-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, L6oZLgZlja4jAB5KT/QyGH9aua6nJIqc1PiURDZvq57poGzMGT0DrxJrqs5K4nLI TA8OojCjH+2Il94ls+8Wkg== 0000950134-98-001017.txt : 19980212 0000950134-98-001017.hdr.sgml : 19980212 ACCESSION NUMBER: 0000950134-98-001017 CONFORMED SUBMISSION TYPE: 10-K/A PUBLIC DOCUMENT COUNT: 4 CONFORMED PERIOD OF REPORT: 19970630 FILED AS OF DATE: 19980211 SROS: NYSE FILER: COMPANY DATA: COMPANY CONFORMED NAME: CHESAPEAKE ENERGY CORP CENTRAL INDEX KEY: 0000895126 STANDARD INDUSTRIAL CLASSIFICATION: CRUDE PETROLEUM & NATURAL GAS [1311] IRS NUMBER: 731395733 STATE OF INCORPORATION: OK FISCAL YEAR END: 0630 FILING VALUES: FORM TYPE: 10-K/A SEC ACT: SEC FILE NUMBER: 333-24995 FILM NUMBER: 98532363 BUSINESS ADDRESS: STREET 1: 6104 N WESTERN CITY: OKLAHOMA CITY STATE: OK ZIP: 73118 BUSINESS PHONE: 4058488000 MAIL ADDRESS: STREET 1: 6104 NORTH WESTERN AVE CITY: OKLAHOMA CITY STATE: OK ZIP: 73118 10-K/A 1 AMENDMENT NO. 3 TO FORM 10-K ENDING 06-30-97 1 ================================================================================ SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-K/A (AMENDMENT NO. 3) [X] Annual Report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 For the Fiscal Year ended June 30, 1997 [ ] 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: NAME OF EACH EXCHANGE TITLE OF EACH CLASS ON WHICH REGISTERED - --------------------------------------------- --------------------------------------------- Common Stock, par value $.01 New York Stock Exchange 9.125% Senior Notes due 2006 New York Stock Exchange
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. [ ] The aggregate market value of Common Stock held by non-affiliates on October 27, 1997 was $423,923,486. At such date, there were 70,429,017 shares of Common Stock issued and outstanding. DOCUMENTS INCORPORATED BY REFERENCE NONE ================================================================================ 2 PART I ITEM 1. BUSINESS OVERVIEW Chesapeake Energy Corporation ("Chesapeake" or the "Company") is an independent energy company which utilizes advanced drilling and completion technologies to explore for and produce oil and natural gas. The Company has traditionally been among the most active drillers of new wells in the United States. From inception in 1989 through June 30, 1997, Chesapeake drilled and participated in a total of 736 gross (294 net) wells, of which 691 gross (276 net) wells were completed. From its first full fiscal year of operation ended June 30, 1990 to the fiscal year ended June 30, 1997, the Company's estimated proved reserves increased to 403 Bcfe from 11 Bcfe, annual production increased to 79 Bcfe from 0.2 Bcfe, total revenue increased to $280 million from $0.6 million, and total assets increased to $949 million from $8 million. Despite this overall favorable record of growth, in fiscal 1997 the Company incurred a net loss of $183 million primarily as a result of a $236 million impairment of its oil and gas properties. The impairment was the amount by which the Company's capitalized costs of oil and gas properties exceeded the estimated present value of future net revenues from its proved reserves at June 30, 1997. A combination of factors in the fourth quarter of fiscal 1997 caused the impairment. First, exploratory drilling of unevaluated leasehold, primarily in the Louisiana Trend, failed to add significant proved reserves. In addition, oil and gas price declines, higher drilling and completion costs and lower than expected results from developmental drilling and production eliminated previously established proved reserves. See Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations -- Results of Operations -- Impairment of Oil and Gas Properties. In response to the fiscal 1997 loss, Chesapeake has revised its fiscal 1998 business strategy. These revisions include slowing its exploration pace in the Louisiana Austin Chalk Trend ("Louisiana Trend") and concentrating its Louisiana Trend drilling activities in Masters Creek; utilizing more extensive use of 3-D seismic prior to conducting drilling operations; reducing the acquisition of additional unproven leasehold; and selectively acquiring proved reserves as a complement to its primary strategy of developing reserves through the drillbit. This strategy will likely have the effect of reducing the Company's anticipated production growth rate from exploration and development drilling. The Company's failure to increase its reserves in fiscal 1997 while incurring $465 million of development, exploration and acquisition costs (including capitalized internal costs) increases its need to add reserves in order to replace production and allow growth through acquisition or drilling. The Company has reduced its fiscal 1998 capital expenditure budget to $225-$275 million and plans to pursue acquisitions of oil and gas properties. The failure to add reserves economically through this new strategy would adversely affect the Company's financial position, results of operations, and could subsequently impede the Company's ability to acquire properties using its stock. Reference is made to the "Glossary" that appears at the end of this Item 1 for definitions of certain terms used in this Form 10-K. DESCRIPTION OF BUSINESS Since its inception, Chesapeake's primary business strategy has been growth through the drillbit. Using this strategy, the Company has expanded its reserves and production through the acquisition and subsequent development of large blocks of acreage. From inception through fiscal 1994, the Company concentrated its undeveloped leasehold acquisitions and associated drilling in the Giddings Field of southern Texas and the Golden Trend Field of southern Oklahoma. Beginning in fiscal 1995, Chesapeake initiated development of new project areas that were either extensions of the Company's historical focus in the Giddings and Golden Trend Fields or new areas which the Company believed had similar characteristics. These additional project areas included the Knox Field in southern Oklahoma, the Sholem Alechem Field in southern Oklahoma, the Louisiana Trend, the Arkoma Basin in southeastern Oklahoma, the Lovington area in eastern New Mexico, and the Williston Basin in 1 3 eastern Montana and western North Dakota. In fiscal 1997, the Company also added a large exploration project in Wharton County, Texas. The Company invested approximately $179 million, including capitalized interest, to acquire over one million acres of leasehold in the Louisiana Trend from fiscal 1995 through fiscal 1997, and an additional $163 million in drilling to explore this leasehold in fiscal 1996 and 1997. Of the Company's six project areas identified in the Louisiana Trend, only in the Masters Creek area has the Company consistently found commercial quantities of oil and gas in the Austin Chalk formation. As of June 30, 1997 the Company owned over two million net undeveloped acres in its leasehold inventory. The Company expects that its inventory of proved and unproved drilling locations will continue to be an important source of new reserves, production and cash flow over the next few years. The Louisiana Trend continues to be a key element of this existing inventory. The following table sets forth the Company's estimated proved reserves (net of interests of other working and royalty interest owners and others entitled to share in production), estimated capital expenditures and the number of potential net drilling locations required to develop the Company's proved undeveloped reserves at June 30, 1997:
ESTIMATED CAPITAL EXPENDITURES PERCENT REQUIRED TO NUMBER OF OF DEVELOP NET PROVED OIL GAS GAS PROVED PUD'S UNDEVELOPED AREAS (MBBL) (MMCF) EQUIVALENT RESERVES ($ IN 000'S) LOCATIONS ----- ------ ------- ---------- -------- ------------ ----------- Louisiana Trend............. 7,673 36,418 82,456 20% 54,529 16 Oklahoma.................... 4,483 123,393 150,291 37% 48,741 37 Giddings.................... 1,990 128,992 140,932 35% 33,825 26 Williston Basin............. 872 551 5,783 2% 2,669 3 Other Areas................. 2,355 9,412 23,542 6% 7,204 9 ------ ------- ------- --- ------- -- Total............. 17,373 298,766 403,004 100% 146,968 91 ====== ======= ======= === ======= ==
PRIMARY OPERATING AREAS The Company's activities are concentrated in three primary operating areas: (i) the Louisiana Trend, (ii) the Knox, Sholem Alechem, Golden Trend, and Arkoma Basin areas of Oklahoma, and (iii) the Navasota River and Independence areas of the downdip Giddings Field in southern Texas. Louisiana Austin Chalk Trend. The Louisiana Trend is the newest of the Company's three primary operating areas and is budgeted to represent approximately 50% of the Company's exploration and development activities in fiscal 1998. In late 1994, Occidental Petroleum Corporation ("Occidental") completed a horizontal Austin Chalk discovery well in the Masters Creek area of central Louisiana. Occidental's well was drilled 200 miles east of the Company's activity in the downdip Giddings Field and 60 miles east of the nearest previous commercial multi-well horizontal Austin Chalk production in the Brookeland Field of southeast Texas. Following the announcement of Occidental's discovery well, the Company extensively reviewed and analyzed vertical drilling reports, electric logs, mud logs, seismic data and vertical Austin Chalk production records to arrive at a geological conclusion that the Austin Chalk could be productive across a large portion of central and southeastern Louisiana. Accordingly, and in competition with Union Pacific Resources Company, Sonat, Inc., Occidental, Amoco Production Company, Helmerich & Payne, Inc., Belco Oil & Gas Corporation and others, Chesapeake invested approximately $179 million from fiscal 1995 through fiscal 1997 to acquire over one million acres of leasehold in the Louisiana Trend. Beginning in fiscal 1996 and accelerating substantially by the end of fiscal 1997, Chesapeake expended an additional $163 million to initiate drilling efforts on 56 gross (34 net) wells to evaluate this leasehold position. 2 4 Leasehold that is classified as unevaluated is not subject to amortization or to the periodic ceiling test evaluations required under full cost accounting. As leasehold is evaluated through exploration efforts including drilling, it becomes subject to amortization and the ceiling test evaluation. At June 30, 1997, the Company had $342 million of oil and gas assets in the Louisiana Trend, of which $275.2 million was evaluated and therefore subject to the ceiling test. From December 1996 through April 1997, the Company initiated drilling efforts on 15 new operated wells in the Louisiana Trend. Between April 1997 and July 1997, the Company completed operations on ten exploratory wells in areas of the Louisiana Trend outside of Masters Creek. Of these wells, one was completed on April 15, 1997, one on May 3, 1997 and eight were completed after June 1, 1997. Based upon the results from these wells, which primarily became known to the Company in late June 1997, the Company made the determination that a significant amount of leasehold previously classified as unevaluated had become evaluated. This determination, in combination with development in the Masters Creek area, resulted in a transfer of approximately $91 million of previously unevaluated leasehold costs to the full cost pool which, and in conjunction with disappointing drilling results and the related costs thereof and lower oil and gas prices, was the primary cause of the full cost ceiling writedown. See "Results of Operations -- Impairment of Oil and Gas Properties" in Item 7, which identifies the components of the impairment. The Company believes that some portion of the Louisiana Trend outside of the Masters Creek area, and specifically certain areas of East Baton Rouge and Point Coupee Parishes that are prospective for the Tuscaloosa formation, may ultimately be successfully exploited. It is the Company's intent to focus its Louisiana drilling in fiscal 1998 primarily in the Masters Creek area and to allow others to lead the continued exploration of areas outside of Masters Creek. The Masters Creek area, where as of September 30, 1997 the Company and the Company's competitors have completed approximately 36 out of 40 wells as commercially productive with approximately 25 additional wells currently drilling, has generally been much more successful than the other areas within the Louisiana Trend. As of September 30, 1997, the Company had eight rigs operating in this area and is participating in more than 10 non-operated wells. For fiscal 1998, the Company has budgeted $125 million to drill approximately 25 net wells targeting the Austin Chalk formation and $13 million to drill two net wells targeting the Tuscaloosa formation. These planned expenditures, in combination with anticipated seismic costs, represent approximately 40% of the Company's planned exploration and development capital expenditures for all areas. The Company, while it has significantly reduced its budget for the Louisiana Trend from prior expectations, continues to believe there are significant economic drilling opportunities in the Masters Creek area. Additionally, the Company has yet to complete the various 3-D seismic programs necessary to fully evaluate leasehold purchased for potential Tuscaloosa production and to support the drilling of the Tuscaloosa wells planned. There can be no assurance that the Louisiana Trend drilling will yield substantial economic returns. Failure of the wells to produce significant quantities of economically attractive reserves and production could have a material adverse impact on the Company's future financial condition and results of operations, and could result in a future ceiling limitation under rules of the Securities and Exchange Commission. Oklahoma. Chesapeake's largest concentration of proved reserves is located in Oklahoma and is comprised of the Knox, Golden Trend, Sholem Alechem, and Arkoma Basin areas. These areas are generally characterized by relatively long lived production from multiple producing zones. The Company has conducted and is evaluating 3-D seismic surveys over significant portions of its Oklahoma leasehold in an effort to enhance its future drilling efforts. In fiscal 1997, the Company invested approximately $68 million to drill 51 gross (32 net) wells in Oklahoma. The Company has budgeted approximately $28 million in fiscal 1998 to drill 36 gross (21 net) wells in Oklahoma. Giddings Field. Chesapeake's second largest concentration of proved reserves and its highest concentration of present value is located in the Giddings Field, Texas. The primary producing formation in Giddings is the Austin Chalk formation, a fractured carbonate reservoir found at depths ranging from 7,000 feet to 3 5 17,000 feet along a 15,000 square mile trend in southeastern Texas and central Louisiana. Chesapeake has concentrated its drilling efforts in the gas prone downdip portion of the Giddings Field, where the Austin Chalk is located at depths below 11,000 feet. The Giddings Field contributed approximately 44.6 Bcfe, or 57% of the Company's total production in fiscal 1997, compared to 47.2 Bcfe or 78% in 1996. The Company expects production to decline in this relatively mature area in fiscal 1998. In fiscal 1997, the Company invested approximately $57 million to drill 36 gross (19 net) wells in Giddings. The Company has budgeted approximately $17 million to drill 18 gross (eight net) wells in Giddings during fiscal 1998. OTHER OPERATING AREAS Williston Basin. During fiscal 1996, Chesapeake began acquiring leasehold in the Williston Basin, located in eastern Montana and western North Dakota, and as of June 30, 1997 owned more than 700,000 gross (500,000 net) acres. During fiscal 1997, the Company drilled and successfully completed four vertical wells targeting the Red River formation on the northern portion of its leasehold. (A "successfully completed" well is a commercial well, i.e. one that generates proceeds from the sale of production in excess of production expenses and related production taxes.) On the southern portion of its leasehold, the Company was unsuccessful in an attempt to establish horizontally drilled Red River production. Also during fiscal 1997, the Company tested a third large area of its Williston acreage with a successful horizontal Nesson well. Currently, the Company is focusing its Williston efforts on continuing to develop the Nesson formation. The Company has budgeted $6 million to drill six gross and net wells during fiscal 1998 in the Williston Basin. Permian Basin. In fiscal 1995, the Company initiated 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 algal reef buildups 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 fiscal 1997 the Company initiated eight wells in this project area, seven of which were successfully completed. The Company has budgeted approximately $14 million to drill 14 gross and net wells in this area during fiscal 1998. Wharton County, Texas. During fiscal 1997 the Company acquired approximately 25,000 net acres at a cost of approximately $29 million 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 intends to participate with a 55% interest in a 55,000 acre 3-D seismic program with Coastal Oil & Gas Corporation, Seagull Energy Corporation and other industry partners during fiscal 1998 to delineate potential future drillsites in the vicinity of Coastal's recently completed Zeidman Trust #2 well. STRATEGIC INVESTMENTS During fiscal 1997, the Company invested in a number of oil and gas related businesses and projects. The most significant of these was the Company's May 1997 initial investment in Bayard Drilling Technologies, Inc. ("Bayard"), consisting of an $18 million subordinated loan and the purchase of $7 million of common stock. In August 1997, the Company agreed to invest up to an additional $9 million and convert certain options, warrants and note amounts that will facilitate a potential initial public offering by Bayard. On August 27, 1997 Bayard filed a registration statement for an initial public offering of its common stock. Chesapeake, subsequent to the completion of the transaction noted above, will own 4,194,000 shares of Bayard common stock (30.4% of the common stock outstanding) and anticipates selling substantially all of its ownership in Bayard in the IPO (assuming the over-allotment option is exercised) and receiving repayment of the subordinated loan. If successful, assuming the sale of all of the Company's Bayard stock and based on the initial filing price of Bayard at $15 per share, the Company would receive total proceeds of approximately $74 million (net of offering costs) and realize a pre-tax gain of approximately $40 million. No assurance can be given, however, that Bayard will successfully complete the initial public offering of its common stock, at what price, or that the net proceeds or pre-tax gain discussed above will be realized by the Company. 4 6 Also during fiscal 1997 the Company invested approximately $12 million for its 50% interest in the Louisiana Austin Chalk Gathering System (a joint venture with Mitchell Energy and Development Corporation) and $5 million for its 15.5% interest in the Masters Creek Gas Plant (a joint venture among Union Pacific, Sonat, Helmerich & Payne, and OXY). The Company has budgeted $4 million for its share of the expansion of these assets during fiscal 1998. The Company considers these mid-stream gas assets to be non-core and therefore may seek to sell them in fiscal 1998. 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.
YEAR ENDED JUNE 30, ----------------------------------------------- 1997 1996 1995 ------------- ------------- ------------- GROSS NET GROSS NET GROSS NET ----- ---- ----- ---- ----- ---- Development: Productive.................................. 90 55.0 111 49.5 133 42.6 Non-productive.............................. 2 .2 4 1.6 5 2.8 -- ---- --- ---- --- ---- Total....................................... 92 55.2 115 51.1 138 45.4 == ==== === ==== === ==== Exploratory: Productive.................................. 71 46.1 29 16.5 11 5.3 Non-productive.............................. 8 5.7 4 1.4 1 .7 -- ---- --- ---- --- ---- Total....................................... 79 51.8 33 17.9 12 6.0 == ==== === ==== === ====
At June 30, 1997, the Company was drilling 25 gross (19.8 net) exploratory or development wells, of which 11 gross (8.1 net) wells have been successfully completed and 12 gross (9.7 net) wells are still being drilled or tested. The Company was also participating with minority interests in 13 non-operated wells being drilled at that date. 1998 3-D SEISMIC SURVEY PROGRAM The Company has increased its emphasis on the use of 3-D seismic surveys to evaluate and define potential drilling locations. The use of 3-D, compared to 2-D, seismic technology is desirable in many situations because it (a) allows more precise imaging of structural and stratigraphic features under the earth, (b) allows more precise well placement minimizing dry hole risk while maximizing the potential oil and gas recovery, and (c) eliminates certain wells from being drilled into reservoirs too small to be economic. During fiscal 1998 the Company has budgeted approximately $25 million for seismic acquisition and evaluation and intends to conduct or participate in seismic surveys covering the following areas:
APPROXIMATE GROSS ACREAGE AREA TARGET FORMATIONS - ------------- ------------------ ------------------------------- 85,000 Baton Rouge, LA Tuscaloosa; Austin Chalk 55,000 Wharton County, TX Deep Wilcox; Frio and Yegua 35,000 Golden Trend, OK Multiple sand and carbonates 90,000 Lovington, NM Strawn 50,000 Williston, MT Red River 50,000 Allen Parish, LA Wilcox; Austin Chalk
WELL DATA At June 30, 1997, the Company had interests in approximately 593 (270.1 net) producing wells, of which 129 (55.4 net) were classified as primarily oil producing wells and 464 (214.7 net) were classified as primarily gas producing wells. 5 7 VOLUMES, REVENUE, PRICES AND PRODUCTION COSTS The following table sets forth certain information regarding the production volumes, revenue, average prices received and average production costs associated with the Company's sale of oil and gas for the periods indicated:
YEAR ENDED JUNE 30, ------------------------------- 1997 1996 1995 -------- -------- ------- NET PRODUCTION: Oil (MBbl)...................................... 2,770 1,413 1,139 Gas (MMcf)...................................... 62,005 51,710 25,114 Gas equivalent (MMcfe).......................... 78,625 60,190 31,947 OIL AND GAS SALES ($ IN 000'S): Oil............................................. $ 57,974 $ 25,224 $19,784 Gas............................................. 134,946 85,625 37,199 -------- -------- ------- Total oil and gas sales................. $192,920 $110,849 $56,983 ======== ======== ======= AVERAGE SALES PRICE: Oil ($ per Bbl)................................. $ 20.93 $ 17.85 $ 17.36 Gas ($ per Mcf)................................. $ 2.18 $ 1.66 $ 1.48 Gas equivalent ($ per Mcfe)..................... $ 2.45 $ 1.84 $ 1.78 OIL AND GAS COSTS ($ PER MCFE): Production expenses and taxes................... $ .19 $ .14 $ .13 General and administrative...................... $ .11 $ .08 $ .11 Depreciation, depletion and amortization of oil and gas properties........................... $ 1.31 $ .85 $ .80
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:
YEAR ENDED JUNE 30, -------------------------------- 1997 1996 1995 -------- -------- -------- ($ IN THOUSANDS) Development costs................................ $187,736 $138,188 $ 78,679 Exploration costs................................ 136,473 39,410 14,129 Acquisition costs: Unproved properties............................ 140,348 138,188 24,437 Proved properties.............................. -- 24,560 -- Capitalized internal costs....................... 3,905 1,699 586 Proceeds from sale of leasehold, equipment and other.......................................... (3,095) (6,167) (11,953) -------- -------- -------- Total.................................. $465,367 $335,878 $105,878 ======== ======== ========
ACREAGE The following table sets forth as of June 30, 1997 the gross and net acres of both developed and undeveloped oil and gas leases which the Company holds. "Gross" acres are the total number of acres in 6 8 which the Company owns a working interest. "Net" acres refer to gross acres multiplied by the Company's fractional working interest. Acreage numbers are stated in thousands.
TOTAL DEVELOPED DEVELOPED UNDEVELOPED AND UNDEVELOPED ------------ -------------------- ---------------- GROSS NET GROSS NET GROSS NET ----- --- -------- -------- ------ ------ Louisiana Trend.............. 41 40 1,154(1) 1,003(1) 1,195 1,043 Oklahoma..................... 85 34 297 134 382 168 Giddings..................... 121 58 186 133 307 191 Williston Basin.............. 3 2 732 498 735 500 Other Areas.................. 27 19 331 250 358 269 --- --- -------- -------- ----- ----- Total.............. 277 153 2,700 2,018 2,977 2,171 === === ======== ======== ===== =====
- --------------- (1) Does not include options for additional leasehold held by the Company but not yet exercised. MARKETING The Company's oil production is sold under market sensitive or spot price contracts. The Company's natural gas production is sold to purchasers under varying percentage-of-proceeds and percentage-of-index contracts. By the terms of these contracts, the Company receives a percentage of the resale price received by the purchaser for sales of residue gas and natural gas liquids recovered after gathering and processing the Company's gas. The residue gas and natural gas liquids sold by these purchasers are sold primarily based on spot market prices. The revenue received by the Company from the sale of natural gas liquids is included in natural gas sales. During fiscal 1997, the following three customers individually accounted for 10% or more of the Company's total oil and gas sales:
PERCENT OF OIL AMOUNT AND GAS ($ IN THOUSANDS) SALES ---------------- -------------- Aquila Southwest Pipeline Corporation.................... 53,885 28% Koch Oil Company......................................... 29,580 15% GPM Gas Corporation...................................... 27,682 14%
Management believes that the loss of any 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 the geographical areas in which the Company is active. 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 (1) 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, (2) 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, (3) 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 (4) basis protection swaps, which are arrangements that guarantee the price differential of oil or gas from a specified delivery point or points. Results from 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 hedging transactions related to the Company's oil and gas production volumes or CEMI physical purchase or sale commitments. 7 9 As of June 30, 1997, the Company had the following oil swap arrangements for periods after June 1997:
NYMEX-INDEX STRIKE PRICE MONTH VOLUME (BBLS) (PER BBL) ----- -------------- ------------ July 1997................................................. 31,000 $ 18.60 August 1997............................................... 31,000 $ 18.43 September 1997............................................ 30,000 $ 18.30 October 1997.............................................. 31,000 $ 18.19 November 1997............................................. 30,000 $ 18.13 December 1997............................................. 31,000 $ 18.08 January through June 1998................................. 724,000 $ 19.82
The Company entered into oil swap arrangements to cancel the effect of the above swaps for the months of August through December at an average price of $21.07 per Bbl. As of June 30, 1997, the Company had the following gas swap arrangements for periods after June 1997:
HOUSTON SHIP CHANNEL INDEX STRIKE PRICE MONTHS VOLUME (MMBTU) (PER MMBTU) ------ -------------- -------------------- July 1997......................................... 1,240,000 $2.313 August 1997....................................... 1,240,000 $2.301 September 1997.................................... 1,200,000 $2.285 October 1997...................................... 1,240,000 $2.300
The Company entered into gas swap arrangements to cancel the effect of the swaps for the months of July through October at an average price of $2.133 per MMBtu. The Company entered into a curve lock for approximately 4.9 Bcf of gas which allows the Company the option to hedge April 1999 through November 1999 gas based upon a negative $0.285 differential to December 1998 gas any time between the strike date and December 1998. A curve lock is a commodity swap arrangement that establishes, or hedges, a price differential between one commodity contract period and another. In markets where the forward curve is typically negatively sloped (prompt prices exceed deferred prices), an upward sloping price curve allows hedgers to lock in a deferred forward sale at a higher premium to a more prompt swap by a curve lock. For example, in the crude oil market, which typically has a negatively sloped price curve, it may be possible for a hedger to lock in a price relationship in which his deferred crude oil is sold at a premium to a prompter swap, because the price curve is upwardly sloping in the future. The expectation of the hedger is that either the market will return to its historically negatively sloped price curve, or that prices generally will increase and the curve lock swap will allow him to realize a premium price for the deferred versus the more prompt price. The Company estimates that had all of the crude oil and natural gas swap agreements in effect for production periods beginning July 1, 1997 terminated on June 30, 1997, based on the closing prices for NYMEX futures contracts as of that date, the Company would have paid the various counterparties a net amount of approximately $185,000, which would have represented the "fair value" at that date. These agreements were not terminated. Periodically, CEMI 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. 8 10 COMPETITION The oil and gas industry is highly competitive. The Company competes with major and independent oil and gas companies for the acquisition of leasehold, proven oil and gas properties, as well as for the services and labor required to explore, develop and produce such properties. Many of these competitors have financial, technical and other resources substantially greater than those of the Company. SEASONAL NATURE OF BUSINESS Historically the demand for natural gas decreases during the summer months and increases during the winter months. However, pipelines, utilities, local distribution companies and industrial users may more effectively utilize natural gas storage capacity by purchasing some of the winter load in the summer at reduced prices. 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 9 11 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) 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 10 12 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 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 recently 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 it will be able to obtain, or be included under, such permits, where necessary, with minor modifications to existing facilities and operations that would not 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 oil-field 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 (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, little investigation of record title is made at the time of acquisition (other than a preliminary review of local 11 13 records). Drilling title opinions are always 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 drilling activities involve greater risk of mechanical problems than conventional vertical drilling operations. 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 362 full-time employees as of June 30, 1997. No employees are represented by organized labor unions. The Company considers its employee relations to be good. FACILITIES The Company owns 12 buildings totaling approximately 80,000 square feet in an office complex in Oklahoma City that comprise its headquarters' offices and also owns a field office in Lindsay, Oklahoma. The Company leases field office space in College Station and Navasota, Texas, Lafayette, Louisiana and Calgary, Canada. REINCORPORATION On December 31, 1996, the Company changed its state of incorporation from Delaware to Oklahoma by the merger of Chesapeake Energy Corporation, a Delaware corporation, with and into its newly formed wholly-owned subsidiary, Chesapeake Oklahoma Corporation. The surviving corporation changed its name to Chesapeake Energy Corporation. Each outstanding share of Common Stock, par value $.10, of the merged Delaware corporation was converted into one share of Common Stock, par value $.01, of the surviving corporation. As a result of the merger, the surviving corporation succeeded to all of the assets and is responsible for all of the liabilities of the merged Delaware corporation. On matters of corporate governance, the rights of the Company's security holders are now governed by Oklahoma law, which is similar to the corporate law of Delaware. 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. 12 14 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. Formation. A succession of sedimentary beds that were deposited under the same general geologic conditions. 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. 13 15 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. 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. 14 16 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS OVERVIEW Chesapeake's revenue, operating cash flow (exclusive of changes in working capital) and production reached record levels in fiscal 1997. However, significant expenditures for acreage acquisition and drilling costs followed by unfavorable exploration and production results, together with increases in drilling and equipment costs and declines in oil and gas prices as of June 30, 1997, resulted in downward revisions in estimates of the Company's proved oil and gas reserves and the present value of the estimated future net revenues from these reserves. Such excess caused the Company to record a $236 million asset writedown during the fourth quarter of the year and caused the Company to report a net loss of $183 million for the year. Chesapeake's strategy during fiscal 1997, and particularly in the third and fourth quarters of the year, was to identify the potential of the various areas of the Louisiana Trend by exploratory drilling. In several large areas outside of the Masters Creek portion of the Louisiana Trend, this exploration program was unsuccessful. In these areas significant leasehold and drilling costs were added to the evaluated oil and gas property pool while insignificant quantities of oil and gas reserves were added to the Company's proved reserve base. During fiscal 1997, the Company participated in 171 gross (107 net) wells, of which 129 wells were operated by the Company. A summary of the Company's drilling activities and capital expenditures by primary operating area is as follows ($ in thousands):
CAPITAL EXPENDITURES GROSS NET --------------------------------- WELLS WELLS DRILLING LEASEHOLD TOTAL ----- ----- -------- --------- -------- Louisiana Trend.................... 50 28.7 $141,581 $ 81,287 $222,868 Oklahoma........................... 51 31.8 67,689 4,556 72,245 Texas.............................. 51 31.7 64,514 41,112 105,626 Other.............................. 19 14.8 51,237 13,391 64,628 Total.................... 171 107.0 $325,021 $140,346 $465,367
The Company's proved reserves decreased 5% to an estimated 403 Bcfe at June 30, 1997, down 22 Bcfe from 425 Bcfe of estimated proved reserves at June 30, 1996 (see Note 11 of Notes to Consolidated Financial Statements in Item 8 and "Results of Operations -- Impairment of Oil and Gas Properties"). Due to the 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, there can be no assurance that the Company's estimated proved reserves will not decrease in the future. The Company's business strategy in fiscal 1997 continued to emphasize the acquisition of large prospective leasehold positions which potentially provide a multi-year inventory of drilling locations. As of June 30, 1997, the Company had approximately 277,000 gross acres of developed leasehold and 2.7 million gross acres of undeveloped leasehold. The fiscal 1997 drilling program, particularly in Louisiana, consisted of more exploratory drilling than in previous years. The Company's strategy for fiscal 1998 is to reduce its capital expenditure program to approximately $225-$275 million, concentrate its Louisiana Trend drilling activities in Masters Creek, utilize more 3-D seismic prior to conducting drilling operations, reduce the acquisition of additional unproven leasehold, and selectively acquire proved reserves. This strategy will likely have the effect of reducing the Company's anticipated production growth rate from exploration and development drilling. To assist the Company in reducing exploratory risks and increasing economic returns the Company has increased its use of 3-D seismic. The Company has conducted, participated in, or is actively pursuing more than 25 3-D seismic programs to more fully evaluate the Company's acreage inventory. 15 17 The following table sets forth certain operating data of the Company for the periods presented:
YEAR ENDED JUNE 30, ----------------------------- 1997 1996 1995 -------- -------- ------- NET PRODUCTION DATA: Oil (MBbl)................................................ 2,770 1,413 1,139 Gas (MMcf)................................................ 62,005 51,710 25,114 Gas equivalent (MMcfe).................................... 78,625 60,190 31,947 OIL AND GAS SALES ($ in 000's): Oil....................................................... $ 57,974 $ 25,224 $19,784 Gas....................................................... 134,946 85,625 37,199 -------- -------- ------- Total oil and gas sales........................... $192,920 $110,849 $56,983 ======== ======== ======= AVERAGE SALES PRICE: Oil ($ per Bbl)........................................... $ 20.93 $ 17.85 $ 17.36 Gas ($ per Mcf)........................................... $ 2.18 $ 1.66 $ 1.48 Gas equivalent ($ per Mcfe)............................... $ 2.45 $ 1.84 $ 1.78 OIL AND GAS COSTS ($ per Mcfe): Production expenses and taxes............................. $ .19 $ .14 $ .13 General and administrative................................ $ .11 $ .08 $ .11 Depreciation, depletion and amortization.................. $ 1.31 $ .85 $ .80 NET WELLS DRILLED: Horizontal wells.......................................... 75.7 42.0 28.5 Vertical wells............................................ 31.3 27.0 23.0 NET WELLS AT END OF PERIOD.................................. 270.1 187.0 96.4
The Company completed an offering of 8,972,000 shares of common stock in December 1996 resulting in net proceeds to the Company of approximately $288.1 million. Additionally, the Company issued $300 million in Senior Notes in March 1997. The Company used the net proceeds from these offerings, along with cash flow from operations, to fund its net capital expenditures of $524 million, repay all amounts outstanding under its commercial bank credit facilities, and retire $47.5 million of Senior Notes. RESULTS OF OPERATIONS General. For the fiscal year ended June 30, 1997, the Company realized a net loss of $183.4 million, or a loss of $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, and net income of $11.7 million, or $0.21 per common share, on total revenues of $67.3 million in fiscal 1995. The loss in fiscal 1997 as compared to significantly higher earnings in fiscal 1996 and fiscal 1995 was largely the result of a $236 million asset writedown recorded in the fourth quarter under the full cost method of accounting. (See "Results of Operations -- 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 and 238% from the fiscal 1995 amount of $57 million. 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, and 31.9 Bcfe produced in fiscal 1995 at a weighted average price of $1.78 per Mcfe. This represents production growth of 31% for fiscal 1997 compared to fiscal 1996 and 146% compared to fiscal 1995. 16 18 The following table shows the Company's production by major field area for fiscal 1997 and fiscal 1996:
FOR THE YEAR ENDED JUNE 30, ---------------------------------------- 1997 1996 ------------------ ------------------ PRODUCTION PRODUCTION ------------------ ------------------ (MMCFE) PERCENT (MMCFE) PERCENT ------- ------- ------- ------- Texas........................................ 47,398 61% 49,347 82% Oklahoma..................................... 17,370 22 10,420 17 Louisiana Trend.............................. 12,785 16 69 -- All Other Fields............................. 1,072 1 354 1 ------ --- ------ --- Total Production............................. 78,625 100% 60,190 100% ====== === ====== ===
The Company's 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 and $17.36 in fiscal 1995. 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. Gas prices in fiscal 1995 averaged $1.48 per Mcf. 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, $5.9 million, and none in fiscal 1997, 1996 and 1995, respectively. Oil and Gas Marketing Sales. In December 1995, the Company entered into the oil and gas marketing business by establishing a subsidiary to provide primarily 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 the 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. There were no comparable marketing activities in fiscal 1995. 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 is being amortized to income over the estimated useful lives of the Peak assets. The Company's investment in Peak is accounted for using the equity method, and resulted in $0.5 million of income being included in Interest and other revenues in fiscal 1997. Revenues from oil and gas service operations were $6.3 million in fiscal 1996, down 28% from $8.8 million in fiscal 1995. The related costs and expenses of these operations were $4.9 million and $7.7 million for the two years ended June 30, 1996 and 1995 respectively. The gross profit margin of 22% in fiscal 1996 was up from the 12% margin in fiscal 1995. The gross profit margin derived from these operations is 17 19 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. Interest and Other. Interest and other revenues for fiscal 1997 were $11.2 million which compares to $3.8 million in fiscal 1996 and $1.5 million in fiscal 1995. 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. During 1995, the Company did not incur any such gains on sale of assets or basis losses. Production Expenses and Taxes. Production expenses and taxes, which include lifting costs and production and excise taxes, increased to $15.1 million in fiscal 1997, as compared to $8.3 million in fiscal 1996 and $4.3 million in fiscal 1995. These increases on a year-to-year basis were primarily the result of increased production. On an Mcfe production unit basis, production expenses and taxes increased to $0.19 per Mcfe as compared to $0.14 per Mcfe in fiscal 1996 and $0.13 per Mcfe in fiscal 1995. During fiscal 1996 and 1995, a high proportion of the Company's production was from the Giddings Field, much of which qualified for Texas severance tax exemptions. The Company expects that operating costs per Mcfe will continue to increase in fiscal 1998 based on the Company's expected production mix and drilling activities in oil prone areas which generally have higher operating costs than gas prone areas and because a higher percentage of the Company's production will not qualify for severance tax exemptions as compared to the past. 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. To the extent that capitalized costs of oil and gas properties, net of accumulated depreciation, depletion and amortization and related deferred income taxes, exceed the discounted future net revenues of proved oil and gas properties, such excess costs are charged to operations. Prior to January 1997, the Company 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 ten 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 in late June 1997, 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. Oil and gas prices 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 18 20 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 estimated discounted future net revenues from its proved reserves, and giving effect to fourth quarter 1997 drilling and production results, oil and gas prices, higher drilling and completion costs, and additional leasehold acquisition costs and delay rentals incurred in areas subsequently determined to have less reserve potential than had previously been estimated. After considering all of these factors, management estimated that at June 30, 1997 it would have capitalized costs of oil and gas properties which would exceed its full cost ceiling by approximately $150 million to $200 million and on June 27, 1997, 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 or fiscal 1995. Oil and Gas Depreciation, Depletion and Amortization. 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, and $77.9 million higher than fiscal 1995's expense of $25.4 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 and $0.80 in fiscal 1995. The Company's DD&A rate in the future will be a function of the results of future acquisition, exploration, development and production results, but the Company's rate is expected to trend upward in fiscal 1998 based on projected higher finding costs for the Louisiana Trend and higher drilling, completing, and equipping expenses throughout the oil and gas industry. Depreciation and Amortization of Other Assets. Depreciation and amortization ("D&A") of other assets increased to $3.8 million in fiscal 1997, compared to $3.2 million in fiscal 1996, and $1.8 million in fiscal 1995. 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. The Company anticipates an increase in D&A in fiscal 1998 as a result of a full year of debt issuance cost amortization on the Senior Notes issued in March 1997 and higher building depreciation expense on the Company's corporate offices. 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 $8.8 million in fiscal 1997, up 83% from $4.8 million in fiscal 1996, and up from $3.6 million in fiscal 1995. The increases in fiscal 1997 as compared to fiscal 1996 and 1995 result primarily from 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, as compared to $1.7 million in 1996 and $0.6 million in 1995. The Company anticipates that G&A costs for fiscal 1998 will continue to increase as the result of wage inflation in the oil and gas industry and legal fees associated with the UPRC and shareholder litigation. Interest and Other. Interest and other expense increased to $18.6 million in fiscal 1997 as compared to $13.7 million in 1996 and $6.6 million in fiscal 1995. Interest expense in the fourth quarter of fiscal 1997 was $8.7 million, reflecting the issuance of the 7.875% Senior Notes and the 8.5% Senior Notes in March 1997. In addition to the interest expense reported, the Company capitalized $12.9 million of interest during fiscal 1997, as compared to $6.4 million capitalized in fiscal 1996 and $1.6 million in fiscal 1995. Interest expense will 19 21 increase significantly in fiscal 1998 as compared to fiscal 1997 as a result of the $300 million Senior Notes issued in March 1997 and reduced levels of capitalized interest expected in fiscal 1998. 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, as compared to income tax expense of $12.9 million in 1996 and $6.3 million in 1995. All of the income tax expense in 1996 and 1995 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 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 $64.1 million has been 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 and $1.2 million in fiscal 1995. The Company does not expect to record any net income tax expense in fiscal 1998 based on information available at this time. Hedging. Periodically the Company utilizes hedging strategies to hedge the price of a portion of its future oil and gas production. These strategies include (1) 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, (2) 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, (3) 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 (4) basis protection swaps. Results from hedging transactions are reflected in oil and gas sales to the extent related to the Company's oil and gas production. The Company has not entered into hedging transactions unrelated to the Company's oil and gas production or physical purchase or sale commitments. As of June 30, 1997, the Company had the following oil swap arrangements for periods after June 1997:
NYMEX-INDEX STRIKE PRICE MONTH VOLUME (BBLS) (PER BBL) ----- ------------- ------------ July 1997................................................ 31,000 $ 18.60 August 1997.............................................. 31,000 $ 18.43 September 1997........................................... 30,000 $ 18.30 October 1997............................................. 31,000 $ 18.19 November 1997............................................ 30,000 $ 18.13 December 1997............................................ 31,000 $ 18.08 January through June 1998................................ 724,000 $ 19.82
The Company entered into oil swap arrangements to cancel the effect of the swaps for the months of August through December at an average price of $21.07 per Bbl. 20 22 As of June 30, 1997, the Company had the following gas swap arrangements for periods after June 1997:
HOUSTON SHIP CHANNEL INDEX STRIKE PRICE MONTH VOLUME (MMBTU) (PER BBL) ----- -------------- -------------------- July 1997........................................ 1,240,000 $2.313 August 1997...................................... 1,240,000 $2.301 September 1997................................... 1,200,000 $2.285 October 1997..................................... 1,240,000 $2.300
The Company had entered into gas swap arrangements to cancel the effect of the swaps for the months of July through October at an average price of $2.133 per MMBtu. The Company has entered into a curve lock for 4.9 Bcf of gas which allows the Company the option to hedge April 1999 through November 1999 gas based upon a negative $0.285 differential to December 1998 gas any time between the strike date and December 1998. Gains or losses on the crude oil and natural gas hedging transactions are recognized as price adjustments in the month of related production. The Company estimates that had all of the crude oil and natural gas swap agreements in effect for production periods beginning July 1, 1997 terminated on June 30, 1997, based on the closing prices for NYMEX futures contracts as of that date, the Company would have paid the counterparty approximately $185,000, which would have represented the "fair value" at that date. These agreements were not terminated. Periodically, the Company's oil and gas marketing subsidiary CEMI 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. LIQUIDITY AND CAPITAL RESOURCES 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, as compared to $121.0 million in fiscal 1996 and $54.7 million in fiscal 1995. The primary reason for the decrease from fiscal 1996 to 1997 was significant changes in the components of current assets and liabilities, specifically $102.8 million of short-term investments at June 30, 1997. Cash provided by operating activities is expected to be a significant source for meeting forecasted cash requirements for fiscal 1998. Cash Flows from Investing Activities. Significantly higher cash was used in fiscal 1997 for development, exploration and acquisition of oil and gas properties as compared to fiscal 1996 and 1995. Approximately $524 million was expended by the Company in fiscal 1997 (net of proceeds from sale of leasehold, equipment and other), as compared to $344 million in fiscal 1996, an increase of $180 million, or approximately 52%. In fiscal 1995 the Company expended $113 million (net of proceeds from sale of leasehold, equipment and other). 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 as compared to $6.2 million in fiscal 1996 and $12.0 million in fiscal 1995. 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 the purchase of additional office buildings, improvements and related equipment in Oklahoma City. 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 $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. 21 23 On March 17, 1997, the Company concluded the sale of $150 million of 7.875% Senior Notes due 2004 (the "7.875% Senior Notes"), and $150 million of 8.5% Senior Notes due 2012 (the "8.5% Senior Notes"), 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 April 1997 the Company terminated its commercial bank facilities. 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 (the "9.125% Senior Notes"). The Company may, at its option, redeem prior to April 15, 1999 up to $42 million principal amount of the 9.125% Senior Notes at 109.125% of the principal amount thereof from equity offering proceeds. The 9.125% Senior Notes are redeemable at the option of the Company at any time at the redemption or make-whole prices set forth in the Indenture. Financial Flexibility and Liquidity. The Company had working capital of approximately $151.3 million at June 30, 1997. During fiscal 1997, the Company invested in a number of oil and gas related businesses and projects. The most significant of these was the Company's initial investment made in Bayard, consisting of an $18 million subordinated note and $7 million of common stock. In August 1997, the Company entered into an agreement with Bayard to invest up to an additional $9 million and convert certain options, warrants and note amounts that will facilitate a potential initial public offering by Bayard. On August 27, 1997 Bayard filed a registration statement for an initial public offering of its common stock. Chesapeake, subsequent to the completion of the transaction noted above, will own 4,194,000 shares of Bayard common stock (30.4% of the common stock outstanding) and anticipates selling substantially all of its ownership in Bayard in the IPO (assuming the over-allotment option is exercised) and receiving repayment of the subordinated note. If successful, assuming the sale of all of the Company's Bayard stock, and based on the initial filing price of Bayard at $15 per share, the Company would receive total proceeds of approximately $74 million (net of offering costs) and realize a pre-tax gain of approximately $40 million. No assurance can be given, however, that Bayard will successfully complete the initial public offering of its common stock, at what price, or that the net proceeds or pre-tax gain discussed above will be realized by the Company. The Company also made investments in Louisiana Trend gas gathering and processing facilities which it may sell during fiscal 1998. These investments include a 50% interest in the Louisiana Austin Chalk Gathering System, and a 15.5% interest in the Masters Creek Gas Plant. If the Company decides to sell these investments, the Company expects that the proceeds should exceed the Company's cost basis of $16.8 million as of June 30, 1997. The Company currently maintains no commercial bank credit facilities because of its substantial working capital position, anticipated proceeds from the sale of the investments described above, and expected cash flows from operations as compared to the fiscal 1998 capital expenditure budget. Although the Senior Note Indentures contain various restrictions on additional indebtedness, based on asset values as of June 30, 1997, the Company estimates it could borrow up to approximately $100 million of commercial bank debt within these restrictions. Debt ratings for the Senior Notes are Ba3 by Moody's Investors Service and BB- by Standard & Poor's Corporation as of September 30, 1997. The Company's long-term debt represented approximately 64% of total capital at June 30, 1997. There are no scheduled principal payments required on any of the Senior Notes until June 2002. The Company's goal is to achieve an equity to capital ratio of at least 50% and to increase its credit ratings, ultimately achieving an investment grade debt rating. YEAR 2000 Year 2000 issues result from the inability of computer programs or computerized equipment to accurately calculate, store or use a date subsequent to December 31, 1999. The erroneous date can be interpreted in a number of different ways; typically the year 2000 is represented as the year 1900. This could result in a system failure or miscalculations causing disruptions of operations, including, among other things, a temporary inability to process transactions, send invoices, or engage in similar normal business. 22 24 The Company has completed an assessment of its core financial and operational software systems and has found them already in compliance, or the necessary steps to bring them into compliance have been identified. These tasks are scheduled for completion by September 1998. The Company believes that the successful completion of these tasks will mitigate any critical Year 2000 issues. However, if these tasks are not completed on time, the Year 2000 issue could have a material impact on the Company's ability to meet financial and reporting requirements. It should not impact the Company's ability to continue exploration, drilling, production, or sales activities. Assessment of other less critical software systems and various types of equipment is continuing and should be completed in March 1998. The Company believes that the potential impact, if any, of these systems not being Year 2000 compliant will at most require employees to manually complete otherwise automated tasks or calculations. Following the completion of the aforementioned assessment, the Company will initiate formal communication with its significant suppliers, business partners and customers to determine the extent to which the Company is vulnerable to those third parties' failure to correct their own Year 2000 issues. However, there can be no guarantee that the systems of other companies on which the Company's systems rely will be timely converted, or that a failure to convert by another company, or a conversion that is incompatible with the Company's systems would not have a material adverse effect on the Company. The Company has determined it has no exposure to contingencies related to the Year 2000 issue for the products it has sold. The Company will utilize both internal and external resources to complete tasks and perform testing necessary to address the Year 2000 issue. The Company plans to complete the Year 2000 project no later than December 31, 1998. Completion of the Year 2000 project is based on management's best estimates, which were derived utilizing numerous assumptions of future events including the continued availability of certain resources, third party modification plans and other factors. However, there can be no guarantee that these estimates will be achieved and actual results could differ materially from those plans. Specific factors that might cause such material differences include, but are not limited to, the availability and cost of personnel trained in this area, the ability to locate and correct all relevant computer codes, and similar uncertainties. FORWARD LOOKING STATEMENTS The information contained in this Form 10-K includes certain forward-looking statements. When used in this document, the words budget, budgeted, anticipate, expects, estimates, believes, goals or projects and similar expressions are intended to identify forward-looking statements. It is important to note that Chesapeake's actual results could differ materially from those projected by such forward-looking statements. Important factors that could cause actual results to differ materially from those projected in the forward- looking statements include, but are not limited to, the following: production variances from expectations, volatility of oil and gas prices, the need to develop and replace its reserves, the substantial capital expenditures required to fund its operations, environmental risks, drilling and operating risks, risks related to exploration and development drilling, the uncertainty inherent in estimating future oil and gas production or reserves, competition, government regulation, and the ability of the Company to implement its business strategy. 23 25 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
PAGE ---- Consolidated Financial Statements: Report of Independent Accountants for the Years Ended June 30, 1997 and 1996...................................... 25 Report of Independent Accountants for the Year Ended June 30, 1995............................................... 26 Consolidated Balance Sheets June 30, 1997 and 1996........ 27 Consolidated Statements of Operations for the Years Ended June 30, 1997, 1996 and 1995........................... 28 Consolidated Statements of Cash Flows for the Years Ended June 30, 1997, 1996 and 1995........................... 29 Consolidated Statements of Stockholders' Equity for the Years Ended June 30, 1997, 1996 and 1995............... 31 Notes to Consolidated Financial Statements................ 32
24 26 REPORT OF INDEPENDENT ACCOUNTANTS To the Board of Directors and Stockholders of Chesapeake Energy Corporation We have audited the accompanying consolidated balance sheets of Chesapeake Energy Corporation and its subsidiaries as of June 30, 1997 and 1996, and the related consolidated statements of operations, stockholders' equity and cash flows for the years then ended. These financial statements 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 in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audits 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. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Chesapeake Energy Corporation and its subsidiaries as of June 30, 1997 and 1996, and the consolidated results of their operations and their cash flows for the years then ended in conformity with generally accepted accounting principles. COOPERS & LYBRAND L.L.P. Oklahoma City, Oklahoma September 30, 1997 25 27 REPORT OF INDEPENDENT ACCOUNTANTS To the Board of Directors and Stockholders of Chesapeake Energy Corporation In our opinion, the consolidated statements of operations, of cash flows and of stockholders' equity for the year ended June 30, 1995 present fairly, in all material respects, the results of operations and cash flows of Chesapeake Energy Corporation and its subsidiaries for the year ended June 30, 1995, in conformity with generally accepted accounting principles. These financial statements are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audit 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 audit provides a reasonable basis for the opinion expressed above. We have not audited the consolidated financial statements of Chesapeake Energy Corporation and its subsidiaries for any period subsequent to June 30, 1995. PRICE WATERHOUSE LLP Houston, Texas September 20, 1995, except for the third paragraph of Note 9 which is as of October 9, 1997 26 28 CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS ASSETS
JUNE 30, --------------------- 1997 1996 --------- -------- ($ IN THOUSANDS) CURRENT ASSETS: Cash and cash equivalents................................. $ 124,017 $ 51,638 Short-term investments.................................... 104,485 -- Accounts receivable: Oil and gas sales....................................... 10,906 12,687 Oil and gas marketing sales............................. 19,939 6,982 Joint interest and other, net of allowances of $387,000 and $340,000, respectively............................ 25,311 27,661 Related parties......................................... 7,401 2,884 Inventory................................................. 4,854 5,163 Other..................................................... 692 2,158 --------- -------- Total Current Assets............................... 297,605 109,173 --------- -------- PROPERTY AND EQUIPMENT: Oil and gas properties, at cost based on full cost accounting: Evaluated oil and gas properties........................ 865,516 363,213 Unevaluated properties.................................. 128,505 165,441 Less: accumulated depreciation, depletion and amortization.......................................... (431,983) (92,720) --------- -------- 562,038 435,934 Other property and equipment.............................. 50,379 18,162 Less: accumulated depreciation and amortization........... (5,051) (2,922) --------- -------- Total Property and Equipment....................... 607,366 451,174 --------- -------- OTHER ASSETS................................................ 44,097 11,988 --------- -------- TOTAL ASSETS................................................ $ 949,068 $572,335 ========= ======== LIABILITIES AND STOCKHOLDERS' EQUITY CURRENT LIABILITIES: Notes payable and current maturities of long-term debt.... $ 1,380 $ 6,755 Accounts payable.......................................... 86,817 54,514 Accrued liabilities and other............................. 28,701 14,062 Revenues and royalties due others......................... 29,428 33,503 --------- -------- Total Current Liabilities.......................... 146,326 108,834 --------- -------- LONG-TERM DEBT, NET......................................... 508,950 268,431 --------- -------- REVENUES AND ROYALTIES DUE OTHERS........................... 6,903 5,118 --------- -------- DEFERRED INCOME TAXES....................................... -- 12,185 --------- -------- CONTINGENCIES AND COMMITMENTS (NOTE 4)...................... -- -- --------- -------- STOCKHOLDERS' EQUITY: Preferred Stock, $.01 par value, 10,000,000 shares authorized; none issued................................. -- -- Common Stock, 100,000,000 shares authorized; par value of $.01 and $.05 at June 30, 1997 and 1996, respectively; 70,276,975 and 60,159,826 shares issued and outstanding at June 30, 1997 and 1996, respectively................. 703 3,008 Paid-in capital........................................... 432,991 136,782 Accumulated earnings (deficit)............................ (146,805) 37,977 --------- -------- Total Stockholders' Equity......................... 286,889 177,767 --------- -------- TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY.................. $ 949,068 $572,335 ========= ========
The accompanying notes are an integral part of these consolidated financial statements. 27 29 CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF OPERATIONS
YEAR ENDED JUNE 30, ------------------------------- 1997 1996 1995 --------- -------- -------- ($ IN THOUSANDS, EXCEPT PER SHARE DATA) ------------------------------- REVENUES: Oil and gas sales......................................... $ 192,920 $110,849 $ 56,983 Oil and gas marketing sales............................... 76,172 28,428 -- Oil and gas service operations............................ -- 6,314 8,836 Interest and other........................................ 11,223 3,831 1,524 --------- -------- -------- Total Revenues.......................................... 280,315 149,422 67,343 --------- -------- -------- COSTS AND EXPENSES: Production expenses and taxes............................. 15,107 8,303 4,256 Oil and gas marketing expenses............................ 75,140 27,452 -- Oil and gas service operations............................ -- 4,895 7,747 Impairment of oil and gas properties...................... 236,000 -- -- Oil and gas depreciation, depletion and amortization...... 103,264 50,899 25,410 Depreciation and amortization of other assets............. 3,782 3,157 1,765 General and administrative................................ 8,802 4,828 3,578 Interest and other........................................ 18,550 13,679 6,627 --------- -------- -------- Total Costs and Expenses................................ 460,645 113,213 49,383 --------- -------- -------- INCOME (LOSS) BEFORE INCOME TAXES AND EXTRAORDINARY ITEM.... (180,330) 36,209 17,960 PROVISION (BENEFIT) FOR INCOME TAXES........................ (3,573) 12,854 6,299 INCOME (LOSS) BEFORE EXTRAORDINARY ITEM..................... (176,757) 23,355 11,661 EXTRAORDINARY ITEM: Loss on early extinguishment of debt, net of applicable income tax of $3,804.................. (6,620) -- -- --------- -------- -------- NET INCOME (LOSS)........................................... $(183,377) $ 23,355 $ 11,661 ========= ======== ======== EARNINGS (LOSS) PER COMMON SHARE: EARNINGS (LOSS) PER COMMON AND COMMON EQUIVALENT SHARE-PRIMARY Income (loss) before extraordinary item................. $ (2.69) $ 0.40 $ 0.21 Extraordinary item...................................... (0.10) -- -- --------- -------- -------- Net income (loss)....................................... $ (2.79) $ 0.40 $ 0.21 ========= ======== ======== EARNINGS (LOSS) PER COMMON AND COMMON EQUIVALENT SHARE-FULLY DILUTED Income (loss) before extraordinary item................. $ (2.69) $ 0.40 $ 0.21 Extraordinary item...................................... (0.10) -- -- --------- -------- -------- Net income (loss)....................................... $ (2.79) $ 0.40 $ 0.21 ========= ======== ======== WEIGHTED AVERAGE COMMON AND COMMON EQUIVALENT SHARES OUTSTANDING (IN 000'S) Primary................................................. 65,767 58,342 55,872 ========= ======== ======== Fully-diluted........................................... 65,767 58,922 56,606 ========= ======== ========
The accompanying notes are an integral part of these consolidated financial statements. 28 30 CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS
YEAR ENDED JUNE 30, ----------------------------------- 1997 1996 1995 --------- --------- --------- ($ IN THOUSANDS) CASH FLOWS FROM OPERATING ACTIVITIES: NET INCOME (LOSS)........................................... $(183,377) $ 23,355 $ 11,661 ADJUSTMENTS TO RECONCILE NET INCOME (LOSS) TO NET CASH PROVIDED BY OPERATING ACTIVITIES: Depreciation, depletion and amortization.................. 105,591 52,768 26,628 Deferred taxes............................................ (3,573) 12,854 6,299 Amortization of loan costs................................ 1,455 1,288 548 Amortization of bond discount............................. 217 563 567 Bad debt expense.......................................... 299 114 308 Gain on sale of fixed assets.............................. (1,593) (2,511) (108) Impairment of oil and gas assets.......................... 236,000 -- -- Extraordinary loss........................................ 6,620 -- -- Equity in earnings of oil field service company........... (499) -- -- CHANGES IN ASSETS AND LIABILITIES: (Increase) decrease in short-term investments............. (102,858) 622 -- (Increase) decrease in accounts receivable................ (19,987) (3,524) (22,510) (Increase) decrease in inventory.......................... (1,467) 78 (1,203) (Increase) decrease in other current assets............... 1,466 (1,525) 614 Increase (decrease) in accounts payable, accrued liabilities and other................................... 48,085 25,834 19,387 Increase (decrease) in current and non-current revenues and royalties due others................................ (2,290) 11,056 12,540 --------- --------- --------- Cash provided by operating activities................... 84,089 120,972 54,731 --------- --------- --------- CASH FLOWS FROM INVESTING ACTIVITIES: Exploration, development and acquisition of oil and gas properties.............................................. (468,462) (342,045) (117,831) Proceeds from sale of oil and gas equipment, leasehold and other................................................... 3,095 6,167 11,953 Other proceeds from sales................................. 6,428 698 1,104 Long term loans made to third parties..................... (20,000) Investment in oil field service company................... (3,048) Investment in gas marketing company, net of cash acquired................................................ -- (363) -- Other investments......................................... (8,000) -- -- Other property and equipment additions.................... (33,867) (8,846) (7,929) --------- --------- --------- Cash used in investing activities....................... (523,854) (344,389) (112,703) --------- --------- --------- CASH FLOWS FROM FINANCING ACTIVITIES: Proceeds from issuance of Common Stock.................... 288,091 99,498 -- Proceeds from long-term borrowings........................ 342,626 166,667 128,834 Payments on long-term borrowings.......................... (119,581) (48,634) (32,370) Cash received from exercise of stock options.............. 1,387 1,989 818 Other financing........................................... (379) -- -- --------- --------- --------- Cash provided by financing activities................... 512,144 219,520 97,282 --------- --------- --------- Net increase (decrease) in cash and cash equivalents........ 72,379 (3,897) 39,310 Cash and cash equivalents, beginning of period.............. 51,638 55,535 16,225 --------- --------- --------- Cash and cash equivalents, end of period.................... $ 124,017 $ 51,638 $ 55,535 ========= ========= ========= SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION CASH PAYMENTS FOR: Interest.................................................. $ 25,854 $ 17,179 $ 6,488 Income taxes.............................................. $ -- $ -- $ --
The accompanying notes are an integral part of these consolidated financial statements. 29 31 CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS -- (CONTINUED) SUPPLEMENTAL SCHEDULE OF NON-CASH INVESTING AND FINANCING ACTIVITIES: The Company has a financing arrangement with a vendor to supply certain oil and gas equipment inventory. The total amounts owed at June 30, 1997, 1996 and 1995 were $1,380,000, $3,156,000 and $6,513,000, respectively. No cash consideration is exchanged for inventory under this financing arrangement until actual draws on the inventory are made. In fiscal 1997, 1996 and 1995, the Company recognized income tax benefits of $4,808,000, $7,950,000 and $1,229,000, 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 $150 million of 7.875% Senior Notes and $150 million of 8.5% Senior Notes in March 1997 are net of $6.4 million in offering fees and expenses which were deducted from the actual cash received. Proceeds from the issuances of $90 million of 10.5% Senior Notes in May 1995 and $120 million of 9.125% Senior Notes in April 1996 are net of $2.7 million and $3.9 million, respectively, in offering fees and expenses which were deducted from the actual cash received. On June 13, 1997 the Company declared a dividend of $0.02 per common share, or $1,405,000, which was paid on July 15, 1997. 30 32 CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
YEAR ENDED JUNE 30, -------------------------------- 1997 1996 1995 --------- -------- ------- ($ IN THOUSANDS) COMMON STOCK: Balance, beginning of period........................... 3,008 58 51 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................. 12 79 7 Change in par value.................................... (2,407) 2,572 -- --------- -------- ------- Balance, end of period................................. 703 3,008 58 ========= ======== ======= COMMON STOCK WARRANTS: Balance, beginning of period........................... -- -- 5 Exercise of Common Stock Warrants...................... -- -- (5) --------- -------- ------- Balance, end of period................................. -- -- -- --------- -------- ------- PAID-IN CAPITAL: Balance, beginning of period........................... $ 136,782 $ 30,295 $28,243 Exercise of stock options and warrants................. 1,375 1,910 823 Issuance of Common Stock............................... 301,593 105,516 -- Offering expenses and other............................ (13,974) (6,317) -- Tax benefit from exercise of stock options............. 4,808 7,950 1,229 Change in par value.................................... 2,407 (2,572) -- --------- -------- ------- Balance, end of period................................. 432,991 136,782 30,295 ========= ======== ======= ACCUMULATED EARNINGS (DEFICIT): Balance, beginning of period........................... 37,977 14,622 2,961 Net income (loss)...................................... (183,377) 23,355 11,661 Dividends on common stock of $0.02 per share........... (1,405) -- -- --------- -------- ------- Balance, end of period................................. (146,805) 37,977 14,622 --------- -------- ------- TOTAL STOCKHOLDERS' EQUITY............................... $ 286,889 $177,767 $44,975 ========= ======== =======
The accompanying notes are an integral part of these consolidated financial statements. 31 33 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 U.S. 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 primarily in Texas, Louisiana, Oklahoma, Montana, North Dakota and New Mexico. Principles of Consolidation The accompanying consolidated financial statements of Chesapeake Energy Corporation (the "Company" or "Parent") include the accounts of its wholly owned subsidiaries Chesapeake Operating, Inc. ("COI"), Chesapeake Exploration Limited Partnership ("CEX"), a limited partnership, Chesapeake Louisiana, L.P. ("CLLP"), a limited partnership, Chesapeake Gas Development Corporation ("CGDC"), Chesapeake Energy Marketing, Inc. ("CEMI"), Chesapeake Canada Corporation ("CCC"), Chesapeake Energy Louisiana Corporation ("CELC"), Lindsay Oil Field Supply, Inc.("LOF"), Sander Trucking Company, Inc. ("STCO") and subsidiaries of those entities. As of June 30, 1997, CGDC had been merged into CEX, and LOF and STCO had been dissolved. All significant intercompany accounts and transactions have been eliminated. 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 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 June 30, 1997, the Company had an unrealized holding loss of $0.6 million included in interest and other revenue. 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. 32 34 CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 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. The Company's oil and gas reserves are estimated annually by independent petroleum engineers as well as the Company's internal engineers. The average composite rates used for depreciation, depletion and amortization were $1.31, $0.85 and $0.80 per equivalent Mcf in 1997, 1996, and 1995, 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. At June 30, 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 fourth quarter writedown in the carrying value of oil and gas properties of $236 million. Other Property and Equipment Other property and equipment consists primarily of gas gathering and processing facilities, vehicles, land, office buildings and equipment, and software. Major renewals and betterments are capitalized while the costs of repairs and maintenance are charged to expense as incurred. The costs of assets retired or otherwise disposed of and the applicable accumulated depreciation are removed from the accounts, and the resulting gain or loss is reflected in operations. Other property and equipment costs are depreciated on both straight-line and accelerated methods over the estimated useful lives of the assets, which range from three to 30 years. Leases The Company has various operating leases primarily for transportation equipment and field offices. Minimum lease payments under these operating leases are as follows ($ in thousands):
OPERATING LEASES --------- 1998............................................... $ 579 1999............................................... 500 2000............................................... 446 2001............................................... 446 2002............................................... 306 ------ Total minimum lease payments....................... $2,277 ======
33 35 CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Capitalized Interest During fiscal 1997, 1996 and 1995, interest of approximately $12,935,000, $6,428,000 and $1,574,000 was capitalized on significant investments in unproved properties that are not being currently depreciated, depleted, or amortized and on which exploration activities are in progress. Service Operations Certain subsidiaries of the Company performed contractual 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 statements of operations include amounts derived from certain of the contractual services provided. The Company's economic interest in its oil and gas properties is 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 recorded as a reduction in the Company's investment in Peak and will be amortized to income over the estimated useful lives of the Peak assets. The Company's investment in Peak is accounted for using the equity method. 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 Primary and fully diluted earnings (loss) per share for all periods have been computed based upon the weighted average number of shares of Common Stock outstanding after giving retroactive effect to all stock splits and the issuance of common stock equivalents when their effect is dilutive. Dilutive options or warrants which are issued during a period or which expire or are cancelled during a period are reflected in both primary and fully diluted earnings per share computations for the time they were outstanding during the period being reported upon. 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 does not believe that SFAS 128 will have a material impact on its earnings per share when adopted. 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 34 36 CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) ownership in the property. A liability is recognized only to the extent that the Company has a net imbalance in excess of the reserves on the underlying properties. The Company's net imbalance positions at June 30, 1997 and 1996 were not material. Hedging The Company periodically uses certain instruments to hedge its exposure to price fluctuations on oil and natural gas transactions. Recognized gains and losses on hedge contracts are reported as a component of the related transaction. Results for hedging transactions are reflected in oil and gas sales to the extent related to the Company's oil and gas production (see Note 10). Debt Issue Costs Other assets include debt issue costs associated with the issuance of the 10.5% Senior Notes on May 25, 1995, the 9.125% Senior Notes on April 9, 1996, and the 7.875% and 8.5% Senior Notes on March 17, 1997 (see Note 2). The remaining unamortized costs on these issuances of Senior Notes at June 30, 1997 totaled $12.5 million and are being amortized over the life of the Senior Notes. Stock Options In October 1995, the Financial Accounting Standards Board issued Statement No. 123 ("SFAS 123"), "Accounting for Stock Based Compensation". As permitted by SFAS 123, the Company has continued its previous method of accounting for stock compensation and has adopted the disclosure requirements of this Statement in fiscal 1997. Reclassifications Certain reclassifications have been made to the consolidated financial statements for the years ended June 30, 1996 and 1995 to conform to the presentation used for the June 30, 1997 consolidated financial statements. 2. SENIOR NOTES 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 at the make-whole prices determined in accordance with the indenture. 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 at the make-whole prices determined in accordance with the indenture, or on or after March 15, 2004, at the redemption price 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"). The 10.5% Senior Notes are redeemable at the option of the Company at any time on or after June 1, 1999. The Company may also redeem at its option at any time on or prior to June 1, 1998 35 37 CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) up to $30 million of the 10.5% Senior Notes at 110% of the principal amount thereof with the proceeds of an equity offering. 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 10.5% 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 10.5%, 9.125%, 7.875% and 8.5% 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 10.5% and 9.125% Senior Notes in the event of a change of control or certain asset sales. 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. As of and for the year ended June 30, 1997, the Guarantor Subsidiaries were COI, CEX, CLLP, CELC and CGDC, and the Non-Guarantor Subsidiaries were CEMI and CCC. Prior to fiscal 1997, the Guarantor Subsidiaries were COI, CEX and two service company subsidiaries the assets of which were sold effective June 30, 1996, and the Non-Guarantor Subsidiaries were CGDC and CEMI (which was acquired in December 1995). 36 38 CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) CONDENSED CONSOLIDATING BALANCE SHEET AS OF JUNE 30, 1997 ($ IN THOUSANDS) ASSETS
NON- GUARANTOR GUARANTOR COMPANY SUBSIDIARIES SUBSIDIARIES (PARENT) ELIMINATIONS CONSOLIDATED ------------ ------------ -------- ------------ ------------ 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........ 33,486 1,904 14,989 -- 50,379 Less: accumulated depreciation, depletion and amortization....... (436,276) -- (758) -- (437,034) -------- ------- -------- --------- --------- 591,214 1,921 14,231 -- 607,366 -------- ------- -------- --------- --------- INVESTMENTS IN SUBSIDIARIES AND INTERCOMPANY ADVANCES............... 817 -- 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 ======== ======= ======== ========= ========= LIABILITIES AND STOCKHOLDERS' EQUITY 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 ======== ======= ======== ========= =========
37 39 CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) CONDENSED CONSOLIDATING BALANCE SHEET AS OF JUNE 30, 1996 ($ IN THOUSANDS) ASSETS
NON- GUARANTOR GUARANTOR COMPANY SUBSIDIARIES SUBSIDIARIES (PARENT) ELIMINATIONS CONSOLIDATED ------------ ------------ -------- ------------ ------------ CURRENT ASSETS: Cash and cash equivalents............ $ 4,061 $ 2,751 $ 44,826 $ -- $ 51,638 Accounts receivable.................. 44,080 7,723 -- (1,589) 50,214 Inventory............................ 4,947 216 -- -- 5,163 Other................................ 2,155 3 -- -- 2,158 ---------- ------- -------- --------- -------- Total Current Assets......... 55,243 10,693 44,826 (1,589) 109,173 ---------- ------- -------- --------- -------- PROPERTY AND EQUIPMENT: Oil and gas properties............... 338,610 24,603 -- -- 363,213 Unevaluated leasehold................ 165,441 -- -- -- 165,441 Other property and equipment......... 9,608 61 8,493 -- 18,162 Less: accumulated depreciation, depletion and amortization........ (87,193) (8,007) (442) -- (95,642) ---------- ------- -------- --------- -------- 426,466 16,657 8,051 -- 451,174 ---------- ------- -------- --------- -------- INVESTMENTS IN SUBSIDIARIES AND INTERCOMPANY ADVANCES................ 519,386 8,132 382,388 (909,906) -- ---------- ------- -------- --------- -------- OTHER ASSETS........................... 2,310 940 8,738 -- 11,988 ---------- ------- -------- --------- -------- TOTAL ASSETS........................... $1,003,405 $36,422 $444,003 $(911,495) $572,335 ========== ======= ======== ========= ======== LIABILITIES AND STOCKHOLDERS' EQUITY CURRENT LIABILITIES: Notes payable and current maturities of long-term debt................. $ 3,846 $ 2,880 $ 29 $ -- $ 6,755 Accounts payable and other........... 91,069 7,339 5,260 (1,589) 102,079 ---------- ------- -------- --------- -------- Total Current Liabilities.... 94,915 10,219 5,289 (1,589) 108,834 ---------- ------- -------- --------- -------- LONG-TERM DEBT......................... 2,113 10,020 256,298 -- 268,431 ---------- ------- -------- --------- -------- REVENUES AND ROYALTIES DUE OTHERS...... 5,118 -- -- -- 5,118 ---------- ------- -------- --------- -------- DEFERRED INCOME TAXES.................. 23,950 1,335 (13,100) -- 12,185 ---------- ------- -------- --------- -------- INTERCOMPANY PAYABLES.................. 824,307 8,182 73,647 (906,136) -- ---------- ------- -------- --------- -------- STOCKHOLDERS' EQUITY: Common Stock......................... 117 2 2,891 (2) 3,008 Other................................ 52,885 6,664 118,978 (3,768) 174,759 ---------- ------- -------- --------- -------- 53,002 6,666 121,869 (3,770) 177,767 ---------- ------- -------- --------- -------- TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY............................... $1,003,405 $36,422 $444,003 $(911,495) $572,335 ========== ======= ======== ========= ========
38 40 CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS ($ IN THOUSANDS)
NON- GUARANTOR GUARANTOR COMPANY SUBSIDIARIES SUBSIDIARIES (PARENT) ELIMINATIONS CONSOLIDATED ------------ ------------ -------- ------------ ------------ 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 Interest and other......................................... 778 749 49,224 (39,528) 11,223 --------- --------- -------- --------- --------- Total Revenues............................................. 192,081 146,691 49,224 (107,681) 280,315 --------- --------- -------- --------- --------- COSTS AND EXPENSES: 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 Interest................................................... 37,644 10 20,424 (39,528) 18,550 --------- --------- -------- --------- --------- Total Costs & Expenses..................................... 400,480 144,304 23,542 (107,681) 460,645 --------- --------- -------- --------- --------- 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 Interest and other....................................... 1,917 238 1,676 -- 3,831 --------- --------- -------- --------- --------- 111,943 42,095 1,676 (6,292) 149,422 --------- --------- -------- --------- --------- COSTS AND EXPENSES: 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 Interest and other....................................... 508 711 12,460 -- 13,679 --------- --------- -------- --------- --------- 66,900 38,336 14,269 (6,292) 113,213 --------- --------- -------- --------- --------- Income (loss) before income taxes........................ 45,043 3,759 (12,593) -- 36,209 Income tax expense (benefit)............................. 15,990 1,335 (4,471) -- 12,854 Net income (loss)........................................ $ 29,053 $ 2,424 $(8,122) $ -- $ 23,355 ========= ========= ======== ========= ========= FOR THE YEAR ENDED JUNE 30, 1995: REVENUES: Oil and gas sales........................................ $ 55,417 $ 1,566 $ -- $ -- $ 56,983 Oil and gas service operations........................... 8,836 -- -- -- 8,836 Interest and other....................................... 1,394 -- 130 -- 1,524 --------- --------- -------- --------- --------- 65,647 1,566 130 -- 67,343 --------- --------- -------- --------- --------- COSTS AND EXPENSES: Production expenses and taxes............................ 4,045 211 -- -- 4,256 Oil and gas service operations........................... 7,747 -- -- -- 7,747 Oil and gas depreciation, depletion and amortization..... 24,775 635 -- -- 25,410 Other depreciation and amortization...................... 1,245 5 515 -- 1,765 General and administrative............................... 2,620 58 900 -- 3,578 Interest and other....................................... 570 184 5,873 -- 6,627 --------- --------- -------- --------- --------- 41,002 1,093 7,288 -- 49,383 --------- --------- -------- --------- --------- Income (loss) before income taxes........................ 24,645 473 (7,158) -- 17,960 Income tax expense (benefit)............................. 8,639 165 (2,505) -- 6,299 --------- --------- -------- --------- --------- Net Income (loss)........................................ $ 16,006 $ 308 $(4,653) $ -- $ 11,661 ========= ========= ======== ========= =========
39 41 CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS ($ IN THOUSANDS)
GUARANTOR NON-GUARANTOR COMPANY SUBSIDIARIES SUBSIDIARIES (PARENT) ELIMINATIONS CONSOLIDATED ------------ ------------- --------- ------------ ------------ 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 ========= ======== ========= ======== ========= FOR THE YEAR ENDED JUNE 30, 1995: CASH FLOWS FROM OPERATING ACTIVITIES................ $ 60,049 $ 305 $ (4,692) $ (931) $ 54,731 --------- -------- --------- -------- --------- CASH FLOWS FROM INVESTING ACTIVITIES: Oil and gas properties............................ (113,722) (4,109) -- -- (117,831) Proceeds from sales............................... 24,557 -- -- (11,500) 13,057 Purchase of oil and gas properties................ -- (11,500) -- 11,500 -- Other additions................................... (7,929) -- -- -- (7,929) --------- -------- --------- -------- --------- (97,094) (15,609) -- -- (112,703) --------- -------- --------- -------- --------- CASH FLOWS FROM FINANCING ACTIVITIES: Proceeds from borrowings.......................... 30,034 11,500 87,300 -- 128,834 Payments on borrowings............................ (32,032) (700) 362 -- (32,370) Intercompany advances, net........................ 78,324 4,509 (83,764) 931 -- Other financing................................... -- -- 818 -- 818 --------- -------- --------- -------- --------- 76,326 15,309 4,716 931 97,282 --------- -------- --------- -------- --------- Net increase (decrease) in cash and cash equivalents....................................... 39,281 5 24 -- 39,310 Cash, beginning of period........................... 13,946 -- 2,279 -- 16,225 --------- -------- --------- -------- --------- Cash, end of period................................. $ 53,227 $ 5 $ 2,303 $ -- $ 55,535 ========= ======== ========= ======== =========
40 42 CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 3. NOTES PAYABLE AND LONG-TERM DEBT Notes payable and long-term debt consist of the following:
JUNE 30, -------------------- 1997 1996 -------- -------- ($ IN THOUSANDS) 7.875% Senior Notes (see Note 2).......................... $150,000 $ -- Discount on 7.875% Senior Notes........................... (115) -- 8.5% Senior Notes (see Note 2)............................ 150,000 -- Discount on 8.5% Senior Notes............................. (862) -- 9.125% Senior Notes (see Note 2).......................... 120,000 120,000 Discount on 9.125% Senior Notes........................... (73) (81) 10.5% Senior Notes (see Note 2)........................... 90,000 90,000 12% Senior Notes.......................................... -- 47,500 Discount on 12% Senior Notes.............................. -- (1,772) Term note payable to Union Bank collateralized by CGDC, not guaranteed by the Company, variable interest at Union Bank's base rate (8.25% per annum at June 30, 1996), or at Eurodollar rate +1.875% collateralized by CGDC's producing oil and gas properties, payable in monthly installments through November 2002............. -- 12,900 Note payable to a vendor, collateralized by oil and gas tubulars, payments due 60 days from shipment of the tubulars.................................................. 1,380 3,156 Note payable to a bank, variable interest at a referenced base rate + 1.75% (10% per annum at June 30, 1996), collateralized by office buildings, payments due in monthly installments through May 1998.................. -- 680 Notes payable to various entities to acquire oil service equipment, interest varies from 7% to 11% per annum, collateralized by equipment, payments due in monthly installments through December 2000........................ -- 1,212 Other collateralized...................................... -- 1,469 Other unsecured............................................. -- 122 -------- -------- Total notes payable and long-term debt...................... 510,330 275,186 Less -- Current maturities.................................. (1,380) (6,755) -------- -------- Notes payable and long-term debt, net of current maturities................................................ $508,950 $268,431 ======== ========
The aggregate scheduled maturities of notes payable and long-term debt for the next five fiscal years ending June 30, 2002 and thereafter were as follows as of June 30, 1997 (in thousands of dollars): 1998............................................ $ 1,380 1999............................................ -- 2000............................................ -- 2001............................................ -- 2002............................................ 90,000 After 2002...................................... 418,950 -------- $510,330 ========
During the quarter ended December 31, 1996, the Company exercised its covenant defeasance rights with respect to all of its outstanding $47.5 million of 12% Senior Notes due 2001. A combination of cash and non- 41 43 CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) callable U.S. Government Securities in the amount of $55.0 million was irrevocably deposited in trust to satisfy the Company's obligations, including accrued but unpaid interest through the date of defeasance of $1.3 million. 4. CONTINGENCIES AND COMMITMENTS The Company and certain of its officers and directors are currently involved in various purported class actions alleging violations of the Securities Exchange Act of 1934. The plaintiffs assert that the defendants made materially false and misleading statements and failed to disclose material facts about the success of the Company's exploration efforts, principally in the Louisiana Trend. As a result, the complaints allege, the price of the Company's common stock was artificially inflated during periods beginning as early as 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 common stock during the class period when they knew or should have known adverse nonpublic information. Each case seeks a determination that the suit is a proper class action, certification of the plaintiff as a class representative and damages in an unspecified amount, together with costs of litigation, including attorneys' fees. The Company and the individual defendants believe that these actions are without merit, and intend to defend against them vigorously. No estimate of loss or range of estimate of loss, if any, can be made at this time. 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 (a) infringement and inducing infringement of UPRC's claim to a patent (the "UPRC Patent") for an invention involving a method of maintaining a borehole in a stratigraphic zone during drilling, and (b) tortious interference with certain business relations between UPRC and certain of its former employees. UPRC's claims against the Company are based on services provided by a third party vendor to the Company. 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 requested the court to declare the UPRC Patent invalid. The Company has also filed a motion to limit the scope of UPRC's claims and for summary judgment. No estimate of loss or range of estimate of loss, if any, can be made at this time. 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, 1998 through June 30, 2000. 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. As of June 30, 1997, the Company had guaranteed $1.3 million of debt owed by Peak. 42 44 CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 5. INCOME TAXES The components of the income tax provision (benefit) for each of the periods are as follows:
YEAR ENDED JUNE 30, ---------------------------- 1997 1996 1995 ------- ------- ------ ($ IN THOUSANDS) Current................................................ $ -- $ -- $ -- Deferred............................................... (3,573) 12,854 6,299 ------- ------- ------ Total........................................ $(3,573) $12,854 $6,299 ======= ======= ======
The effective income tax rate differed from the computed "expected" federal income tax rate on earnings before income taxes for the following reasons:
YEAR ENDED JUNE 30, ----------------------------- 1997 1996 1995 -------- ------- ------ ($ IN THOUSANDS) Computed "expected" income tax provision (benefit).... $(63,116) $12,673 $6,286 Tax percentage depletion.............................. (294) (238) (144) Valuation allowance................................... 64,116 -- -- State income taxes and other.......................... (4,279) 419 157 -------- ------- ------ $ (3,573) $12,854 $6,299 ======== ======= ======
Deferred income taxes are provided to reflect temporary differences in the basis of net assets for income tax and financial reporting purposes. The tax effected temporary differences and tax loss carryforwards which comprise deferred taxes are as follows:
YEAR ENDED JUNE 30, -------------------------------- 1997 1996 1995 -------- -------- -------- ($ IN THOUSANDS) Deferred tax liabilities: Acquisition, exploration and development costs and related depreciation, depletion and amortization..................................... $(49,831) $(63,725) $(31,220) Deferred tax assets: Net operating loss carryforwards................... 112,889 50,776 23,414 Percentage depletion carryforward.................. 1,058 764 526 -------- -------- -------- 113,947 51,540 23,940 -------- -------- -------- Net deferred tax asset (liability)................. $ 64,116 $(12,185) $ (7,280) Less: Valuation allowance.......................... (64,116) -- -- -------- -------- -------- Total deferred tax asset (liability)............... $ -- $(12,185) $ (7,280) ======== ======== ========
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 the fourth quarter of fiscal 1997, the Company recorded a $236 million write-down related to the impairment of oil and gas properties. This write-down and significant tax net operating loss carryforwards (caused primarily by expensing intangible drilling costs for tax purposes) result in a net deferred tax asset at 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, based in part on the Company's continued drilling efforts. Therefore, the Company has recorded a valuation allowance equal to the net deferred tax asset. 43 45 CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) At June 30, 1997, the Company had regular tax net operating loss carryforwards of approximately $300 million and alternative minimum tax net operating loss carryforwards of approximately $45 million. These loss carryforward amounts will expire during the years 2007 through 2012. The Company also had a percentage depletion carryforward of approximately $2.8 million at June 30, 1997, 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 an Ownership Change. However, management believes this will not result in a significant limitation of the utilization of the 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 June 30, 1997, 1996 and 1995 the Company had accounts receivable for these costs of $7.4 million, $2.9 million and $4.4 million, respectively. During fiscal 1997, 1996 and 1995 the Company incurred legal expenses of $207,000, $347,000 and $516,000, respectively, for legal services provided by the 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 up to 10% of the employees' annual salary with the Company's common stock. The amount of employee contributions is limited as specified in the plan. The Company may, at its discretion, make additional contributions to the plan. The Company contributed $603,000, $187,000 and $95,000 to the plan during the fiscal years ended June 30, 1997, 1996 and 1995, respectively. 8. MAJOR CUSTOMERS Sales to individual customers constituting 10% or more of total oil and gas sales were as follows:
PERCENT OF YEAR AMOUNT OIL AND GAS SALES - ---- ---------------- ----------------- ($ IN THOUSANDS) 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% 1995 Aquila Southwest Pipeline Corporation $18,548 33% Wickford Energy Marketing, L.C. $15,704 28% GPM Gas Corporation $11,686 21%
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. 44 46 CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 9. STOCKHOLDERS' EQUITY AND STOCK BASED COMPENSATION 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, which resulted in net proceeds to the Company of approximately $288.1 million. On April 12, 1996 the Company completed a public offering of 5,989,500 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 1994, a 3-for-2 stock split of the Common Stock in December 1995 and June 1996, and a 2-for-1 stock split of the Common Stock in December 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 may 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 may be granted under the NSO Plan after December 10, 2002. 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 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 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 may 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 fiscal 1997 and 1996, respectively: 45 47 CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) interest rates (zero-coupon U.S. government issues with a remaining life equal to the expected term of the options) of 6.74% and 6.21%; dividend yields of 0.9% and 0.9%; volatility factors of the expected market price of the Company's common stock of .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:
YEAR ENDED JUNE 30, ---------------------- 1997 1996 ---------- -------- (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) Net Income (Loss) As reported............................................... $(183,377) $23,355 Pro forma................................................. (190,160) 22,081 Earnings (Loss) per Share As reported............................................... $ (2.79) $ 0.40 Pro forma................................................. (2.89) 0.38
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 generally 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:
YEAR ENDED JUNE 30, --------------------------------------------------------------------------------------- 1997 1996 1995 --------------------------- --------------------------- --------------------------- WEIGHTED-AVG WEIGHTED-AVG WEIGHTED-AVG OPTIONS EXERCISE PRICE OPTIONS EXERCISE PRICE OPTIONS EXERCISE PRICE ---------- -------------- ---------- -------------- ---------- -------------- Outstanding -- Beginning of Year....... 7,602,884 $ 4.66 6,828,592 $1.97 5,033,340 $0.72 Granted................................ 3,564,884 19.35 2,426,850 9.98 3,185,550 3.38 Exercised.............................. (1,197,998) 1.95 (1,574,046) 1.31 (1,288,732) 0.67 Forfeited.............................. (2,066,111) 22.26 (78,512) 2.61 (101,566) 0.92 ---------- ------ ---------- ----- ---------- ----- Outstanding -- End of Year............. 7,903,659 7.09 7,602,884 4.66 6,828,592 1.97 ---------- ------ ---------- ----- ---------- ----- Exercisable -- End of Year............. 3,323,824 2,974,386 2,489,742 ---------- ---------- ---------- Shares Authorized for Future Grants.... 5,212,056 713,826 3,102,982 ---------- ---------- ---------- Fair Value of Options Granted During the Year............................. $ 7.51 $4.84 N/A ------ -----
46 48 CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) The following table summarizes information about stock options outstanding at June 30, 1997:
OPTIONS OUTSTANDING OPTIONS EXERCISABLE ----------------------------------------------- ---------------------------- NUMBER WEIGHTED-AVG. NUMBER RANGE OF OUTSTANDING REMAINING WEIGHTED-AVG. EXERCISABLE WEIGHTED-AVG. EXERCISE PRICES 6/30/97 CONTRACTUAL LIFE EXERCISE PRICE 6/30/97 EXERCISE PRICE --------------- ----------- ---------------- -------------- ----------- -------------- $ 0.56-$ 0.67..................... 843,767 5.36 $ 0.59 843,767 $ 0.59 $ 0.71-$ 1.33..................... 784,116 4.36 $ 1.00 784,116 $ 1.00 $ 2.25-$ 2.25..................... 1,128,883 7.30 $ 2.25 406,183 $ 2.25 $ 2.43-$ 4.92..................... 408,689 7.43 $ 3.15 394,159 $ 3.08 $ 4.92-$ 4.92..................... 974,910 7.82 $ 4.92 390,774 $ 4.92 $ 5.67-$ 5.67..................... 1,213,534 8.17 $ 5.67 217,140 $ 5.67 $ 6.47-$ 6.47..................... 180,000 8.28 $ 6.47 180,000 $ 6.47 $14.25-$14.25..................... 1,513,010 9.82 $14.25 0 $ 0.00 $14.75-$25.88..................... 756,750 6.30 $17.85 7,685 $17.67 $30.63-$30.63..................... 100,000 9.27 $30.63 100,000 $30.63 $ 0.56-$30.63..................... 7,903,659 7.44 $ 7.09 3,323,824 $ 3.29
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 fiscal 1997, 1996 and 1995, $4,808,000, $7,950,000 and $1,229,000, 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 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 (1) 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, (2) 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, (3) 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 (4) basis protection swaps. Results from hedging transactions are reflected in oil and gas sales to the extent related to the Company's oil and gas production. The Company has not entered into hedging transactions unrelated to the Company's oil and gas production or physical purchase or sale commitments. 47 49 CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) As of June 30, 1997, the Company had the following oil swap arrangements for periods after June 1997:
NYMEX-INDEX MONTH VOLUME (BBLS) STRIKE PRICE (PER BBL) ----- ------------- ---------------------- July 1997........................................... 31,000 $18.60 August 1997......................................... 31,000 $18.43 September 1997...................................... 30,000 $18.30 October 1997........................................ 31,000 $18.19 November 1997....................................... 30,000 $18.13 December 1997....................................... 31,000 $18.08 January through June 1998........................... 724,000 $19.82
The Company entered into oil swap arrangements to cancel the effect of the swaps for the months of August through December at an average price of $21.07 per Bbl. As of June 30, 1997, the Company had the following gas swap arrangements for periods after June 1997:
HOUSTON SHIP CHANNEL MONTHS VOLUME (MMBTU) INDEX STRIKE PRICE (PER MMBTU) ------ -------------- ------------------------------ July 1997.............................. 1,240,000 $2.313 August 1997............................ 1,240,000 $2.301 September 1997......................... 1,200,000 $2.285 October 1997........................... 1,240,000 $2.300
The Company entered into gas swap arrangements to cancel the effect of the swaps for the months of July through October at an average price of $2.133 per MMBtu. The Company has entered into a curve lock for 4.9 Bcf of gas which allows the Company the option to hedge April 1999 through November 1999 gas based upon a negative $0.285 differential to December 1998 gas any time between the strike date and December 1998. A curve lock is a swap arrangement which allows the Company to hedge the price differential between one commodity contract period and another. Gains or losses on the crude oil and natural gas hedging transactions, including "cancelled" swaps, are not recognized immediately in income, but are deferred and recognized as price adjustments in the month of related future production. The Company estimates that had all of the crude oil and natural gas swap agreements in effect for production periods beginning July 1, 1997 terminated on June 30, 1997, based on the closing prices for NYMEX futures contracts as of that date, the Company would have paid the counterparty approximately $185,000, which would have represented the "fair value" at that date. These agreements were not terminated. The fair value of hedging instruments at June 30, 1996 was a loss of approximately $4.6 million. Periodically, the Company's oil and gas marketing subsidiary CEMI 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. 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 48 50 CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 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 not considered investment grade, 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 carrying value of financial instruments included in noncurrent other assets approximates fair value at June 30, 1997. 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 June 30, 1997 and 1996 was $508.9 million and $255.6 million, respectively, compared to approximate fair values of $514.1 million and $261.2 million, respectively. The carrying value of other long-term debt approximates its fair value as interest rates are primarily variable, based on prevailing market rates. 11. DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES Net Capitalized Costs Evaluated and unevaluated capitalized costs related to the Company's oil and gas producing activities are summarized as follows:
JUNE 30, -------------------- 1997 1996 -------- -------- ($ IN THOUSANDS) Oil and gas properties: Proved.................................................... $865,516 $363,213 Unproved.................................................. 128,505 165,441 -------- -------- Total............................................. 994,021 528,654 Less accumulated depreciation, depletion and amortization... (431,983) (92,720) -------- -------- Net capitalized costs....................................... $562,038 $435,934 ======== ========
Unproved properties not subject to amortization at June 30, 1997 and 1996 consisted mainly of lease acquisition costs. The Company capitalized approximately $12,935,000 and $6,428,000 of interest during the years ended June 30, 1997 and 1996 on significant investments in unproved properties that were not being depreciated, depleted, or amortized and on which exploration or development activities were not in progress. The Company will continue to evaluate its unevaluated properties, however, the timing of the ultimate evaluation and disposition of the properties has not been determined. 49 51 CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Costs Incurred in Oil and Gas Acquisition, Exploration and Development Costs incurred in oil and gas property acquisition, exploration and development activities which have been capitalized are summarized as follows:
JUNE 30, -------------------------------- 1997 1996 1995 -------- -------- -------- ($ IN THOUSANDS) Development costs........................................ $187,736 $138,188 $ 78,679 Exploration costs........................................ 136,473 39,410 14,129 Acquisition costs: Unproved properties.................................... 140,348 138,188 24,437 Proved properties...................................... -- 24,560 -- Capitalized internal costs............................... 3,905 1,699 586 Proceeds from sale of leasehold, equipment and other..... (3,095) (6,167) (11,953) -------- -------- -------- Total........................................... $465,367 $335,878 $105,878 ======== ======== ========
Results of Operations from Oil and Gas Producing Activities (unaudited) The Company's results of operations from oil and gas producing activities are presented below for the years ended June 30, 1997, 1996 and 1995, respectively. The following table includes revenues and expenses associated directly with the Company's oil and gas producing activities. It does not include any allocation of the Company's interest costs and, therefore, is not necessarily indicative of the contribution to consolidated net operating results of the Company's oil and gas operations.
JUNE 30, --------------------------------- 1997 1996 1995 --------- -------- -------- ($ IN THOUSANDS) Oil and gas sales...................................... $ 192,920 $110,849 $ 56,983 Production costs (a)................................... (15,107) (8,303) (4,256) Impairment of oil and gas properties................... (236,000) -- -- Depletion and depreciation............................. (103,264) (50,899) (25,410) Imputed income tax (provision) benefit(b).............. 60,544 (18,335) (9,561) --------- -------- -------- Results of operations from oil and gas producing activities......................... $(100,907) $ 33,312 $ 17,756 ========= ======== ========
- --------------- (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. 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. At 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 a fourth quarter 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 the independent petroleum engineering firm of Williamson Petroleum Consultants, Inc. ("Williamson") and the Company's petroleum engineers as of June 30, 1997, 1996 and 1995. The reserves evaluated internally by the Company constituted 50 52 CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) approximately 50.0%, 0.6% and 0.5% of total proved reserves as of June 30, 1997, 1996 and 1995, respectively. 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, 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. All of the Company's oil and gas reserves are located in the United States. Presented below is a summary of changes in estimated reserves of the Company based upon the reports prepared by Williamson and the Company's petroleum engineers for 1997, 1996 and 1995:
JUNE 30, ------------------------------------------------------- 1997 1996 1995 ----------------- ---------------- ---------------- OIL GAS OIL GAS OIL GAS (MBBL) (MMCF) (MBBL) (MMCF) (MBBL) (MMCF) ------ -------- ------ ------- ------ ------- Proved reserves, beginning of year............................ 12,258 351,224 5,116 211,808 4,154 117,066 Extensions, discoveries and other additions....................... 13,874 147,485 8,781 158,052 2,549 138,372 Revisions of previous estimate.... (5,989) (137,938) (669) 12,987 (448) (18,516) Production........................ (2,770) (62,005) (1,413) (51,710) (1,139) (25,114) Sale of reserves-in-place......... -- -- -- -- -- -- Purchase of reserves-in-place..... -- -- 443 20,087 -- -- ------ -------- ------ ------- ------ ------- Proved reserves, end of year...... 17,373 298,766 12,258 351,224 5,116 211,808 ====== ======== ====== ======= ====== ======= Proved developed reserves, end of year..................... 7,324 151,879 3,648 144,721 1,973 77,764 ====== ======== ====== ======= ====== =======
As of the fiscal year ended June 30, 1997, the Company recorded revisions to the previous years' reserve estimates of approximately six million barrels of oil and 138 million Mcf, or approximately 174 Bcfe. The reserve revisions are primarily attributable to the decrease in oil and gas pricing between periods, escalating development costs at June 30, 1997, and unfavorable developmental drilling and production results during fiscal 1997. Specifically, the Company recorded downward adjustments to proved reserves of 159 Bcfe in 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 $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 in the current year 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. In prior years, the Company reported "Extensions, discoveries and other additions" net of current year production related thereto. The Company began reporting this category inclusive of current year production in fiscal 1997 and restated fiscal 1996 and fiscal 1995 quantities accordingly. A corresponding change in fiscal 51 53 CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 1996 and fiscal 1995 was recorded to "Revisions of previous estimate" with no net change to year-end reserve quantities. 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 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:
JUNE 30, ------------------------------------ 1997 1996 1995 --------- ---------- --------- ($ IN THOUSANDS) Future cash inflows............................. $ 954,839 $1,101,642 $ 427,377 Future production costs......................... (190,604) (168,974) (75,927) Future development costs........................ (152,281) (137,068) (76,543) Future income tax provision..................... (104,183) (135,543) (51,789) --------- ---------- --------- Future net cash flows........................... 507,771 660,057 223,118 Less effect of a 10% discount factor............ (92,273) (198,646) (63,207) --------- ---------- --------- Standardized measure of discounted future net cash flows.................................... $ 415,498 $ 461,411 $ 159,911 ========= ========== =========
52 54 CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) The principal sources of change in the standardized measure of discounted future net cash flows are as follows:
JUNE 30, -------------------------------- 1997 1996 1995 --------- --------- -------- ($ IN THOUSANDS) Standardized measure, beginning of year............ $ 461,411 $ 159,911 $118,608 Sales of oil and gas produced, net of production costs............................................ (177,813) (102,546) (52,727) Net changes in prices and production costs......... (99,234) 88,729 (24,807) Extensions and discoveries, net of production and development costs................................ 287,068 275,916 108,644 Changes in future development costs................ (12,831) (11,201) 3,406 Development costs incurred during the period that reduced future development costs................. 46,888 43,409 23,678 Revisions of previous quantity estimates........... (199,738) 12,728 (21,595) Purchase of reserves-in-place...................... -- 29,641 -- Accretion of discount.............................. 54,702 18,814 14,126 Net change in income taxes......................... 63,719 (57,382) (5,586) Changes in production rates and other.............. (8,674) 3,392 (3,836) --------- --------- -------- Standardized measure, end of year.................. $ 415,498 $ 461,411 $159,911 ========= ========= ========
For an explanation of the reclassifications made to the standardized measure of discounted future net cash flows in fiscal 1996 and fiscal 1995, see discussion of Oil and Gas Reserve Quantities included above. 53 55 CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 12. QUARTERLY FINANCIAL DATA (UNAUDITED) Summarized unaudited quarterly financial data for fiscal 1997 and 1996 are as follows ($ in thousands except per share data):
QUARTER ENDED ---------------------------------------------------- SEPTEMBER 30, DECEMBER 31, MARCH 31, JUNE 30, 1996 1996 1997 1997 ------------- ------------ --------- --------- Net sales............................. $48,937 $71,249 $79,809 $ 69,097 Gross profit (loss)(a)................ 14,889 28,057 25,737 (241,686) Net income (loss) before extraordinary item................................ 8,204 10,274 15,928 (217,783) Net income (loss) per share before extraordinary item: Primary............................. .13 .15 .22 (3.12) Fully-diluted....................... .13 .15 .22 (3.12)
QUARTER ENDED ---------------------------------------------------- SEPTEMBER 30, DECEMBER 31, MARCH 31, JUNE 30, 1995 1995 1996 1996 ------------- ------------ --------- --------- Net sales............................. $21,988 $31,766 $44,145 $ 47,692 Gross profit(a)....................... 6,368 11,368 14,741 13,580 Net income............................ 2,915 5,459 7,623 7,358 Net income per share: Primary............................. .05 .10 .13 .12 Fully-diluted....................... .05 .09 .13 .12
- --------------- (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, can 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. At 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 a fourth quarter writedown in the carrying value of oil and gas properties of $236 million. 54 56 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. Incorporated herein by reference to Exhibit 3.1 to Registrant's quarterly report on Form 10-Q for the quarter ended December 31, 1996. 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 registration statement on Form S-4 (No. 333-24995). 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). 4.3 -- Indenture dated as of May 15, 1995 among Chesapeake Energy Corporation, its subsidiaries signatory thereto as Subsidiary Guarantors and United States Trust Company of New York, as Trustee, with respect to 10.5% Senior Notes due 2002. Incorporated herein by reference to Exhibit 4.3 to Registrant's registration statement on Form S-4 (No. 33-93718). 4.4 -- Indenture dated April 1, 1996 among Chesapeake Energy Corporation, its subsidiaries signatory thereto as Subsidiary Guarantors and United States Trust Company of New York, as Trustee, with respect to 9.125% Senior Notes due 2006. Incorporated herein by reference to Exhibit 4.6 to Registrant's registration statement on Form S-3 Registration Statement (No. 333-1588) 4.5 -- Agreement to furnish copies of unfiled long-term debt instruments. 4.8 -- Stock Registration Agreement dated May 21, 1992 between Chesapeake Energy Corporation and various lenders, as amended by First Amendment thereto dated May 26, 1992. Incorporated herein by reference to Exhibits 10.26.1 and 10.26.2 to Registrant's registration statement on Form S-1 (No. 33-55600). 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).
55 57
EXHIBIT NUMBER DESCRIPTION ------- ----------- 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. 10.2.1+ -- Employment Agreement dated as of July 1, 1997 between Aubrey K. McClendon and Chesapeake Energy Corporation. 10.2.2+ -- Employment Agreement dated as of July 1, 1997 between Tom L. Ward and Chesapeake Energy Corporation. 10.2.3+ -- Employment Agreement dated as of July 1, 1997 between Marcus C. Rowland and Chesapeake Energy Corporation. 10.2.4+ -- Employment Agreement dated as of July 1, 1995 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, 1995. 10.2.5+ -- Employment Agreement dated as of July 1, 1997 between J. Mark Lester and Chesapeake Energy Corporation. 10.2.6+ -- Employment Agreement dated as of July 1, 1997 between Henry J. Hood and Chesapeake Energy Corporation. 10.2.7+ -- Employment Agreement dated as of July 1, 1997 between Ronald A. Lefaive and Chesapeake Energy Corporation. 10.2.8+ -- Employment Agreement dated as of July 1, 1997 between Martha A. Burger and Chesapeake Energy Corporation. 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). 10.9 -- 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 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. 11 -- Statement of Net Income (Loss) Per Share.
56 58
EXHIBIT NUMBER DESCRIPTION ------- ----------- 21 -- Subsidiaries of Registrant 23.1* -- Consent of Coopers & Lybrand L.L.P. 23.2* -- Consent of Price Waterhouse LLP 23.3* -- Consent of Williamson Petroleum Consultants, Inc. 27 -- Financial Data Schedule
- --------------- * Filed herewith. + Management contract or compensatory plan or arrangement. (b) Reports on Form 8-K During the quarter ended June 30, 1997, the Company filed the following Current Reports on Form 8-K dated April 2, 1997 announcing the completion of its Brown #1-H in Washington County, Texas, April 24, 1997 reporting third quarter and first nine months fiscal 1997 results, and June 27, 1997 announcing refocused Louisiana drilling program and expected asset writedown. 57 59 SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this amendment on Form 10-K/A to be signed on its behalf by the undersigned thereunto duly authorized on February 11, 1998. CHESAPEAKE ENERGY CORPORATION By /s/ MARCUS C. ROWLAND ----------------------------------- Marcus C. Rowland Senior Vice President -- Finance and Chief Financial Officer (Principal Financial Officer) 58 60 INDEX TO EXHIBITS
EXHIBIT NUMBER DESCRIPTION ------- ----------- 3.1 -- Registrant's Certificate of Incorporation. Incorporated herein by reference to Exhibit 3.1 to Registrant's quarterly report on Form 10-Q for the quarter ended December 31, 1996. 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 registration statement on Form S-4 (No. 333-24995). 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). 4.3 -- Indenture dated as of May 15, 1995 among Chesapeake Energy Corporation, its subsidiaries signatory thereto as Subsidiary Guarantors and United States Trust Company of New York, as Trustee, with respect to 10.5% Senior Notes due 2002. Incorporated herein by reference to Exhibit 4.3 to Registrant's registration statement on Form S-4 (No. 33-93718). 4.4 -- Indenture dated April 1, 1996 among Chesapeake Energy Corporation, its subsidiaries signatory thereto as Subsidiary Guarantors and United States Trust Company of New York, as Trustee, with respect to 9.125% Senior Notes due 2006. Incorporated herein by reference to Exhibit 4.6 to Registrant's registration statement on Form S-3 Registration Statement (No. 333-1588) 4.5 -- Agreement to furnish copies of unfiled long-term debt instruments. 4.8 -- Stock Registration Agreement dated May 21, 1992 between Chesapeake Energy Corporation and various lenders, as amended by First Amendment thereto dated May 26, 1992. Incorporated herein by reference to Exhibits 10.26.1 and 10.26.2 to Registrant's registration statement on Form S-1 (No. 33-55600). 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. 10.2.1+ -- Employment Agreement dated as of July 1, 1997 between Aubrey K. McClendon and Chesapeake Energy Corporation.
61
EXHIBIT NUMBER DESCRIPTION ------- ----------- 10.2.2+ -- Employment Agreement dated as of July 1, 1997 between Tom L. Ward and Chesapeake Energy Corporation. 10.2.3+ -- Employment Agreement dated as of July 1, 1997 between Marcus C. Rowland and Chesapeake Energy Corporation. 10.2.4+ -- Employment Agreement dated as of July 1, 1995 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, 1995. 10.2.5+ -- Employment Agreement dated as of July 1, 1997 between J. Mark Lester and Chesapeake Energy Corporation. 10.2.6+ -- Employment Agreement dated as of July 1, 1997 between Henry J. Hood and Chesapeake Energy Corporation. 10.2.7+ -- Employment Agreement dated as of July 1, 1997 between Ronald A. Lefaive and Chesapeake Energy Corporation. 10.2.8+ -- Employment Agreement dated as of July 1, 1997 between Martha A. Burger and Chesapeake Energy Corporation. 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). 10.9 -- 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 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. 11 -- Statement of Net Income (Loss) Per Share. 21 -- Subsidiaries of Registrant 23.1* -- Consent of Coopers & Lybrand L.L.P. 23.2* -- Consent of Price Waterhouse LLP 23.3* -- Consent of Williamson Petroleum Consultants, Inc. 27 -- Financial Data Schedule
- --------------- * Filed herewith. + Management contract or compensatory plan or arrangement. EX-23.1 2 CONSENT OF COOPERS & LYBRAND LLP 1 EXHIBIT 23.1 CONSENT OF INDEPENDENT ACCOUNTANTS We consent to the incorporation by reference in the registration statements of Chesapeake Energy Corporation on Form S-8 (File Nos. 33-84256, 33-84258, 33-89282, 33-88196, 333-27525 and 333-07255) and Form S-3 (File Nos. 333-04027 and 333-12533) of our report dated September 30, 1997, on our audits of the consolidated financial statements of Chesapeake Energy Corporation as of June 30, 1997 and 1996 and for the years then ended, which report is included in this Annual Report on Form 10-K/A. COOPERS & LYBRAND L.L.P. Oklahoma City, Oklahoma February 9, 1998 EX-23.2 3 CONSENT OF PRICE WATERHOUSE LLP 1 EXHIBIT 23.2 CONSENT OF INDEPENDENT ACCOUNTANTS We consent to the incorporation by reference in the registration statements of Chesapeake Energy Corporation on Form S-8 (File Nos. 33-84256, 33-84258, 33-89282, 33-88196, 333-27525 and 333-07255) and Form S-3 (File Nos. 333-04027 and 333-12533) of our report dated September 20, 1995, except for the third paragraph of Note 9 which is as of October 9, 1997, on our audit of the consolidated financial statements of Chesapeake Energy Corporation for the year ended June 30, 1995, which report is included in this Annual Report on Form 10-K/A. PRICE WATERHOUSE LLP Houston, Texas February 9, 1998 EX-23.3 4 CONSENT OF WILLIAMSON PETROLEUM CONSULTANTS INC. 1 EXHIBIT 23.3 CONSENT OF WILLIAMSON PETROLEUM CONSULTANTS, INC. As independent oil and gas consultants, Williamson Petroleum Consultants, Inc. hereby consents to (a) the use of our reserve report entitled "Evaluation of Oil and Gas Reserves to the Interests of Chesapeake Energy Corporation in Certain Properties in Louisiana and Texas, Effective June 30, 1997, for Disclosure to the Securities and Exchange Commission, Williamson Project 7.8496" dated September 17, 1997 and all references to our firm included in or made a part of the Chesapeake Energy Corporation Annual Report on Form 10-K/A to be filed with the Securities and Exchange Commission on or about February 11, 1998 and (b) to the incorporation by reference of this Form 10-K/A for the year ending June 30, 1997 in the Registration Statements on Form S-8 (Nos. 33-84256, 33-84258, 33-88196, 333-07255, 33-89282, and 333-27525) and on Form S-3 (Nos. 333-04027 and 333-12533). /s/ WILLIAMSON PETROLEUM CONSULTANTS, INC. ---------------------------------------------- WILLIAMSON PETROLEUM CONSULTANTS, INC. Houston, Texas February 11, 1998 -----END PRIVACY-ENHANCED MESSAGE-----