERATING ACTIVITIES ... $ 165,850 $ (11,008) $ (70,753) $ -- $ 84,089 ------------- ------------- ------------- ------------- ------------- CASH FLOWS FROM INVESTING ACTIVITIES: Oil and gas properties ............... (468,519) 57 -- -- (468,462) Proceeds from sale of assets ......... 9,523 -- -- -- 9,523 Investment in service operations ..... (3,048) -- -- -- (3,048) Long-term loans to third parties ..... (2,000) -- (18,000) -- (20,000) Other investments .................... -- -- (8,000) -- (8,000) Other additions ...................... (24,318) (1,999) (7,550) -- (33,867) ------------- ------------- ------------- ------------- ------------- (488,362) (1,942) (33,550) -- (523,854) ------------- ------------- ------------- ------------- ------------- CASH FLOWS FROM FINANCING ACTIVITIES: Proceeds from borrowings ............. 50,000 -- 292,626 -- 342,626 Payments on borrowings ............... (118,901) -- (680) -- (119,581) Exercise of stock options ............ -- -- 1,387 -- 1,387 Issuance of common stock ............. -- -- 288,091 -- 288,091 Other financing ...................... -- -- (379) -- (379) Intercompany advances, net ........... 380,735 14,645 (395,380) -- -- ------------- ------------- ------------- ------------- ------------- 311,834 14,645 185,665 -- 512,144 ------------- ------------- ------------- ------------- ------------- Net increase (decrease) in cash and cash equivalents .......................... (10,678) 1,695 81,362 -- 72,379 Cash, beginning of period .............. 4,144 2,668 44,826 -- 51,638 ------------- ------------- ------------- ------------- ------------- Cash, end of period .................... $ (6,534) $ 4,363 $ 126,188 $ -- $ 124,017 ============= ============= ============= ============= ============= FOR THE YEAR ENDED JUNE 30, 1996: CASH FLOWS FROM OPERATING ACTIVITIES ... $ 126,868 $ 4,204 $ (10,100) $ -- $ 120,972 ------------- ------------- ------------- ------------- ------------- CASH FLOWS FROM INVESTING ACTIVITIES: Oil and gas properties ............... (341,246) (6,099) -- 5,300 (342,045) Proceeds from sales .................. 12,165 -- -- (5,300) 6,865 Investment in gas marketing company .. -- 266 (629) -- (363) Other additions ...................... (4,683) (109) (4,054) -- (8,846) ------------- ------------- ------------- ------------- ------------- (333,764) (5,942) (4,683) -- (344,389) ------------- ------------- ------------- ------------- ------------- CASH FLOWS FROM FINANCING ACTIVITIES: Proceeds from borrowings ............. 40,350 10,300 116,017 -- 166,667 Payments on borrowings ............... (45,397) (3,200) (37) -- (48,634) Exercise of stock options ............ -- -- 1,989 -- 1,989 Issuance of common stock ............. -- -- 99,498 -- 99,498 Intercompany advances, net ........... 162,777 (2,616) (160,161) -- -- ------------- ------------- ------------- ------------- ------------- 157,730 4,484 57,306 -- 219,520 ------------- ------------- ------------- ------------- ------------- Net increase (decrease) in cash and cash equivalents .......................... (49,166) 2,746 42,523 -- (3,897) Cash, beginning of period .............. 53,227 5 2,303 -- 55,535 ------------- ------------- ------------- ------------- ------------- Cash, end of period .................... $ 4,061 $ 2,751 $ 44,826 $ -- $ 51,638 ============= ============= ============= ============= ============= </TABLE> 56
57 3. NOTES PAYABLE AND LONG-TERM DEBT Notes payable and long-term debt consist of the following: <TABLE> <CAPTION> DECEMBER 31, JUNE 30, ------------------------------ ------------- 1998 1997 1997 ------------- ------------- ------------- ($ IN THOUSANDS) <S> <C> <C> <C> 7.875% Senior Notes (see Note 2) ................................ $ 150,000 $ 150,000 $ 150,000 Discount on 7.875% Senior Notes ................................. (90) (106) (115) 8.5% Senior Notes (see Note 2) .................................. 150,000 150,000 150,000 Discount on 8.5% Senior Notes ................................... (774) (833) (862) 9.125% Senior Notes (see Note 2) ................................ 120,000 120,000 120,000 Discount on 9.125% Senior Notes ................................. (60) (69) (73) 9.625% Senior Notes (see Note 2) ................................ 500,000 -- -- 10.5% Senior Notes (see Note 2) ................................. -- 90,000 90,000 Note payable to a vendor, collateralized by oil and gas tubulars, payments due 60 days from shipment of the tubulars ........... -- -- 1,380 Other collateralized ............................................ 25,000 -- -- ------------- ------------- ------------- Total notes payable and long-term debt .......................... 944,076 508,992 510,330 Less-- current maturities ....................................... (25,000) -- (1,380) ------------- ------------- ------------- Notes payable and long-term debt, net of current maturities ................................................... $ 919,076 $ 508,992 $ 508,950 ============= ============= ============= </TABLE> The aggregate scheduled maturities of notes payable and long-term debt for the next five fiscal years ending December 31, 2003 and thereafter were as follows as of December 31, 1998 (in thousands of dollars): <TABLE> <S> <C> 1999........................................................................................... $ 25,000 2000........................................................................................... -- 2001........................................................................................... -- 2002........................................................................................... -- 2003........................................................................................... -- After 2003..................................................................................... 919,076 --------- $ 944,076 ========= </TABLE> 4. CONTINGENCIES AND COMMITMENTS The Company and certain of its officers and directors are defendants in a consolidated class action suit alleging violations of the Securities Exchange Act of 1934. The plaintiffs assert that the defendants made material misrepresentations and failed to disclose material facts about the success of the Company's exploration efforts in the Louisiana Trend. As a result, the complaint alleges, the price of the Company's common stock was artificially inflated from January 25, 1996 until June 27, 1997, when the Company issued a press release announcing disappointing drilling results in the Louisiana Trend and a full-cost ceiling writedown to be reflected in its June 30, 1997 financial statements. The plaintiffs further allege that certain of the named individual defendants sold common stock during the class period when they knew or should have known adverse nonpublic information. The plaintiffs seek a determination that the suit is a proper class action and damages in an unspecified amount, together with interest and costs of litigation, including attorneys' fees. The Company and the individual defendants believe that these claims are without merit and have filed a motion to dismiss. No estimate of loss or range of estimate of loss, if any, can be made at this time. Another purported class action alleging violations of the Securities Act of 1933 and the Oklahoma Securities Act is pending against the Company and others on behalf of investors who purchased common stock of Bayard Drilling Technologies, Inc. ("Bayard") in its initial public offering in November 1997. Total proceeds of the offering were $254 million, of which the Company received net proceeds of $90.2 million as a selling shareholder. Plaintiffs allege that the Company, which owned 30.1% of Bayard's common stock outstanding prior to the offering, was a controlling person of Bayard. Plaintiffs also allege that the Company had established an interlocking financial relationship with Bayard and was a customer of Bayard's drilling services under allegedly below-market terms. Plaintiffs also note the fact that three executive officers and directors of the Company were formerly directors of Bayard. Plaintiffs assert that the Bayard prospectus contained material omissions and misstatements relating to (i) the Company's financial "problems" and their impact on Bayard's operating results, (ii) increased costs associated with Bayard's growth strategy, (iii) undisclosed pending related-party transactions between Bayard and third parties 57
58 other than the Company, (iv) Bayard's planned use of offering proceeds and (v) Bayard's capital expenditures and liquidity. The alleged defective disclosures are claimed to have resulted in a decline in Bayard's share price following the public offering. The plaintiffs seek a determination that the suit is a proper class action and damages in an unspecified amount or rescission, together with interest and costs of litigation, including attorneys' fees. The Company believes that these actions are without merit and has filed a motion to dismiss. No estimate of loss or range of estimate of loss, if any, can be made at this time. In October 1996, Union Pacific Resources Company ("UPRC") sued the Company alleging infringement of a patent for a drilling method, tortious interference with confidentiality contracts between UPRC and certain of its former employees and misappropriation of proprietary information of UPRC. UPRC's claims against the Company are based on services provided to the Company by a third party vendor controlled by former UPRC employees. UPRC is seeking injunctive relief, damages of an unspecified amount, including actual, enhanced, consequential and punitive damages, interest, costs and attorneys' fees. In May 1998, the court ruled as a matter of law that UPRC's tort claims for misappropriation of trade secrets and tortious interference with business relations are barred by the statute of limitations. Further, the court found that UPRC's claim for inducement to infringe its patent for a drillbit steering method is barred as to any wells drilled by the Company prior to August 14, 1995. The only issues remaining in the case involve the validity, potential infringement and value, if any, of UPRC's patent. The Company believes that it has meritorious defenses to UPRC's allegations and has petitioned the court to declare the UPRC patent invalid. Various motions for summary judgment are pending. No estimate of a probable loss or range of estimate of a probable loss, if any, can be made at this time; however, in reports filed in the proceeding, experts for UPRC claim that damages could be as much as $18 million while Company experts state that the amount should not exceed $25,000, in each case based on a reasonable royalty. This case has been set for trial in June 1999 on the issue of liability. The Company is currently involved in various other routine disputes incidental to its business operations. While it is not possible to determine the ultimate disposition of these matters, management, after consultation with legal counsel, is of the opinion that the final resolution of all such currently pending or threatened litigation is not likely to have a material adverse effect on the consolidated financial position or results of operations of the Company. The Company has employment contracts with its two principal shareholders and its chief financial officer and various other senior management personnel which provide for annual base salaries, bonus compensation and various benefits. The contracts provide for the continuation of salary and benefits for the respective terms of the agreements in the event of termination of employment without cause. These agreements expire at various times from June 30, 2000 through June 30, 2003. Due to the nature of the oil and gas business, the Company and its subsidiaries are exposed to possible environmental risks. The Company has implemented various policies and procedures to avoid environmental contamination and risks from environmental contamination. The Company is not aware of any potential material environmental issues or claims. 5. INCOME TAXES The components of the income tax provision (benefit) for each of the periods are as follows: <TABLE> <CAPTION> YEAR ENDED SIX MONTHS ENDED YEAR ENDED JUNE 30, DECEMBER 31, DECEMBER 31, ------------------------------ 1998 1997 1997 1996 ------------- ------------- ------------- ------------- ($ IN THOUSANDS) <S> <C> <C> <C> <C> Current ...................... $ -- $ -- $ -- $ -- Deferred ..................... -- -- (3,573) 12,854 ------------- ------------- ------------- ------------- Total .............. $ -- $ -- $ (3,573) $ 12,854 ============= ============= ============= ============= </TABLE> The effective income tax expense (benefit) differed from the computed "expected" federal income tax expense (benefit) on earnings before income taxes for the following reasons: 58
59 <TABLE> <CAPTION> YEAR ENDED SIX MONTHS ENDED YEAR ENDED JUNE 30, DECEMBER 31, DECEMBER 31, ------------------------------ 1998 1997 1997 1996 ------------- ------------- ------------- ------------- ($ IN THOUSANDS) <S> <C> <C> <C> <C> Computed "expected" income tax provision (benefit) $ (322,182) $ (11,051) $ (63,116) $ 12,673 Tax percentage depletion ......................... (430) (48) (294) (238) Valuation allowance .............................. 380,969 13,818 64,116 -- State income taxes and other ..................... (58,357) (2,719) (4,279) 419 ------------- ------------- ------------- ------------- $ -- $ -- $ (3,573) $ 12,854 ============= ============= ============= ============= </TABLE> Deferred income taxes are provided to reflect temporary differences in the basis of net assets for income tax and financial reporting purposes. The tax effected temporary differences and tax loss carryforwards which comprise deferred taxes are as follows: <TABLE> <CAPTION> YEAR ENDED SIX MONTHS ENDED YEAR ENDED JUNE 30, DECEMBER 31, DECEMBER 31, ------------------------------ 1998 1997 1997 1996 ------------- ------------- ------------- ------------- ($ IN THOUSANDS) <S> <C> <C> <C> <C> Deferred tax liabilities: Acquisition, exploration and development costs and related depreciation, depletion and amortization ................................... $ -- $ (49,657) $ (49,831) $ (63,725) Deferred tax assets: Acquisition, exploration and development costs and related depreciation, depletion and amortization ................................... 242,765 -- -- -- Net operating loss carryforwards ................. 214,602 126,485 112,889 50,776 Percentage depletion carryforward ................ 1,536 1,106 1,058 764 ------------- ------------- ------------- ------------- 458,903 127,591 113,947 51,540 ------------- ------------- ------------- ------------- Net deferred tax asset (liability) ............... 458,903 77,934 64,116 (12,185) Less: Valuation allowance ........................ (458,903) (77,934) (64,116) -- ------------- ------------- ------------- ------------- Total deferred tax asset (liability) ............. $ -- $ -- $ -- $ (12,185) ============= ============= ============= ============= </TABLE> SFAS 109 requires that the Company record a valuation allowance when it is more likely than not that some portion or all of the deferred tax assets will not be realized. In 1998, the Transition Period and fiscal 1997, the Company recorded an $826 million writedown, a $110 million writedown and a $236 million writedown, respectively, related to the impairment of oil and gas properties. The writedowns and significant tax net operating loss carryforwards (caused primarily by expensing intangible drilling costs for tax purposes) resulted in a net deferred tax asset at December 31, 1998 and 1997 and June 30, 1997. Management believes it is more likely than not that the Company will generate future tax net operating losses for at least the next five years.. Therefore, the Company has recorded a valuation allowance equal to the net deferred tax asset. At December 31, 1998, the Company had U.S. and Canadian regular tax net operating loss carryforwards of approximately $571 million and $1 million, respectively, and U.S. alternative minimum tax net operating loss carryforwards of approximately $196 million. The U.S. loss carryforward amounts will expire during the years 2007 through 2018. The Company also had a percentage depletion carryforward of approximately $4 million at December 31, 1998, which is available to offset future federal income taxes payable and has no expiration date. In accordance with certain provisions of the Tax Reform Act of 1986, a change of greater than 50% of the beneficial ownership of the Company within a three-year period (an "Ownership Change") would place an annual limitation on the Company's ability to utilize its existing tax carryforwards. Under regulations issued by the Internal Revenue Service, the Company has had two Ownership Changes. However, management believes this will not result in a significant limitation of the tax carryforwards. Acquired tax carryforwards are subject to separate limitations; however, management believes these will not result in a significant limitation of the acquired tax carryforwards. 6. RELATED PARTY TRANSACTIONS Certain directors, shareholders and employees of the Company have acquired working interests in certain of the Company's oil and gas properties. The owners of such working interests are required to pay their proportionate share of all costs. As of December 31, 1998 and 1997 and June 30, 1997, the Company had accounts receivable 59
60 from related parties, primarily related to such participation, of $5.6 million, $4.2 million and $7.4 million, respectively. Certain officers of the Company have loans due on December 31, 1999 to CEMI in the principal amount of $9.9 million. Such loans, which were first made in July 1998, are collateralized and carry an annual interest rate of 9.125%. During 1998, the six months ended December 31, 1997 and fiscal 1997 and 1996, the Company incurred legal expenses of $493,000, $388,000, $207,000 and $347,000, respectively, for legal services provided by a law firm of which a director is a member. 7. EMPLOYEE BENEFIT PLANS The Company maintains the Chesapeake Energy Corporation Savings and Incentive Stock Bonus Plan, a 401(k) profit sharing plan. Eligible employees may make voluntary contributions to the plan which are matched by the Company for up to 10% of the employee's annual salary with the Company's common stock. The amount of employee contribution is limited as specified in the plan. The Company may, at its discretion, make additional contributions to the plan. The Company contributed $1,359,000, $418,000, $603,000 and $187,000 to the plan during 1998, the six months ended December 31, 1997 and the fiscal years ended June 30, 1997 and 1996, respectively. 8. MAJOR CUSTOMERS AND SEGMENT INFORMATION Sales to individual customers constituting 10% or more of total oil and gas sales were as follows: <TABLE> <CAPTION> PERCENT OF YEAR ENDED DECEMBER 31, AMOUNT OIL AND GAS SALES ----------------------------------------------------- ---------------- ----------------- ($ IN THOUSANDS) <S> <C> <C> 1998 Koch Oil Company $ 30,564 12% Aquila Southwest Pipeline Corporation $ 28,946 11% SIX MONTHS ENDED DECEMBER 31, ----------------------------------------------------- 1997 Aquila Southwest Pipeline Corporation $ 20,138 21% Koch Oil Company $ 18,594 19% GPM Gas Corporation $ 12,610 13% FISCAL YEAR ENDED JUNE 30, ----------------------------------------------------- 1997 Aquila Southwest Pipeline Corporation $ 53,885 28% Koch Oil Company $ 29,580 15% GPM Gas Corporation $ 27,682 14% 1996 Aquila Southwest Pipeline Corporation $ 41,900 38% GPM Gas Corporation $ 28,700 26% Wickford Energy Marketing, L.C. $ 18,500 17% </TABLE> Management believes that the loss of any of the above customers would not have a material impact on the Company's results of operations or its financial position. The Company believes all of its material operations are part of the oil and gas industry, and therefore reports as a single industry setment. Beginning in 1998, the Company conducted foreign operations in Canada. The geographic distribution of the Company's revenue, operating income and identifiable assets are summarized below ($ in thousands): <TABLE> <CAPTION> UNITED STATES CANADA CONSOLIDATED ------------- ------------- -------------- <S> <C> <C> <C> 1998: Revenue ........................... $ 369,968 $ 7,978 $ 377,946 Operating income (loss) ........... (842,798) (13,399) (856,197) Identifiable assets ............... 724,713 87,902 812,615 </TABLE> 60
61 9. STOCKHOLDERS' EQUITY AND STOCK BASED COMPENSATION During 1998, the Company's Board of Directors approved the expenditure of up to $30 million to purchase outstanding Company common stock. As of August 25, 1998, the Company had purchased approximately 8.5 million shares of common stock for an aggregate amount of $30 million pursuant to such authorization. On April 28, 1998, the Company acquired by merger the Mid-Continent operations of DLB Oil & Gas, Inc. ("DLB") for $17.5 million in cash, 5 million shares of the Company's common stock, and the assumption of $90 million in outstanding debt and working capital obligations. On April 22, 1998, the Company issued $230 million (4.6 million shares) of its 7% Cumulative Convertible Preferred Stock, $50 per share liquidation preference, resulting in net proceeds to the Company of $223 million. On March 10, 1998, the Company acquired Hugoton Energy Corporation ("Hugoton") pursuant to a merger by issuing approximately 25.8 million shares of the Company's common stock in exchange for 100% of Hugoton's common stock. On December 16, 1997, the Company acquired AnSon Production Corporation. Consideration for this merger was approximately $43 million consisting of the issuance of approximately 3.8 million shares of Company common stock and cash consideration in accordance with the terms of the merger agreement. On December 2, 1996, the Company completed a public offering of approximately 9.0 million shares of common stock at a price of $33.63 per share, resulting in net proceeds to the Company of approximately $288.1 million. On April 12, 1996, the Company completed a public offering of approximately 6.0 million shares of common stock at a price of $17.67 per share, resulting in net proceeds to the Company of approximately $99.4 million. A 2-for-1 stock split of the common stock in December 1996, and a 3-for-2 stock split of the common stock in December 1995 and in June 1996 have been given retroactive effect in these financial statements. Stock Option Plans Under the Company's 1992 Incentive Stock Option Plan (the "ISO Plan"), options to purchase common stock may be granted only to employees of the Company and its subsidiaries. Subject to any adjustment as provided by the ISO Plan, the aggregate number of shares which may be issued and sold may not exceed 3,762,000 shares. The maximum period for exercise of an option may not be more than 10 years (or five years for an optionee who owns more than 10% of the common stock) from the date of grant, and the exercise price may not be less than the fair market value of the shares underlying the options on the date of grant (or 110% of such value for an optionee who owns more than 10% of the common stock). Options granted become exercisable at dates determined by the Stock Option Committee of the Board of Directors. No options could be granted under the ISO Plan after December 16, 1994. Under the Company's 1992 Nonstatutory Stock Option Plan (the "NSO Plan"), non-qualified options to purchase common stock may be granted only to directors and consultants of the Company. Subject to any adjustment as provided by the NSO Plan, the aggregate number of shares which may be issued and sold may not exceed 3,132,000 shares. The maximum period for exercise of an option may not be more than 10 years from the date of grant, and the exercise price may not be less than the fair market value of the shares underlying the options on the date of grant. Options granted become exercisable at dates determined by the Stock Option Committee of the Board of Directors. No options can be granted under the NSO Plan after December 10, 2002. 61
62 Under the Company's 1994 Stock Option Plan (the "1994 Plan"), and its 1996 Stock Option Plan (the "1996 Plan"), incentive and nonqualified stock options to purchase Common Stock may be granted to employees and consultants of the Company and its subsidiaries. Subject to any adjustment as provided by the respective plans, the aggregate number of shares which may be issued and sold may not exceed 4,886,910 shares under the 1994 Plan and 6,000,000 shares under the 1996 Plan. The maximum period for exercise of an option may not be more than 10 years from the date of grant and the exercise price may not be less than 75% of the fair market value of the shares underlying the options on the date of grant. Options granted become exercisable at dates determined by the Stock Option Committee of the Board of Directors. No options can be granted under the 1994 Plan after December 16, 2004 or under the 1996 Plan after October 14, 2006. The Company 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. No compensation expense has been recognized because the exercise price of the stock options equaled the market price of the underlying stock on the date of grant. Pro forma information regarding net income and earnings per share is required by SFAS No. 123 and has been determined as if the Company had accounted for its employee stock options under the fair value method of the statement. The fair value for these options was estimated at the date of grant using a Black-Scholes option pricing model with the following weighted-average assumptions for 1998, the six months ended December 31, 1997 and fiscal 1997 and 1996, respectively: interest rates (zero-coupon U.S. government issues with a remaining life equal to the expected term of the options) of 5.20%, 6.45%, 6.74% and 6.21%; dividend yields of 0.0%, 0.9%, 0.9% and 0.9%; volatility factors of the expected market price of the Company's common stock of .96, .67, .60 and .60; and weighted-average expected life of the options of four years. The Black-Scholes option valuation model was developed for use in estimating the fair value of traded options which have no vesting restrictions and are fully transferable. In addition, option valuation models require the input of highly subjective assumptions including the expected stock price volatility. Because the Company's employee stock options have characteristics significantly different from those of traded options, and because changes in the subjective input assumptions can materially affect the fair value estimate, in management's opinion the existing models do not necessarily provide a reliable single measure of the fair value of its employee stock options. The Company's pro forma information follows: <TABLE> <CAPTION> YEAR ENDED SIX MONTHS ENDED YEAR ENDED JUNE 30, DECEMBER 31, DECEMBER 31, ------------------------------ 1998 1997 1997 1996 ------------- ------------- ------------- ------------- (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) <S> <C> <C> <C> <C> Net Income (Loss) As reported ................ $ (933,854) $ (31,574) $ (183,377) $ 23,355 Pro forma .................. (948,014) (35,084) (190,160) 22,081 Earnings (Loss) per Share As reported ................ $ (9.97) $ (0.45) $ (2.79) $ 0.40 Pro forma .................. (10.12) (0.50) (2.89) 0.38 </TABLE> 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 the Company's 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 years. A summary of the Company's stock option activity and related information follows: <TABLE> <CAPTION> YEAR ENDED DECEMBER 31, SIX MONTHS ENDED DECEMBER 31, 1998 1997 ------------------------------- ------------------------------ WEIGHTED-AVG WEIGHTED-AVG OPTIONS EXERCISE PRICE OPTIONS EXERCISE PRICE ------------- -------------- ------------- -------------- <S> <C> <C> <C> <C> Outstanding Beginning of Period .................. 8,330,381 $ 5.49 7,903,659 $ 7.09 Granted .......................................... 14,580,063 $ 2.78 3,362,207 8.29 Exercised ........................................ (108,761) $ 1.35 (219,349) 3.13 Cancelled/Forfeited .............................. (11,541,308) $ 5.64 (2,716,136) 13.87 ------------- ------------- ------------- ------------- Outstanding End of Period ........................ 11,260,375 $ 1.86 8,330,381 5.49 ------------- ------------- ------------- ------------- Exercisable End of Period ........................ 3,535,126 3,838,869 ------------- ------------- Shares Authorized for Future Grants........ 1,761,359 4,585,973 ------------- ------------- Fair Value of Options Granted During the Period................................ $ 2.34 $ 4.98 ------------- ------------- </TABLE> 62
63 <TABLE> <CAPTION> YEAR ENDED JUNE 30, ---------------------------------------------------------------------- 1997 1996 --------------------------------- -------------------------------- WEIGHTED-AVG WEIGHTED-AVG OPTIONS EXERCISE PRICE OPTIONS EXERCISE PRICE ------------- --------------- ------------- --------------- <S> <C> <C> <C> <C> Outstanding Beginning of Year ...................... 7,602,884 $ 4.66 6,828,592 $ 1.97 Granted ............................................ 3,564,884 19.35 2,426,850 9.98 Exercised .......................................... (1,197,998) 1.95 (1,574,046) 1.31 Cancelled/Forfeited ................................ (2,066,111) 22.26 (78,512) 2.61 ------------- ------------- ------------- ------------- Outstanding End of Year ............................ 7,903,659 7.09 7,602,884 4.66 ------------- ------------- ------------- ------------- Exercisable End of Year ............................ 3,323,824 2,974,386 ------------- ------------- Shares Authorized for Future Grants ................ 5,212,056 713,826 ------------- ------------- Fair Value of Options Granted During the Year ...... $ 7.51 $ 4.84 ------------- ------------- </TABLE> The following table summarizes information about stock options outstanding at December 31, 1998: <TABLE> <CAPTION> OPTIONS OUTSTANDING OPTIONS EXERCISABLE ----------------------------------------------------- -------------------------------- NUMBER WEIGHTED-AVG. NUMBER RANGE OF OUTSTANDING REMAINING WEIGHTED-AVG. EXERCISABLE WEIGHTED-AVG. EXERCISE PRICES @ 12/31/98 CONTRACTUAL LIFE EXERCISE PRICE @ 12/31/98 EXERCISE PRICE ------------------ -------------- ------------------ --------------- --------------- -------------- <S> <C> <C> <C> <C> <C> $0.0800 - $ 0.8556 1,243,185 3.85 $0.6434 1,243,185 $ 0.6434 $1.1300 - $ 1.1300 6,708,697 9.79 $1.1300 36,563 $ 1.1300 $1.2400 - $ 2.2511 2,047,254 5.45 $1.7603 1,349,704 $ 2.0293 $2.4311 - $ 7.3100 1,062,864 7.50 $4.5489 752,239 $ 4.4790 $8.7500 - $ 8.7500 48,625 8.50 $8.7500 26,310 $ 8.7500 $10.6900 - $10.6900 18,750 8.75 $10.6900 18,750 $10.6900 $14.2500 - $14.2500 28,500 8.32 $14.2500 7,125 $14.2500 $17.6667 - $17.6667 1,500 7.26 $17.6667 750 $17.6667 $25.8750 - $25.8750 1,000 7.95 $25.8750 500 $25.8750 $30.6250 - $30.6250 100,000 7.77 $30.6250 100,000 $30.6250 ------------ ---- -------- --------- -------- $0.0800 - $30.6250 11,260,375 8.10 $1.8620 3,535,126 $2.9900 </TABLE> The exercise of certain stock options results in state and federal income tax benefits to the Company related to the difference between the market price of the common stock at the date of disposition (or sale) and the option price. During 1998, the six months ended December 31, 1997 and fiscal 1997 and 1996, $0, $0, $4,808,000 and $7,950,000, respectively, were recorded as adjustments to additional paid-in capital and deferred income taxes with respect to such tax benefits. 10. FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES The Company has only limited involvement with derivative financial instruments, as defined in Statement of Financial Accounting Standards No. 119 "Disclosure About Derivative Financial Instruments and Fair Value of Financial Instruments", and does not use them for trading purposes. The Company's primary objective is to hedge a portion of its exposure to price volatility from producing crude oil and natural gas. These arrangements may expose the Company to credit risk from its counterparties and to basis risk. The Company does not expect that the counterparties will fail to meet their obligations given their high credit ratings. Hedging Activities Periodically the Company utilizes hedging strategies to hedge the price of a portion of its future oil and gas production. These strategies include (i) swap arrangements that establish an index-related price above which the Company pays the counterparty and below which the Company is paid by the counterparty, (ii) the purchase of index-related puts that provide for a "floor" price below which the counterparty pays the Company the amount by which the price of the commodity is below the contracted floor, (iii) the sale of index-related calls that provide for a "ceiling" price above which the Company pays the counterparty the amount by which the price of the commodity is above the contracted ceiling, and (iv) basis protection swaps, which are arrangements that guarantee the price differential of oil or gas from a specified delivery point or points. Results from commodity hedging transactions are 63
64 reflected in oil and gas sales to the extent related to the Company's oil and gas production. The Company only enters into commodity hedging transactions related to the Company's oil and gas production volumes or CEMI's physical purchase or sale commitments. Gains or losses on crude oil and natural gas hedging transactions are recognized as price adjustments in the months of related production. As of December 31, 1998, the Company had the following natural gas swap arrangements designed to hedge a portion of the Company's domestic gas production for periods after December 1998: <TABLE> <CAPTION> NYMEX-INDEX VOLUME STRIKE PRICE MONTHS (MMBTU) (PER MMBTU) - ------ ------------- ------------- <S> <C> <C> February 1999.................................................................... 4,300,000 $ 1.968 March 1999....................................................................... 4,600,000 1.968 April 1999....................................................................... 4,500,000 1.968 May 1999......................................................................... 4,600,000 1.968 June 1999........................................................................ 1,200,000 1.950 July 1999........................................................................ 1,240,000 1.950 August 1999...................................................................... 1,240,000 1.950 September 1999................................................................... 1,200,000 1.950 </TABLE> During 1998, the Company has closed transactions for natural gas previously hedged for the period April 1999 through November 1999 for net proceeds of $0.5 million. Subsequent to December 31, 1998, the Company entered into additional natural gas swap arrangements for 6,100,000 MMBtu at a strike price of $1.875 for the period from June 1999 through September 1999. Such swap arrangements, along with those listed above and other miscellaneous transactions, were closed as of March 15, 1999, resulting in net proceeds of $4.7 million (unrealized gain of $0.8 million at December 31, 1998). As of December 31, 1998, the Company had the following natural gas swap arrangements designed to hedge a portion of the Company's Canadian gas production for periods after December 1998: <TABLE> <CAPTION> VOLUME INDEX STRIKE PRICE MONTHS (MMBTU) (PER MMBTU) - ------ --------------- ----------------- <S> <C> <C> January 1999........................................................... 589,000 $ 1.60 February 1999.......................................................... 532,000 1.60 March 1999............................................................. 589,000 1.60 April 1999............................................................. 570,000 1.60 May 1999............................................................... 589,000 1.60 June 1999.............................................................. 570,000 1.60 July 1999.............................................................. 589,000 1.60 August 1999............................................................ 589,000 1.60 September 1999......................................................... 570,000 1.60 </TABLE> If the swap arrangements listed above had been settled on December 31, 1998, the Company would have incurred a loss of $0.8 million. As of December 31, 1998, the Company had the following oil swap arrangements for periods after December 1998: <TABLE> <CAPTION> NYMEX HEATING OIL MINUS MONTHLY NYMEX CRUDE OIL VOLUME INDEX STRIKE PRICE MONTHS (BBLS) (PER BBL) - ------ --------------- ---------------- <S> <C> <C> January 1999........................................................... 217,000 $ 2.957 February 1999.......................................................... 196,000 2.957 March 1999............................................................. 155,000 2.900 </TABLE> If the swap arrangements listed above had been settled on December 31, 1998, the Company would have incurred a loss of $0.2 million. Subsequent to December 31, 1998, the Company settled the swap arrangements listed above for the period of January 1999 and February 1999 resulting in a $0.4 million loss. 64
65 In addition to commodity hedging transactions related to the Company's oil and gas production, CEMI periodically enters into various hedging transactions designed to hedge against physical purchase or sale commitments made by CEMI. Gains or losses on these transactions are recorded as adjustments to oil and gas marketing sales in the consolidated statements of operations and are not considered by management to be material. The Company also utilizes hedging strategies to manage fixed-interest rate exposure. Through the use of a swap arrangement, the Company believes it can benefit from stable or falling interest rates and reduce its current interest expense. For the year ended December 31, 1998, the Company's interest rate swap resulted in a $0.7 million reduction of interest expense during 1998. Concentration of Credit Risk Other financial instruments which potentially subject the Company to concentrations of credit risk consist principally of cash, short-term investments in debt instruments and trade receivables. The Company's accounts receivable are primarily from purchasers of oil and natural gas products and exploration and production companies which own interests in properties operated by the Company. The industry concentration has the potential to impact the Company's overall exposure to credit risk, either positively or negatively, in that the customers may be similarly affected by changes in economic, industry or other conditions. The Company generally requires letters of credit for receivables from customers which are judged to have sub-standard credit, unless the credit risk can otherwise be mitigated. The cash and investments in debt securities are with major banks or institutions with high credit ratings. 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". The estimated fair value amounts have been determined by the Company 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. The Company estimates the fair value of its long-term, fixed-rate debt using quoted market prices. The Company's carrying amount for such debt at December 31, 1998 and 1997 and June 30, 1997 was $919.1 million, $509.0 million and $508.9 million, respectively, compared to approximate fair values of $654.7 million, $517.0 million and $514.1 million, respectively. The carrying value of other long-term debt approximates its fair value as interest rates are primarily variable, based on prevailing market rates. The Company estimates the fair value of its convertible preferred stock, which was issued in April 1998, using quoted market prices. The Company's carrying amount for such preferred stock at December 31, 1998 was $230 million, compared to an approximate fair value of $48.9 million. 11. DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES Net Capitalized Costs Evaluated and unevaluated capitalized costs related to the Company's oil and gas producing activities are summarized as follows: 65
66 <TABLE> <CAPTION> DECEMBER 31, 1998 - ----------------- U.S. CANADA COMBINED ------------- ------------- ------------- ($ IN THOUSANDS) <S> <C> <C> <C> Oil and gas properties: Proved ................................................ $ 2,060,076 $ 82,867 $ 2,142,943 Unproved .............................................. 44,780 7,907 52,687 ------------- ------------- ------------- Total ......................................... 2,104,856 90,774 2,195,630 Less accumulated depreciation, depletion and amortization (1,556,284) (17,998) (1,574,282) ------------- ------------- ------------- Net capitalized costs ................................... $ 548,572 $ 72,776 $ 621,348 ============= ============= ============= </TABLE> <TABLE> <CAPTION> DECEMBER 31, 1997 - ----------------- U.S. CANADA COMBINED ------------- ------------- ------------- ($ IN THOUSANDS) <S> <C> <C> <C> Oil and gas properties: Proved ................................................ $ 1,095,363 $ -- $ 1,095,363 Unproved .............................................. 125,155 -- 125,155 ------------- ------------- ------------- Total ......................................... 1,220,518 -- 1,220,518 Less accumulated depreciation, depletion and amortization (602,391) -- (602,391) ------------- ------------- ------------- Net capitalized costs ................................... $ 618,127 $ -- $ 618,127 ============= ============= ============= </TABLE> <TABLE> <CAPTION> JUNE 30, 1997 - ------------- U.S. CANADA COMBINED ------------- ------------- ------------- ($ IN THOUSANDS) <S> <C> <C> <C> Oil and gas properties: Proved ................................................ $ 865,516 $ -- $ 865,516 Unproved .............................................. 128,505 -- 128,505 ------------- ------------- ------------- Total ......................................... 994,021 -- 994,021 Less accumulated depreciation, depletion and amortization (431,983) -- (431,983) ------------- ------------- ------------- Net capitalized costs ................................... $ 562,038 $ -- $ 562,038 ============= ============= ============= </TABLE> Unproved properties not subject to amortization at December 31, 1998 and 1997, and June 30, 1997 consisted mainly of lease acquisition costs. The Company capitalized approximately $6.5 million, $5.1 million and $12.9 million of interest during 1998, the six months ended December 31, 1997 and the year ended June 30, 1997 on significant investments in unproved properties that were not yet included in the amortization base of the full-cost pool. The Company will continue to evaluate its unevaluated properties; however, the timing of the ultimate evaluation and disposition of the properties has not been determined. Costs Incurred in Oil and Gas Acquisition, Exploration and Development Costs incurred in oil and gas property acquisition, exploration and development activities which have been capitalized are summarized as follows: <TABLE> <CAPTION> YEAR ENDED DECEMBER 31, 1998 - ---------------------------- U.S. CANADA COMBINED ---------- ---------- --------- ($ IN THOUSANDS) <S> <C> <C> <C> Development costs........................................ $ 145,953 $ 4,584 $ 150,537 Exploration costs........................................ 63,245 5,427 68,672 Acquisition costs: Unproved properties.................................... 23,834 2,535 26,369 Proved properties...................................... 662,104 78,176 740,280 Sales of oil and gas properties.......................... (15,712) -- (15,712) Capitalized internal costs............................... 5,262 -- 5,262 Proceeds from sale of leasehold, equipment and other..... (296) -- (296) ---------- ---------- --------- Total.......................................... $ 884,390 $ 90,722 $ 975,112 ========== ========== ========= </TABLE> 66
67 <TABLE> <CAPTION> SIX MONTHS ENDED DECEMBER 31, 1997 - ---------------------------------- U.S. CANADA COMBINED ---------- ---------- --------- ($ IN THOUSANDS) <S> <C> <C> <C> Development costs........................................ $ 120,628 $ -- $ 120,628 Exploration costs........................................ 40,534 -- 40,534 Acquisition costs: Unproved properties.................................... 25,516 -- 25,516 Proved properties...................................... 39,245 -- 39,245 Sales of oil and gas properties.......................... -- -- -- Capitalized internal costs............................... 2,435 -- 2,435 Proceeds from sale of leasehold, equipment and other..... (1,861) -- (1,861) ---------- ---------- --------- Total.......................................... $ 226,497 $ -- $ 226,497 ========== ========== ========= </TABLE> <TABLE> <CAPTION> YEAR ENDED JUNE 30, 1997 - ------------------------ U.S. CANADA COMBINED ---------- ---------- --------- ($ IN THOUSANDS) <S> <C> <C> <C> Development costs........................................ $ 187,736 $ -- $ 187,736 Exploration costs........................................ 136,473 -- 136,473 Acquisition costs: Unproved properties.................................... 140,348 -- 140,348 Proved properties...................................... -- -- -- Sales of oil and gas properties.......................... -- -- -- Capitalized internal costs............................... 3,905 -- 3,905 Proceeds from sale of leasehold, equipment and other..... (3,095) -- (3,095) ---------- ---------- --------- Total.......................................... $ 465,367 $ -- $ 465,367 ========== ========== ========= </TABLE> <TABLE> <CAPTION> YEAR ENDED JUNE 30, 1996 - ------------------------ U.S. CANADA COMBINED ---------- ---------- --------- ($ IN THOUSANDS) <S> <C> <C> <C> Development costs........................................ $ 138,188 $ -- $ 138,188 Exploration costs........................................ 39,410 -- 39,410 Acquisition costs: Unproved properties.................................... 138,188 -- 138,188 Proved properties...................................... 24,560 -- 24,560 Sales of oil and gas properties.......................... -- -- -- Capitalized internal costs............................... 1,699 -- 1,699 Proceeds from sale of leasehold, equipment and other..... (6,167) -- (6,167) ---------- ---------- --------- Total.......................................... $ 335,878 $ -- $ 335,878 ========== ========== ========= </TABLE> Results of Operations from Oil and Gas Producing Activities (unaudited) The Company's results of operations from oil and gas producing activities are presented below for 1998, the six months ended December 31, 1997 and for the years ended June 30, 1997 and 1996, respectively. The following table includes revenues and expenses associated directly with the Company's oil and gas producing activities. It does not include any allocation of the Company's interest costs and, therefore, is not necessarily indicative of the contribution to consolidated net operating results of the Company's oil and gas operations. <TABLE> <CAPTION> YEAR ENDED DECEMBER 31, 1998 - ---------------------------- U.S. CANADA COMBINED ------------- ------------- ------------- ($ IN THOUSANDS) <S> <C> <C> <C> Oil and gas sales ............................................. $ 248,909 $ 7,978 $ 256,887 Production costs (a) .......................................... (57,663) (1,834) (59,497) Impairment of oil and gas properties .......................... (810,610) (15,390) (826,000) Depletion and depreciation .................................... (143,283) (3,361) (146,644) Imputed income tax (provision) benefit (b) .................... 285,981 5,673 291,654 ------------- ------------- ------------- Results of operations from oil and gas producing activities ... $ (476,666) $ (6,934) $ (483,600) ============= ============= ============= </TABLE> 67
68 <TABLE> <CAPTION> SIX MONTHS ENDED DECEMBER 31, 1997 - ---------------------------------- U.S. CANADA COMBINED ------------- ------------- ------------- ($ IN THOUSANDS) <S> <C> <C> <C> Oil and gas sales ............................................. $ 95,657 $ -- $ 95,657 Production costs (a) .......................................... (10,094) -- (10,094) Impairment of oil and gas properties .......................... (110,000) -- (110,000) Depletion and depreciation .................................... (60,408) -- (60,408) Imputed income tax (provision) benefit (b) .................... 31,817 -- 31,817 ------------- ------------- ------------- Results of operations from oil and gas producing activities ... $ (53,028) $ -- $ (53,028) ============= ============= ============= </TABLE> <TABLE> <CAPTION> YEAR ENDED JUNE 30, 1997 - ------------------------ U.S. CANADA COMBINED ------------- ------------- ------------- ($ IN THOUSANDS) <S> <C> <C> <C> Oil and gas sales ............................................. $ 192,920 $ -- $ 192,920 Production costs (a) .......................................... (15,107) -- (15,107) Impairment of oil and gas properties .......................... (236,000) -- (236,000) Depletion and depreciation .................................... (103,264) -- (103,264) Imputed income tax (provision) benefit (b) .................... 60,544 -- 60,544 ------------- ------------- ------------- Results of operations from oil and gas producing activities ... $ (100,907) $ -- $ (100,907) ============= ============= ============= </TABLE> <TABLE> <CAPTION> YEAR ENDED JUNE 30, 1996 - ------------------------- U.S. CANADA COMBINED ------------- ------------- ------------- ($ IN THOUSANDS) <S> <C> <C> <C> Oil and gas sales ............................................. $ 110,849 $ -- $ 110,849 Production costs (a) .......................................... (8,303) -- (8,303) Impairment of oil and gas properties .......................... -- -- -- Depletion and depreciation .................................... (50,899) -- (50,899) Imputed income tax (provision) benefit (b) .................... (18,335) -- (18,335) ------------- ------------- ------------- Results of operations from oil and gas producing activities ... $ 33,312 $ -- $ 33,312 ============= ============= ============= </TABLE> - ---------------------- (a) Production costs include lease operating expenses and production taxes. (b) The imputed income tax provision is hypothetical (at the statutory rate) and determined without regard to the Company's deduction for general and administrative expenses, interest costs and other income tax credits and deductions, nor whether the hypothetical tax benefits will be realized. Capitalized costs, less accumulated amortization and related deferred income taxes, cannot exceed an amount equal to the sum of the present value (discounted at 10%) of estimated future net revenues less estimated future expenditures to be incurred in developing and producing the proved reserves, less any related income tax effects. During 1998, capitalized costs of oil and gas properties exceeded the estimated present value of future net revenues from the Company's proved reserves, net of related income tax considerations, resulting in a writedown in the carrying value of oil and gas properties of $826 million. At December 31, 1997, capitalized costs of oil and gas properties exceeded the estimated present value of future net revenues for the Company's proved reserves, net of related income tax considerations, resulting in a writedown in the carrying value of oil and gas properties of $110 million. At June 30, 1997, capitalized costs of oil and gas properties also exceeded the estimated present value of future net revenues for the Company's proved reserves, net of related income tax considerations, resulting in a writedown in the carrying value of oil and gas properties of $236 million. Oil and Gas Reserve Quantities (unaudited) The reserve information presented below is based upon reports prepared by independent petroleum engineers and the Company's petroleum engineers. As of December 31, 1998, Williamson Petroleum Consultants, Inc. ("Williamson"), Ryder Scott Company Petroleum Engineers, H.J. Gruy and Associates, Inc. and the Company's internal reservoir engineers evaluated 63%, 12%, 1% and 24% of the Company's combined discounted future net revenues from the Company's estimated proved reserves, respectively. As of December 31, 1997, Williamson, Porter Engineering Associates, Netherland, Sewell & Associates, Inc. and internal reservoir engineers evaluated approximately 53%, 42%, 3% and 2% the Company's combined discounted future net revenues from the Company's estimated proved reserves, respectively. As of June 30, 1997 and 1996, the reserves evaluated by 68
69 Williamson constituted approximately 41% and 99% of the company's combined discounted future net revenues from the Company's estimated proved reserves, respectively, with the remaining reserves being evaluated internally. The reserves evaluated internally in fiscal 1997 were subsequently evaluated by Williamson with a variance of approximately 4% of total proved reserves. The information is presented in accordance with regulations prescribed by the Securities and Exchange Commission. The Company emphasizes that reserve estimates are inherently imprecise. The Company's reserve estimates were generally based upon extrapolation of historical production trends, analogy to similar properties and volumetric calculations. Accordingly, these estimates are expected to change, and such changes could be material and occur in the near term as future information becomes available. Proved oil and gas reserves represent the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed oil and gas reserves are those expected to be recovered through existing wells with existing equipment and operating methods. As of December 31, 1997, all of the Company's oil and gas reserves were located in the United States. Presented below is a summary of changes in estimated reserves of the Company for 1998, the six months ended December 31, 1997 and for the fiscal years 1997 and 1996: <TABLE> <CAPTION> DECEMBER 31, 1998 - ----------------- U.S. CANADA COMBINED -------------------------- -------------------------- -------------------------- OIL GAS OIL GAS OIL GAS (MBBL) (MMCF) (MBBL) (MMCF) (MBBL) (MMCF) ----------- ----------- ----------- ----------- ----------- ----------- <S> <C> <C> <C> <C> <C> <C> Proved reserves, beginning of period ..... 18,226 339,118 -- -- 18,226 339,118 Extensions, discoveries and other additions .............................. 3,448 90,879 -- -- 3,448 90,879 Revisions of previous estimates .......... (4,082) (60,477) -- -- (4,082) (60,477) Production ............................... (5,975) (86,681) (1) (7,740) (5,976) (94,421) Sale of reserves-in-place ................ (30) (3,515) -- -- (30) (3,515) Purchase of reserves-in-place ............ 10,973 444,694 34 239,513 11,007 684,207 ----------- ----------- ----------- ----------- ----------- ----------- Proved reserves, end of period ........... 22,560 724,018 33 231,773 22,593 955,791 =========== =========== =========== =========== =========== =========== Proved developed reserves: Beginning of period .................... 10,087 178,082 -- -- 10,087 178,082 =========== =========== =========== =========== =========== =========== End of period .......................... 18,003 552,953 33 105,990 18,036 658,943 =========== =========== =========== =========== =========== =========== </TABLE> <TABLE> <CAPTION> DECEMBER 31, 1997 - ----------------- U.S. CANADA COMBINED -------------------------- -------------------------- -------------------------- OIL GAS OIL GAS OIL GAS (MBBL) (MMCF) (MBBL) (MMCF) (MBBL) (MMCF) ----------- ----------- ----------- ----------- ----------- ----------- <S> <C> <C> <C> <C> <C> <C> Proved reserves, beginning of period ..... 17,373 298,766 -- -- 17,373 298,766 Extensions, discoveries and other additions .............................. 5,573 68,813 -- -- 5,573 68,813 Revisions of previous estimates .......... (3,428) (24,189) -- -- (3,428) (24,189) Production ............................... (1,857) (27,327) -- -- (1,857) (27,327) Sale of reserves-in-place ................ -- -- -- -- -- -- Purchase of reserves-in-place ............ 565 23,055 -- -- 565 23,055 ----------- ----------- ----------- ----------- ----------- ----------- Proved reserves, end of period ........... 18,226 339,118 -- -- 18,226 339,118 =========== =========== =========== =========== =========== =========== Proved developed reserves: Beginning of period .................... 7,324 151,879 -- -- 7,324 151,879 =========== =========== =========== =========== =========== =========== End of period .......................... 10,087 178,082 -- -- 10,087 178,082 =========== =========== =========== =========== =========== =========== </TABLE> 69
70 <TABLE> <CAPTION> JUNE 30, 1997 U.S. CANADA COMBINED - ------------- -------------------------- -------------------------- -------------------------- OIL GAS OIL GAS OIL GAS (MBBL) (MMCF) (MBBL) (MMCF) (MBBL) (MMCF) ----------- ----------- ----------- ----------- ----------- ----------- <S> <C> <C> <C> <C> <C> <C> Proved reserves, beginning of period ..... 12,258 351,224 -- -- 12,258 351,224 Extensions, discoveries and other additions .............................. 13,874 147,485 -- -- 13,874 147,485 Revisions of previous estimates .......... (5,989) (137,938) -- -- (5,989) (137,938) Production ............................... (2,770) (62,005) -- -- (2,770) (62,005) Sale of reserves-in-place ................ -- -- -- -- -- -- Purchase of reserves-in-place ............ -- -- -- -- -- -- ----------- ----------- ----------- ----------- ----------- ----------- Proved reserves, end of period ........... 17,373 298,766 -- -- 17,373 298,766 =========== =========== =========== =========== =========== =========== Proved developed reserves: Beginning of period .................... 3,648 144,721 -- -- 3,648 144,721 =========== =========== =========== =========== =========== =========== End of period .......................... 7,324 151,879 -- -- 7,324 151,879 =========== =========== =========== =========== =========== =========== </TABLE> <TABLE> <CAPTION> JUNE 30, 1996 U.S. CANADA COMBINED - ------------- -------------------------- -------------------------- -------------------------- OIL GAS OIL GAS OIL GAS (MBBL) (MMCF) (MBBL) (MMCF) (MBBL) (MMCF) ----------- ----------- ----------- ----------- ----------- ----------- <S> <C> <C> <C> <C> <C> <C> Proved reserves, beginning of period ..... 5,116 211,808 -- -- 5,116 211,808 Extensions, discoveries and other additions .............................. 8,781 158,052 -- -- 8,781 158,052 Revisions of previous estimates .......... (669) 12,987 -- -- (669) 12,987 Production ............................... (1,413) (51,710) -- -- (1,413) (51,710) Sale of reserves-in-place ................ -- -- -- -- -- -- Purchase of reserves-in-place ............ 443 20,087 -- -- 443 20,087 ----------- ----------- ----------- ----------- ----------- ----------- Proved reserves, end of period ........... 12,258 351,224 -- -- 12,258 351,224 =========== =========== =========== =========== =========== =========== Proved developed reserves: Beginning of period .................... 1,973 77,764 -- -- 1,973 77,764 =========== =========== =========== =========== =========== =========== End of period .......................... 3,648 144,721 -- -- 3,648 144,721 =========== =========== =========== =========== =========== =========== </TABLE> During 1998, the Company acquired approximately 750 Bcfe of proved reserves through merger or through purchases of oil and gas properties. The total consideration given for the acquisitions was 30.8 million shares of Company common stock, $280 million of cash, the assumption of $205 million of debt, and the incurrence of approximately $20 million of other acquisition related costs. Also during 1998, the Company recorded downward revisions to the December 31, 1997 estimates of approximately 4,082 MBbl and 60,477 MMcf, or approximately 85 Bcfe. These reserve revisions were primarily attributable to lower oil and gas prices at December 31, 1998. The weighted average prices used to value the Company's reserves at December 31, 1998 were $10.48 per barrel of oil and $1.68 per Mcf of gas, as compared to the prices used at December 31, 1997 of $17.62 per barrel of oil and $2.29 per Mcf of gas. For the six months ended December 31, 1997, the Company recorded downward revisions to the June 30, 1997 reserve estimates of approximately 3,428 MBbl and 24,189 MMcf, or approximately 45 Bcfe. The reserve revisions were primarily attributable to lower than expected results from development drilling and production which eliminated certain previously established proven reserves. On December 16, 1997, Chesapeake acquired AnSon Production Corporation, a privately owned oil and gas producer based in Oklahoma City. Consideration for this acquisition was approximately $43 million. The Company estimates that it acquired approximately 26.4 Bcfe in connection with this acquisition. For the fiscal year ended June 30, 1997, the Company recorded downward revisions to the previous year's reserve estimates of approximately 5,989 MBbl and 137,938 MMcf, or approximately 174 Bcfe. The reserve revisions were primarily attributable to the decrease in oil and gas prices between periods, higher drilling and completion costs, and unfavorable developmental drilling and production results during fiscal 1997. Specifically, the Company recorded aggregate downward adjustments to proved reserves of 159 Bcfe for the Knox, Giddings and Louisiana Trend areas. On April 30, 1996, the Company purchased interests in certain producing and non-producing oil and gas properties, including approximately 14,000 net acres of unevaluated leasehold, from Amerada Hess Corporation for 70
71 $37.8 million. The properties are located in the Knox and Golden Trend fields of southern Oklahoma, most of which are operated by the Company. In fiscal 1996 the reserves acquired from Amerada Hess Corporation were included in both "extensions, discoveries and other additions" and "purchase of reserves-in-place". The fiscal 1996 presentation has been restated to remove the acquired reserves from "extensions, discoveries and other additions" with a corresponding offset to "revisions of previous estimate". This revision resulted in no net change to total oil and gas reserves. Standardized Measure of Discounted Future Net Cash Flows (unaudited) Statement of Financial Accounting Standards No. 69 ("SFAS 69") prescribes guidelines for computing a standardized measure of future net cash flows and changes therein relating to estimated proved reserves. The Company has followed these guidelines which are briefly discussed below. Future cash inflows and future production and development costs are determined by applying year-end prices and costs to the estimated quantities of oil and gas to be produced. Estimates are made of quantities of proved reserves and the future periods during which they are expected to be produced based on year-end economic conditions. Estimated future income taxes are computed using current statutory income tax rates including consideration for the current tax basis of the properties and related carryforwards, giving effect to permanent differences and tax credits. The resulting future net cash flows are reduced to present value amounts by applying a 10% annual discount factor. The Company's reserve values were calculated using weighted average prices at December 31, 1998 of $10.48 per barrel of oil and $1.68 per Mcf of natural gas. If prices in future periods are below the average realized levels at December 31, 1998, future impairment charges will likely be incurred. The assumptions used to compute the standardized measure are those prescribed by the Financial Accounting Standards Board and, as such, do not necessarily reflect the Company's expectations of actual revenue to be derived from those reserves nor their present worth. The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the standardized measure computations since these estimates are the basis for the valuation process. The following summary sets forth the Company's future net cash flows relating to proved oil and gas reserves based on the standardized measure prescribed in SFAS 69: <TABLE> <CAPTION> DECEMBER 31, 1998 - ----------------- U.S. CANADA COMBINED ------------- ------------- ------------- ($ IN THOUSANDS) <S> <C> <C> <C> Future cash inflows (a) ................................. $ 1,374,280 $ 474,143 $ 1,848,423 Future production costs ................................. (432,876) (52,493) (485,369) Future development costs ................................ (124,717) (29,634) (154,351) Future income tax provision ............................. (6,464) (143,747) (150,211) ------------- ------------- ------------- Net future cash flows ................................... 810,223 248,269 1,058,492 Less effect of a 10% discount factor .................... (303,096) (132,281) (435,377) ------------- ------------- ------------- Standardized measure of discounted future net cash flows $ 507,127 $ 115,988 $ 623,115 ============= ============= ============= Discounted (at 10%) future net cash flows before income taxes .............................................. $ 504,148 $ 156,843 $ 660,991 ============= ============= ============= </TABLE> 71
72 <TABLE> <CAPTION> DECEMBER 31, 1997 - ----------------- U.S. CANADA COMBINED ------------- ------------- ------------- ($ IN THOUSANDS) <S> <C> <C> <C> Future cash inflows (b) ................................. $ 1,100,807 $ -- $ 1,100,807 Future production costs ................................. (223,030) -- (223,030) Future development costs ................................ (158,387) -- (158,387) Future income tax provision ............................. (108,027) -- (108,027) ------------- ------------- ------------- Net future cash flows ................................... 611,363 -- 611,363 Less effect of a 10% discount factor .................... (181,253) -- (181,253) ------------- ------------- ------------- Standardized measure of discounted future net cash flows............................................ $ 430,110 $ -- $ 430,110 ============= ============= ============= Discounted (at 10%) future net cash flows before income taxes ........................................... $ 466,509 $ -- $ 466,509 ============= ============= ============= </TABLE> <TABLE> <CAPTION> JUNE 30, 1997 U.S. CANADA COMBINED - ------------- ------------- ------------- ------------- ($ IN THOUSANDS) <S> <C> <C> <C> Future cash inflows (c) ................................. $ 954,839 $ -- $ 954,839 Future production costs ................................. (190,604) -- (190,604) Future development costs ................................ (152,281) -- (152,281) Future income tax provision ............................. (104,183) -- (104,183) ------------- ------------- ------------- Net future cash flows ................................... 507,771 -- 507,771 Less effect of a 10% discount factor .................... (92,273) -- (92,273) ------------- ------------- ------------- Standardized measure of discounted future net cash flows ........................................... $ 415,498 $ -- $ 415,498 ============= ============= ============= Discounted (at 10%) future net cash flows before income taxes ........................................... $ 437,386 $ -- $ 437,386 ============= ============= ============= </TABLE> <TABLE> <CAPTION> JUNE 30, 1996 - ------------- U.S. CANADA COMBINED ------------- ------------- ------------- ($ IN THOUSANDS) <S> <C> <C> <C> Future cash inflows (d) ................................. $ 1,101,642 $ -- $ 1,101,642 Future production costs ................................. (168,974) -- (168,974) Future development costs ................................ (137,068) -- (137,068) Future income tax provision ............................. (135,543) -- (135,543) ------------- ------------- ------------- Net future cash flows ................................... 660,057 -- 660,057 Less effect of a 10% discount factor .................... (198,646) -- (198,646) ------------- ------------- ------------- Standardized measure of discounted future net cash flows $ 461,411 $ -- $ 461,411 ============= ============= ============= Discounted (at 10%) future net cash flows before income taxes ......................................... $ 547,016 $ -- $ 547,016 ============= ============= ============= </TABLE> - ---------- (a) Calculated using weighted average prices of $10.48 per barrel of oil and $1.68 per Mcf of gas. (b) Calculated using weighted average prices of $17.62 per barrel of oil and $2.29 per Mcf of gas. (c) Calculated using weighted average prices of $18.38 per barrel of oil and $2.12 per Mcf of gas. (d) Calculated using weighted average prices of $20.90 per barrel of oil and $2.41 per Mcf of gas. The principal sources of change in the standardized measure of discounted future net cash flows are as follows: 72
73 <TABLE> <CAPTION> DECEMBER 31, 1998 - ----------------- U.S. CANADA COMBINED ----------- ----------- ----------- ($ IN THOUSANDS) <S> <C> <C> <C> Standardized measure, beginning of period ............... $ 430,110 $ -- $ 430,110 Sales of oil and gas produced, net of production costs .. (191,246) (6,144) (197,390) Net changes in prices and production costs .............. (189,817) -- (189,817) Extensions and discoveries, net of production and development costs ................................... 85,464 -- 85,464 Changes in future development costs ..................... 72,279 -- 72,279 Development costs incurred during the period that reduced future development costs ............................ 28,191 -- 28,191 Revisions of previous quantity estimates ................ (64,770) -- (64,770) Purchase of reserves-in-place ........................... 288,694 164,821 453,515 Sales of reserves-in-place .............................. (3,079) -- (3,079) Accretion of discount ................................... 46,651 -- 46,651 Net change in income taxes .............................. 39,377 (40,855) (1,478) Changes in production rates and other ................... (34,727) (1,834) (36,561) ----------- ----------- ----------- Standardized measure, end of period ..................... $ 507,127 $ 115,988 $ 623,115 =========== =========== =========== </TABLE> <TABLE> <CAPTION> DECEMBER 31, 1997 - ----------------- U.S. CANADA COMBINED ----------- ----------- ----------- ($ IN THOUSANDS) <S> <C> <C> <C> Standardized measure, beginning of period ............... $ 415,498 $ -- $ 415,498 Sales of oil and gas produced, net of production costs .. (85,563) -- (85,563) Net changes in prices and production costs .............. 26,106 -- 26,106 Extensions and discoveries, net of production and development costs.................................... 92,597 -- 92,597 Changes in future development costs ..................... (7,422) -- (7,422) Development costs incurred during the period that reduced future development costs ............................ 47,703 -- 47,703 Revisions of previous quantity estimates ................ (62,655) -- (62,655) Purchase of reserves-in-place ........................... 25,236 -- 25,236 Sales of reserves-in-place .............................. -- -- -- Accretion of discount ................................... 43,739 -- 43,739 Net change in income taxes .............................. (14,510) -- (14,510) Changes in production rates and other ................... (50,619) -- (50,619) ----------- ----------- ----------- Standardized measure, end of period ..................... $ 430,110 $ -- $ 430,110 =========== =========== =========== </TABLE> <TABLE> <CAPTION> JUNE 30, 1997 - ------------- U.S. CANADA COMBINED ----------- ----------- ----------- ($ IN THOUSANDS) <S> <C> <C> <C> Standardized measure, beginning of period ............... $ 461,411 $ -- $ 461,411 Sales of oil and gas produced, net of production costs .. (177,813) -- (177,813) Net changes in prices and production costs .............. (99,234) -- (99,234) Extensions and discoveries, net of production and development costs.................................... 287,068 -- 287,068 Changes in future development costs ..................... (12,831) -- (12,831) Development costs incurred during the period that reduced future development costs ............................ 46,888 -- 46,888 Revisions of previous quantity estimates ................ (199,738) -- (199,738) Purchase of reserves-in-place ........................... -- -- -- Sales of reserves-in-place .............................. -- -- -- Accretion of discount ................................... 54,702 -- 54,702 Net change in income taxes .............................. 63,719 -- 63,719 Changes in production rates and other ................... (8,674) -- (8,674) ----------- ----------- ----------- Standardized measure, end of period ..................... $ 415,498 $ -- $ 415,498 =========== =========== =========== </TABLE> 73
74 <TABLE> <CAPTION> JUNE 30, 1996 - ------------- U.S. CANADA COMBINED ----------- ----------- ----------- ($ IN THOUSANDS) <S> <C> <C> <C> Standardized measure, beginning of period ................................ $ 159,911 $ -- $ 159,911 Sales of oil and gas produced, net of production costs ................... (102,546) -- (102,546) Net changes in prices and production costs ............................... 88,729 -- 88,729 Extensions and discoveries, net of production and development costs....... 275,916 -- 275,916 Changes in future development costs ...................................... (11,201) -- (11,201) Development costs incurred during the period that reduced future development costs ............................................. 43,409 -- 43,409 Revisions of previous quantity estimates ................................. 12,728 -- 12,728 Purchase of reserves-in-place ............................................ 29,641 -- 29,641 Sales of reserves-in-place ............................................... -- -- -- Accretion of discount .................................................... 18,814 -- 18,814 Net change in income taxes ............................................... (57,382) -- (57,382) Changes in production rates and other .................................... 3,392 -- 3,392 ----------- ----------- ----------- Standardized measure, end of period ...................................... $ 461,411 $ -- $ 461,411 =========== =========== =========== </TABLE> 12. TRANSITION PERIOD COMPARATIVE DATA The following table presents certain financial information for the twelve months ended December 31, 1998 and 1997, and the six months ended December 31, 1997 and 1996, respectively: <TABLE> <CAPTION> TWELVE MONTHS ENDED SIX MONTHS ENDED DECEMBER 31, DECEMBER 31, ------------------------------ ------------------------------ 1998 1997 1997 1996 ------------- ------------- ------------- ------------- (UNAUDITED) (UNAUDITED) ($ IN THOUSANDS, EXCEPT PER SHARE DATA) <S> <C> <C> <C> <C> Revenues ............................................ $ 377,946 $ 302,804 $ 153,898 $ 120,186 ============= ============= ============= ============= Gross profit (loss)(a) .............................. $ (856,197) $ (309,041) $ (93,092) $ 42,946 ============= ============= ============= ============= Income (loss) before income taxes and extraordinary item ............................ $ (920,520) $ (251,150) $ (31,574) $ 39,246 Income taxes ........................................ -- (17,898) -- 14,325 ------------- ------------- ------------- ------------- Income (loss) before extraordinary item ............. (920,520) (233,252) (31,574) 24,921 Extraordinary item .................................. (13,334) (177) -- (6,443) ------------- ------------- ------------- ------------- Net income (loss) ................................... $ (933,854) $ (233,429) $ (31,574) $ 18,478 ============= ============= ============= ============= Earnings per share - basic Income (loss) before extraordinary item ......... $ (9.83) $ (3.30) $ (0.45) $ 0.40 Extraordinary item .............................. (0.14) -- -- (0.10) ------------- ------------- ------------- ------------- Net income (loss) ............................... $ (9.97) $ (3.30) $ (0.45) $ 0.30 ============= ============= ============= ============= Earnings per share - assuming dilution Income (loss) before extraordinary item ......... $ (9.83) $ (3.30) $ (0.45) $ 0.38 Extraordinary item .............................. (0.14) -- -- (0.10) ------------- ------------- ------------- ------------- Net income (loss) ............................... $ (9.97) $ (3.30) $ (0.45) $ 0.28 ============= ============= ============= ============= Weighted average common shares outstanding (in 000's) Basic ........................................... 94,911 70,672 70,835 61,985 ============= ============= ============= ============= Assuming dilution ............................... 94,911 70,672 70,835 66,300 ============= ============= ============= ============= </TABLE> - ---------- (a) Total revenue excluding interest and other income, less total costs and expenses excluding interest and other expense. 74
75 13. QUARTERLY FINANCIAL DATA (UNAUDITED) Summarized unaudited quarterly financial data for 1998, the six months ended December 31, 1997 and fiscal 1997 are as follows ($ in thousands except per share data): <TABLE> <CAPTION> QUARTER ENDED ---------------------------------------------------------------- MARCH 31, JUNE 30, SEPTEMBER 30, DECEMBER 31, 1998 1998 1998 1998 ------------- ------------- ------------- ------------- <S> <C> <C> <C> <C> Net sales ........................................ $ 76,765 $ 109,310 $ 106,338 $ 85,533 Gross profit (loss)(a) ........................... (246,036) (218,645) 13,650 (405,166) Net income (loss) before extraordinary item ...... (256,500) (234,739) (4,149) (425,132) Net income (loss) ................................ (256,500) (248,073) (4,149) (425,132) Income (loss) per share before extraordinary item: Basic .......................................... (3.19) (2.29) (0.08) (4.44) Diluted ........................................ (3.19) (2.29) (0.08) (4.44) </TABLE> <TABLE> <CAPTION> QUARTER ENDED ----------------------------- SEPTEMBER 30, DECEMBER 31, 1997 1997 ------------- ------------- <S> <C> <C> Net sales ............................................ $ 72,532 $ 81,366 Gross profit (loss)(a) ............................... 8,210 (101,302) Net Income (loss) .................................... 5,513 (37,087) Net Income (loss) per share before extraordinary item: Basic .............................................. .08 (.52) Diluted ............................................ .08 (.52) </TABLE> <TABLE> <CAPTION> QUARTER ENDED ------------------------------------------------------------- SEPTEMBER 30, DECEMBER 31, MARCH 31, JUNE 30, 1996 1996 1997 1997 ------------- ------------- ------------- ------------- <S> <C> <C> <C> <C> Net sales ........................................ $ 48,937 $ 71,249 $ 79,809 $ 69,097 Gross profit (loss)(a) ........................... 14,889 28,057 25,737 (241,686) Income (loss) before extraordinary item .......... 8,204 16,717 16,105 (217,783) Net income (loss) ................................ 8,204 10,274 15,928 (217,783) Income (loss) per share before extraordinary item: Basic .......................................... .14 .26 .23 (3.12) Diluted ........................................ .13 .25 .22 (3.12) </TABLE> - ---------- (a) Total revenue excluding interest and other income, less total costs and expenses excluding interest and other expense. Capitalized costs, less accumulated amortization and related deferred income taxes, cannot exceed an amount equal to the sum of the present value of estimated future net revenues less estimated future expenditures to be incurred in developing and producing the proved reserves, less any related income tax effects. At December 31, 1998, June 30, 1998, March 31, 1998, December 31, 1997 and June 30, 1997, capitalized costs of oil and gas properties exceeded the estimated present value of future net revenues for the Company's proved reserves, net of related income tax considerations, resulting in writedowns in the carrying value of oil and gas properties of $360 million, $216 million, $250 million, $110 million and $236 million, respectively. During the fourth quarter of 1998, the Company incurred a $55 million impairment charge to adjust certain non-oil and gas assets to their estimated fair values. Of this amount, $30 million related to the Company's investment in preferred stock of Gothic Energy Corporation, and the remainder was related to certain of the Company's gas processing and transportation assets located in Louisiana. 14. ACQUISITIONS During 1998, the Company acquired approximately 750 Bcfe of proved reserves through merger or through purchases of oil and gas properties. The total consideration given for the acquisitions was $280 million of cash, 75
76 30.8 million shares of Company common stock, the assumption of $205 million of debt, and the incurrence of approximately $20 million of other acquisition related costs. In March 1998, the Company acquired Hugoton Energy Corporation ("Hugoton") pursuant to a merger by issuing 25.8 million shares of the Company's common stock in exchange for 100% of Hugoton's common stock. The acquisition of Hugoton was accounted for using the purchase method as of March 1, 1998, and the results of operations of Hugoton have been included since that date. The following unaudited pro forma information has been prepared assuming Hugoton had been acquired as of the beginning of the periods presented. The pro forma information is presented for informational purposes only and is not necessarily indicative of what would have occurred if the acquisition had been made as of those dates. In addition, the pro forma information is not intended to be a projection of future results and does not reflect the efficiencies expected to result from the integration of Hugoton. Pro Forma Information (Unaudited) <TABLE> <CAPTION> YEAR ENDED DECEMBER 31, ---------------------------------- 1998 1997 --------------- --------------- (IN THOUSANDS, EXCEPT PER SHARE DATA) <S> <C> <C> Revenues .............................................. $ 387,638 $ 379,546 Loss before extraordinary item ........................ $ (921,969) $ (215,350) Net loss .............................................. $ (935,303) $ (215,527) Loss before extraordinary item per common share .............................................. $ (9.41) $ (2.23) Net loss per common share ............................. $ (9.55) $ (2.23) </TABLE> The Company acquired other businesses and oil and gas properties during the twelve months ended December 31, 1998. The results of operations of each of these businesses and properties, taken individually, were not material in relation to the Company's consolidated results of operations. 76
77 SCHEDULE II CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES VALUATION AND QUALIFYING ACCOUNTS ($ IN THOUSANDS) <TABLE> <CAPTION> ADDITIONS ------------------------- BALANCE AT CHARGED BALANCE AT BEGINNING CHARGED TO OTHER END DESCRIPTION OF PERIOD TO EXPENSE ACCOUNTS DEDUCTIONS OF PERIOD - -------------------------------------------- ----------- ----------- ----------- ----------- ----------- <S> <C> <C> <C> <C> <C> December 31, 1998: Allowance for doubtful accounts .......... $ 691 $ 1,589 $ 1,000 $ 71 $ 3,209 Valuation allowance for deferred tax assets ................................. $ 77,934 $ 380,969 $ -- $ -- $ 458,903 December 31, 1997: Allowance for doubtful accounts .......... $ 387 $ 40 $ 264 $ -- $ 691 Valuation allowance for deferred tax assets ................................. $ 64,116 $ 13,818 $ -- $ -- $ 77,934 June 30, 1997: Allowance for doubtful accounts .......... $ 340 $ 299 $ -- $ 252 $ 387 Valuation allowance for deferred tax assets ................................. $ -- $ 64,116 $ -- $ -- $ 64,116 June 30, 1996: Allowance for doubtful accounts .......... $ 452 $ 114 $ -- $ 226 $ 340 </TABLE> 77
78 ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE Not applicable. PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT The information called for by this Item 10 is incorporated herein by reference to the definitive Proxy Statement to be filed by the Company pursuant to Regulation 14A of the General Rules and Regulations under the Securities Exchange Act of 1934 not later than April 30, 1999. ITEM 11. EXECUTIVE COMPENSATION The information called for by this Item 11 is incorporated herein by reference to the definitive Proxy Statement to be filed by the Company pursuant to Regulation 14A of the General Rules and Regulations under the Securities Exchange Act of 1934 not later than April 30, 1999. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT The information called for by this Item 12 is incorporated herein by reference to the definitive Proxy Statement to be filed by the Company pursuant to Regulation 14A of the General Rules and Regulations under the Securities Exchange Act of 1934 not later than April 30, 1999. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS The information called for by this Item 13 is incorporated herein by reference to the definitive Proxy Statement to be filed by the Company pursuant to Regulation 14A of the General Rules and Regulations under the Securities Exchange Act of 1934 not later than April 30, 1999. 78
79 PART IV ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K (a) The following documents are filed as part of this report: 1. Financial Statements. The Company's consolidated financial statements are included in Item 8 of this report. Reference is made to the accompanying Index to Consolidated Financial Statements. 2. Financial Statement Schedules. No financial statement schedules are filed with this report as no schedules are applicable or required. 3. Exhibits. The following exhibits are filed herewith pursuant to the requirements of Item 601 of Regulation S-K: EXHIBIT NUMBER DESCRIPTION ------ ----------- 3.1 -- Registrant's Certificate of Incorporation as amended. Incorporated herein by reference to Exhibit 3.1 to Registrant's Amendment No. 1 to Form S-3 registration statement (No. 333-57235). 3.2 -- Registrant's Bylaws. Incorporated herein by reference to Exhibit 3.2 to Registrant's registration statement on Form 8-B (No. 001-13726). 4.1 -- Indenture dated as of March 15, 1997 among the Registrant, as issuer, Chesapeake Operating, Inc., Chesapeake Gas Development Corporation and Chesapeake Exploration Limited Partnership, as Subsidiary Guarantors, and United States Trust Company of New York, as Trustee, with respect to 7.875% Senior Notes due 2004. Incorporated herein by reference to Exhibit 4.1 to Registrant's registration statement on Form S-4 (No. 333-24995). First Supplemental Indenture dated December 17, 1997 and Second Supplemental Indenture dated February 16, 1998. Incorporated herein by reference to Exhibit 4.1.1 to Registrant's transition report on Form 10-K for the six months ended December 31, 1997. Second [Third] Supplemental Indenture dated April 22, 1998. Incorporated herein by reference to Exhibit 4.1.1 to Registrant's Amendment No. 1 to Form S-3 registration statement (No. 333-57235). Fourth Supplemental Indenture dated July 1, 1998. Incorporated herein by reference to Exhibit 4.1.1 to Registrant's quarterly report on Form 10-Q for the quarter ended September 30, 1998. 4.2 -- Indenture dated as of March 15, 1997 among the Registrant, as issuer, Chesapeake Operating, Inc., Chesapeake Gas Development Corporation and Chesapeake Exploration Limited Partnership, as Subsidiary Guarantors, and United States Trust Company of New York, As Trustee, with respect to 8.5% Senior Notes due 2012. Incorporated herein by reference to Exhibit 4.1.3 to Registrant registration statement on Form S-4 (No. 333-24995). First Supplemental Indenture dated December 17, 1997 and Second Supplemental Indenture dated February 16, 1998. Incorporated herein by reference to Exhibit 4.2.1 to Registrant's transition report on Form 10-K for the six months ended December 31, 1997. Second [Third] Supplemental Indenture dated April 22, 1998. Incorporated herein by reference to Exhibit 4.2.1 to Registrant's Amendment No. 1 to Form S-3 registration statement (No. 333-57235). Fourth Supplemental Indenture dated July 1, 1998. Incorporated herein by reference to Exhibit 4.2.1 to Registrant's quarterly report on Form 10-Q for the quarter ended September 30, 1998. 4.3 -- Indenture dated as of April 1, 1998 among the Registrant, as Subsidiary Guarantors, and United States Trust Company of New York, As Trustee, with respect to 9-5/8% Senior Notes due 2005. Incorporated herein by reference to Exhibit 4.3 to Registrant registration statement 79
80 on Form S-3 (No. 333-57235). First Supplemental Indenture dated July 1, 1998. Incorporated herein by reference to Exhibit 4.4.1 to Registrant's quarterly report on Form 10-Q for the quarter ended September 30, 1998. 4.4 -- Indenture dated as of April 1, 1996 among the Registrant, its subsidiaries signatory thereto, as Subsidiary Guarantors, and United States Trust Company of New York, as Trustee, with respect to 9-1/8% Senior Notes, due 2006. Incorporated herein by reference to Exhibit 4.6 to Registrant's registration statement on Form S-3 9No. 333-1588). First Supplemental Indenture dated December 30, 1996 and Second Supplemental Indenture dated December 17, 1997. Incorporated herein by reference to Exhibit 4.4.1 to Registrant's transition report on Form 10-K for the six months ended December 31, 1997. Third Supplemental Indenture dated April 22, 1998. Incorporated herein by reference to Exhibit 4.4.1 to Registrant's Amendment No. 1 to Form S-3 registration statement (No. 333-57235). Fourth Supplemental Indenture dated July 1, 1998. Incorporated herein by reference to Exhibit 4.3.1 to Registrant's quarterly report on Form 10-Q for the quarter ended September 30, 1998. 4.5 -- Agreement to furnish copies of unfiled long-term debt Instruments. Incorporated herein by reference to Registrant's transition report on Form 10-K for the six months ended December 31, 1997. 4.9 -- Registration Rights Agreement dated October 22, 1997 as amended by Amendment No. 1 dated December 22, 1997 between Chesapeake Energy Corporation and Charles E. Davidson. Incorporated herein by reference to Exhibit 4.9 and 4.10 to Registrant's registration statement on Form S-4 (No. 333-48735). 4.10 -- Registration Rights Agreement between Chesapeake Energy Corporation and certain shareholders of Hugoton Energy Corporation. Incorporated herein by reference to Registrant's registration statement on Form S-4 (No. 333-48735). 4.11 -- Registration Rights Agreement as of April 22, 1998 among the Registrant and Donaldson, Lufkin & Jenrette Securities Corporation, Morgan Stanley & Co. Incorporated, Bear Stearns & Co. Inc., Lehman Brothers Inc. and J.P. Morgan Securities Inc., with respect to 7% Cumulative Convertible Preferred Stock. Incorporated herein by reference to Exhibit 4.11 to Registrant's quarterly report on Form 10-Q for the quarter ended March 31, 1998. 10.1.1+ -- Registrant's 1992 Incentive Stock Option Plan. Incorporated herein by reference to Exhibit 10.1.1 to Registrant's registration statement on Form S-4 (No. 33-93718). 10.1.2+ -- Registrant's 1992 Nonstatutory Stock Option Plan, as Amended. Incorporated herein by reference to Exhibit 10.1.2 to Registrant's quarterly report on Form 10-Q for the quarter ended December 31, 1996. 10.1.3+ -- Registrant's 1994 Stock Option Plan, as amended. Incorporated herein by reference to Exhibit 10.1.3 to Registrant's quarterly report on Form 10-Q for the quarter ended December 31, 1996. 10.1.4+ -- Registrant's 1996 Stock Option Plan. Incorporated herein by reference to Registrant's Proxy Statement for its 1996 Annual Meeting of Shareholders. 10.1.4.1 -- Amendment to the Chesapeake Energy Corporation 1996 Stock Option Plan. Incorporated herein by reference to Exhibit 10.1.4.1 to Registrant's quarterly report on Form 10-Q for the quarter ended December 31, 1996. 10.2.1+ -- Amended and Restated Employment Agreement dated as of July 1, 1998 between Aubrey K. McClendon and Chesapeake Energy Corporation. Incorporated herein by reference to Exhibit 10.2.1 to Registrant's quarterly report on Form 10-Q for the quarter ended September 30, 1998. 80
81 10.2.2+ -- Amended and Restated Employment Agreement dated as of July 1, 1998 between Tom L. Ward and Chesapeake Energy Corporation. Incorporated herein by reference to Exhibit 10.2.2 to Registrant's quarterly report on Form 10-Q for the quarter ended September 30, 1998. 10.2.3*+ -- Amended and Restated Employment Agreement dated as of July 1, 1998 between Marcus C. Rowland and Chesapeake Energy Corporation. 10.2.4+ -- Employment Agreement dated as of July 1, 1997 between Steven C. Dixon and Chesapeake Energy Corporation. Incorporated herein by reference to Exhibit 10.2.4 to Registrant's quarterly report on Form 10-Q for the quarter ended September 30, 1997. 10.2.5+ -- Employment Agreement dated as of July 1, 1997 between J. Mark Lester and Chesapeake Energy Corporation. Incorporated herein by reference to Exhibit 10.2.5 to Registrant's annual report on Form 10-K for the year ended June 30, 1997. 10.2.6+ -- Employment Agreement dated as of July 1, 1997 between Henry J. Hood and Chesapeake Energy Corporation. Incorporated herein by reference to Exhibit 10.2.6 to Registrant's annual report on Form 10-K for the year ended June 30, 1997. 10.2.7+ -- Employment Agreement dated as of July 1, 1997 between Ronald A. Lefaive and Chesapeake Energy Corporation. Incorporated herein by reference to Exhibit 10.2.7 to Registrant's annual report on Form 10-K for the year ended June 30, 1997. 10.2.8+ -- Employment Agreement dated as of July 1, 1997 between Martha A. Burger and Chesapeake Energy Corporation. Incorporated herein by reference to Exhibit 10.2.8 to Registrant's annual report on Form 10-K for the year ended June 30, 1997. 10.2.9* -- Amendment to Employment Agreements of Steven C. Dixon, J. Mark Lester, Henry J. Hood, Ronald A. Lefaive and Martha A. Burger dated as of July 1, 1997. 10.3+ -- Form of Indemnity Agreement for officers and directors of Registrant and its subsidiaries. Incorporated herein by reference to Exhibit 10.30 to Registrant's Registration statement on Form S-1 (No. 33-55600). 10.4.1* -- Second Amended and Restated Loan Agreement between Aubrey K. McClendon and Chesapeake Energy Marketing, Inc., dated effective December 31, 1998. 10.4.2* -- Second Amended and Restated Loan Agreement between Tom L. Ward and Chesapeake Energy Marketing, Inc., dated effective December 31, 1998. 10.5 -- Rights Agreement dated July 15, 1998 between the Registrant and UMB Bank, N.A., as Rights Agent. Incorporated herein by reference to Exhibit 1 to Registrant's registration statement on Form 8-A filed July 16, 1998. Amendment No. 1 dated September 11, 1998. Incorporated herein by reference to Exhibit 10.3 to Registrant's quarterly report on Form 10-Q for the quarter ended September 30, 1998. 10.9 -- Indemnity and Stock Registration Agreement, as amended by First Amendment (Revised) thereto, dated as of February 12, 1993, and as amended by Second Amendment thereto dated as of October 20, 1995, among Chesapeake Energy Corporation, Chesapeake Operating, Inc., Chesapeake Investments, TLW Investments, Inc., et al. Incorporated herein by reference to Exhibit 10.35 to Registrant's annual report on Form 10-K for the year ended June 30, 1993 and Exhibit 10.4.1 to Registrant's Quarterly report on Form 10-Q for the quarter ended December 31, 1995. 10.10 -- Partnership Agreement of Chesapeake Exploration Limited Partnership dated December 27, 1994 between Chesapeake Energy Corporation and Chesapeake Operating, Inc. Incorporated 81
82 herein by reference to Exhibit 10.10 to Registrant's registration statement on Form S-4 (No. 33-93718). 10.11 -- Amended and Restated Limited Partnership Agreement of Chesapeake Louisiana, L.P. dated June 30, 1997 between Chesapeake Operating, Inc. and Chesapeake Energy Louisiana Corporation. 21* -- Subsidiaries of Registrant 23.1* -- Consent of PricewaterhouseCoopers LLP 23.2* -- Consent of Williamson Petroleum Consultants, Inc. 23.3* -- Consent of Ryder Scott Company Petroleum Engineers 27* -- Financial Data Schedule - ---------- * Filed herewith. + Management contract or compensatory plan or arrangement. (b) Reports on Form 8-K During the quarter ended December 31, 1998, the Company filed the following Current Reports on Form 8-K dated: October 7, 1998 announcing a significant Tuscaloosa discovery. October 23, 1998 providing a status report on drilling activity. November 9, 1998 announcing that it had agreed to tender its 19.9% stake in Pan East Petroleum Corp. to Poco Petroleums Ltd. and had agreed to a property exchange with Pan East. November 18, 1998 reporting 1998 third quarter results. December 8, 1998 announcing completion of a significant Tuscaloosa discovery. December 17, 1998 announcing capital budget and suspension of dividend of its preferred stock. December 22, 1998 responding to Union Pacific Resources Corporation's press release regarding pending litigation. 82
83 SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. CHESAPEAKE ENERGY CORPORATION By /s/ AUBREY K. McCLENDON --------------------------------- Aubrey K. McClendon Chairman of the Board and Chief Executive Officer Date: March 30, 1999 Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. <TABLE> <CAPTION> SIGNATURE TITLE DATE - -------------------------------------- -------------------------------------- -------------- <S> <C> <C> /s/ AUBREY K. McCLENDON Chairman of the Board, Chief Executive March 30, 1999 - -------------------------------------- Officer and Director Aubrey K. McClendon (Principal Executive Officer) /s/ TOM L. WARD President, Chief Operating Officer and March 30, 1999 - -------------------------------------- Director Tom L. Ward (Principal Executive Officer) /s/ MARCUS C. ROWLAND Executive Vice President and Chief March 30, 1999 - -------------------------------------- Financial Officer Marcus C. Rowland (Principal Financial Officer) /s/ RONALD A. LEFAIVE Senior Vice President - Accounting, March 30, 1999 - -------------------------------------- Controller and Chief Accounting Officer Ronald A. Lefaive (Principal Accounting Officer) /s/ EDGAR F. HEIZER, JR. Director March 30, 1999 - -------------------------------------- Edgar F. Heizer, Jr. /s/ BREENE M. KERR Director March 30, 1999 - -------------------------------------- Breene M. Kerr /s/ SHANNON T. SELF Director March 30, 1999 - -------------------------------------- Shannon T. Self /s/ FREDERICK B. WHITTEMORE Director March 30, 1999 - -------------------------------------- Frederick B. Whittemore /s/ WALTER C. WILSON Director March 30, 1999 - -------------------------------------- Walter C. Wilson </TABLE> 83
84 INDEX TO EXHIBITS <TABLE> <CAPTION> EXHIBIT NUMBER DESCRIPTION PAGE -------- ----------- ---- <S> <C> <C> 3.1 -- Registrant's Certificate of Incorporation as amended. Incorporated herein by reference to Exhibit 3.1 to Registrant's Amendment No. 1 to Form S-3 registration statement (No. 333-57235). 3.2 -- Registrant's Bylaws. Incorporated herein by reference to Exhibit 3.2 to Registrant's registration statement on Form 8-B (No. 001-13726). 4.1 -- Indenture dated as of March 15, 1997 among the Registrant, as issuer, Chesapeake Operating, Inc., Chesapeake Gas Development Corporation and Chesapeake Exploration Limited Partnership, as Subsidiary Guarantors, and United States Trust Company of New York, as Trustee, with respect to 7.875% Senior Notes due 2004. Incorporated herein by reference to Exhibit 4.1 to Registrant's registration statement on Form S-4 (No. 333-24995). First Supplemental Indenture dated December 17, 1997 and Second Supplemental Indenture dated February 16, 1998. Incorporated herein by reference to Exhibit 4.1.1 to Registrant's transition report on Form 10-K for the six months ended December 31, 1997. Second [Third] Supplemental Indenture dated April 22, 1998. Incorporated herein by reference to Exhibit 4.1.1 to Registrant's Amendment No. 1 to Form S-3 registration statement (No. 333-57235). Fourth Supplemental Indenture dated July 1, 1998. Incorporated herein by reference to Exhibit 4.1.1 to Registrant's quarterly report on Form 10-Q for the quarter ended September 30, 1998. 4.2 -- Indenture dated as of March 15, 1997 among the Registrant, as issuer, Chesapeake Operating, Inc., Chesapeake Gas Development Corporation and Chesapeake Exploration Limited Partnership, as Subsidiary Guarantors, and United States Trust Company of New York, As Trustee, with respect to 8.5% Senior Notes due 2012. Incorporated herein by reference to Exhibit 4.1.3 to Registrant registration statement on Form S-4 (No. 333-24995). First Supplemental Indenture dated December 17, 1997 and Second Supplemental Indenture dated February 16, 1998. Incorporated herein by reference to Exhibit 4.2.1 to Registrant's transition report on Form 10-K for the six months ended December 31, 1997. Second [Third] Supplemental Indenture dated April 22, 1998. Incorporated herein by reference to Exhibit 4.2.1 to Registrant's Amendment No. 1 to Form S-3 registration statement (No. 333-57235). Fourth Supplemental Indenture dated July 1, 1998. Incorporated herein by reference to Exhibit 4.2.1 to Registrant's quarterly report on Form 10-Q for the quarter ended September 30, 1998. 4.3 -- Indenture dated as of April 1, 1998 among the Registrant, as Subsidiary Guarantors, and United States Trust Company of New York, As Trustee, with respect to 9-5/8% Senior Notes due 2005. Incorporated herein by reference to Exhibit 4.3 to Registrant registration statement on Form S-3 (No. 333-57235). First Supplemental Indenture dated July 1, 1998. Incorporated herein by reference to Exhibit 4.4.1 to Registrant's quarterly report on Form 10-Q for the quarter ended September 30, 1998. 4.4 -- Indenture dated as of April 1, 1996 among the Registrant, its subsidiaries signatory thereto, as Subsidiary Guarantors, and United States Trust Company of New York, as Trustee, with respect to 9-1/8% Senior Notes, due 2006. Incorporated herein by reference to Exhibit 4.6 to Registrant's registration statement on Form S-3 9No. 333-1588). First Supplemental Indenture dated December 30, 1996 and Second Supplemental Indenture dated December 17, 1997. Incorporated herein by reference to Exhibit 4.4.1 to Registrant's transition report on Form 10-K for the six months </TABLE>
85 <TABLE> <CAPTION> EXHIBIT NUMBER DESCRIPTION PAGE -------- ----------- ---- <S> <C> <C> ended December 31, 1997. Third Supplemental Indenture dated April 22, 1998. Incorporated herein by reference to Exhibit 4.4.1 to Registrant's Amendment No. 1 to Form S-3 registration statement (No. 333-57235). Fourth Supplemental Indenture dated July 1, 1998. Incorporated herein by reference to Exhibit 4.3.1 to Registrant's quarterly report on Form 10-Q for the quarter ended September 30, 1998. 4.5 -- Agreement to furnish copies of unfiled long-term debt Instruments. Incorporated herein by reference to Registrant's transition report on Form 10-K for the six months ended December 31, 1997. 4.9 -- Registration Rights Agreement dated October 22, 1997 as amended by Amendment No. 1 dated December 22, 1997 between Chesapeake Energy Corporation and Charles E. Davidson. Incorporated herein by reference to Exhibit 4.9 and 4.10 to Registrant's registration statement on Form S-4 (No. 333-48735). 4.10 -- Registration Rights Agreement between Chesapeake Energy Corporation and certain shareholders of Hugoton Energy Corporation. Incorporated herein by reference to Registrant's registration statement on Form S-4 (No. 333-48735). 4.11 -- Registration Rights Agreement as of April 22, 1998 among the Registrant and Donaldson, Lufkin & Jenrette Securities Corporation, Morgan Stanley & Co. Incorporated, Bear Stearns & Co. Inc., Lehman Brothers Inc. and J.P. Morgan Securities Inc., with respect to 7% Cumulative Convertible Preferred Stock. Incorporated herein by reference to Exhibit 4.11 to Registrant's quarterly report on Form 10-Q for the quarter ended March 31, 1998. 10.1.1+ -- Registrant's 1992 Incentive Stock Option Plan. Incorporated herein by reference to Exhibit 10.1.1 to Registrant's registration statement on Form S-4 (No. 33-93718). 10.1.2+ -- Registrant's 1992 Nonstatutory Stock Option Plan, as Amended. Incorporated herein by reference to Exhibit 10.1.2 to Registrant's quarterly report on Form 10-Q for the quarter ended December 31, 1996. 10.1.3+ -- Registrant's 1994 Stock Option Plan, as amended. Incorporated herein by reference to Exhibit 10.1.3 to Registrant's quarterly report on Form 10-Q for the quarter ended December 31, 1996. 10.1.4+ -- Registrant's 1996 Stock Option Plan. Incorporated herein by reference to Registrant's Proxy Statement for its 1996 Annual Meeting of Shareholders. 10.1.4.1 -- Amendment to the Chesapeake Energy Corporation 1996 Stock Option Plan. Incorporated herein by reference to Exhibit 10.1.4.1 to Registrant's quarterly report on Form 10-Q for the quarter ended December 31, 1996. 10.2.1+ -- Amended and Restated Employment Agreement dated as of July 1, 1998 between Aubrey K. McClendon and Chesapeake Energy Corporation. Incorporated herein by reference to Exhibit 10.2.1 to Registrant's quarterly report on Form 10-Q for the quarter ended September 30, 1998. 10.2.2+ -- Amended and Restated Employment Agreement dated as of July 1, 1998 between Tom L. Ward and Chesapeake Energy Corporation. Incorporated herein by reference </TABLE>
86 <TABLE> <CAPTION> EXHIBIT NUMBER DESCRIPTION PAGE -------- ----------- ---- <S> <C> <C> to Exhibit 10.2.2 to Registrant's quarterly report on Form 10-Q for the quarter ended September 30, 1998. 10.2.3*+ -- Amended and Restated Employment Agreement dated as of July 1, 1998 between Marcus C. Rowland and Chesapeake Energy Corporation............................................ 88 10.2.4+ -- Employment Agreement dated as of July 1, 1997 between Steven C. Dixon and Chesapeake Energy Corporation. Incorporated herein by reference to Exhibit 10.2.4 to Registrant's quarterly report on Form 10-Q for the quarter ended September 30, 1997. 10.2.5+ -- Employment Agreement dated as of July 1, 1997 between J. Mark Lester and Chesapeake Energy Corporation. Incorporated herein by reference to Exhibit 10.2.5 to Registrant's annual report on Form 10-K for the year ended June 30, 1997. 10.2.6+ -- Employment Agreement dated as of July 1, 1997 between Henry J. Hood and Chesapeake Energy Corporation. Incorporated herein by reference to Exhibit 10.2.6 to Registrant's annual report on Form 10-K for the year ended June 30, 1997. 10.2.7+ -- Employment Agreement dated as of July 1, 1997 between Ronald A. Lefaive and Chesapeake Energy Corporation. Incorporated herein by reference to Exhibit 10.2.7 to Registrant's annual report on Form 10-K for the year ended June 30, 1997. 10.2.8+ -- Employment Agreement dated as of July 1, 1997 between Martha A. Burger and Chesapeake Energy Corporation. Incorporated herein by reference to Exhibit 10.2.8 to Registrant's annual report on Form 10-K for the year ended June 30, 1997. 10.2.9* -- Amendment to Employment Agreements of Steven C. Dixon, J. Mark Lester, Henry J. Hood, Ronald A. Lefaive and Martha A. Burger dated as of July 1, 1997.............................104 10.3+ -- Form of Indemnity Agreement for officers and directors of Registrant and its subsidiaries. Incorporated herein by reference to Exhibit 10.30 to Registrant's Registration statement on Form S-1 (No. 33-55600). 10.4.1* -- Second Amended and Restated Loan Agreement between Aubrey K. McClendon and Chesapeake Energy Marketing, Inc., dated effective December 31, 1998.............................106 10.4.2* -- Second Amended and Restated Loan Agreement between Tom L. Ward and Chesapeake Energy Marketing, Inc., dated effective December 31, 1998...................................121 10.5 -- Rights Agreement dated July 15, 1998 between the Registrant and UMB Bank, N.A., as Rights Agent. Incorporated herein by reference to Exhibit 1 to Registrant's registration statement on Form 8-A filed July 16, 1998. Amendment No. 1 dated September 11, 1998. Incorporated herein by reference to Exhibit 10.3 to Registrant's quarterly report on Form 10-Q for the quarter ended September 30, 1998. 10.9 -- Indemnity and Stock Registration Agreement, as amended by First Amendment (Revised) thereto, dated as of February 12, 1993, and as amended by Second Amendment thereto dated as of October 20, 1995, among Chesapeake Energy Corporation, Chesapeake Operating, Inc., Chesapeake Investments, TLW Investments, Inc., et al. Incorporated herein by reference to Exhibit 10.35 to Registrant's annual report on Form 10-K for the year ended June 30, 1993 and Exhibit </TABLE>
87 <TABLE> <CAPTION> EXHIBIT NUMBER DESCRIPTION PAGE -------- ----------- ---- <S> <C> <C> 10.4.1 to Registrant's Quarterly report on Form 10-Q for the quarter ended December 31, 1995. 10.10 -- Partnership Agreement of Chesapeake Exploration Limited Partnership dated December 27, 1994 between Chesapeake Energy Corporation and Chesapeake Operating, Inc. Incorporated herein by reference to Exhibit 10.10 to Registrant's registration statement on Form S-4 (No. 33-93718). 10.11 -- Amended and Restated Limited Partnership Agreement of Chesapeake Louisiana, L.P. dated June 30, 1997 between Chesapeake Operating, Inc. and Chesapeake Energy Louisiana Corporation. 21* -- Subsidiaries of Registrant....................................136 23.1* -- Consent of PricewaterhouseCoopers LLP.........................137 23.2* -- Consent of Williamson Petroleum Consultants, Inc..............138 23.3* -- Consent of Ryder Scott Company Petroleum Engineers............139 27* -- Financial Data Schedule.......................................140 </TABLE> - ---------- * Filed herewith. + Management contract or compensatory plan or arrangement.