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 ranks among the five most active drillers of new wells in the United States.
From inception in 1989 through June 30, 1996, Chesapeake drilled a total of 562 gross (186 net) wells, of which 529 gross (175 net) wells were commercially productive. As a result of its successful drilling efforts, the Company has experienced significant growth in its proved reserves, production and revenue. From its first full fiscal year of operation ended June 30, 1990 to the fiscal year ended June 30, 1996, the Company's estimated proved reserves increased to 425 Bcfe from 11 Bcfe, annual production increased to 60.2 Bcfe from 0.2 Bcfe, total revenue increased to $149.4 million from $0.6 million, and total assets increased to $572 million from $8 million.
At June 30, 1996, the Company's estimated proved reserves consisted of 12.3 MMBbl of oil and 351.2 Bcf of gas, a total of 425 Bcfe. During fiscal 1996, the Company's proved reserves increased from 242 Bcfe to 425 Bcfe, an increase of 183 Bcfe (76%), or a four-fold replacement of its 60.2 Bcfe of production. At June 30, 1996, the present value of estimated future net revenue attributable to Chesapeake's estimated proved reserves before income taxes (utilizing a 10% discount rate) was $547 million, based on average prices at fiscal year end 1996 of $20.90 per Bbl and $2.41 per Mcf.
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.
BUSINESS STRATEGY
Since its inception, Chesapeake's 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. The Company has focused in areas where reservoirs such as fractured carbonates offer (i) low geological risk, (ii) large reserve potential, and (iii) the opportunity to earn attractive economic returns through the application of advanced drilling and completion technologies.
The Company historically concentrated its undeveloped leasehold acquisitions and associated drilling in the Giddings Field of southern Texas and the Golden Trend Field of southern Oklahoma. Since early fiscal 1995, Chesapeake has extensively developed new project areas that are either extensions of the Company's historical focus in the Giddings and Golden Trend Fields or are new areas in which the Company's geological and engineering expertise provides the Company with competitive advantages. These additional project areas include the Knox Field in southcentral Oklahoma, the Sholem Alechem Field in southern Oklahoma, the Louisiana Austin Chalk Trend (the "Louisiana Trend"), the Arkoma Basin in southeastern Oklahoma, the Lovington area in eastern New Mexico, and the Williston Basin in eastern Montana and western North Dakota. Within the Louisiana Trend, the Company has acquired over 1,000,000 acres, and has identified six project areas: South Brookeland, Leesville, Masters Creek, St. Landry, Baton Rouge and Livingston. An important element in the Company's business strategy is to retain a higher level of ownership in these new project areas than it historically retained in the Giddings and Golden Trend Fields.
The Company's operating areas are typically characterized by fractured carbonate reservoirs that are known to contain oil and gas and generally cover a large geographic region. In the past, development of these reservoirs has been limited by both economic and technological factors. Recent advances in drilling and completion technologies, and the resulting lower exploration costs, provide the Company with the opportunity to develop large new reserves of oil and natural gas and to generate attractive economic returns.
COMPETITIVE ADVANTAGES
Management believes five competitive advantages are responsible for Chesapeake's rapid growth and distinguish the Company from other independent energy companies.
Growth Through the Drillbit. Employing its strategy of growth through the drillbit, the Company has substantially increased its reserves and production. By focusing drilling efforts on deep fractured carbonate reservoirs, management believes the Company can continue to increase its reserves and production and generate attractive returns by integrating the Company's advanced drilling and completion expertise with its large inventory of undeveloped leasehold.
Dominant Leasehold Positions. Through aggressive acreage acquisition in its existing and new project areas, the Company seeks to establish a dominant leasehold position in each of its project areas. Such a dominant position allows the Company to maximize its economic returns while limiting drilling opportunities available to its competitors. Consistent with this strategy, the Company has assembled a significant leasehold acreage inventory which included approximately 900 proved and unproved drilling locations at June 30, 1996.
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(a) Includes wells drilling
(b) Acreage in thousands
Technological Leadership. The Company has developed significant expertise in the rapidly evolving technologies of horizontal drilling, 3-D seismic evaluation, and deep fracture stimulation. The Company believes its expertise in employing these technologies is the most important factor in its growth during the past several years. In particular, the Company has developed considerable horizontal drilling and completion expertise, especially in wells which target deep fractured carbonates. Over the last several years, deeper, more complex horizontal wells have become technically and economically feasible and the cost of drilling these wells has decreased. As a result, the Company believes there has been a substantial increase in the number of areas which are economically attractive for horizontal drilling.
Superior Operating Margin. Management believes the Company's operating cost structure is among the lowest of all publicly traded independent energy producers. For fiscal 1996 the Company's per unit operating costs (consisting of general and administrative expense, lease operating expense, production taxes, and depreciation, depletion and amortization of oil and gas properties) were $1.07 per Mcfe produced resulting in an operating margin of $0.77 per Mcfe. Management believes the key to creating value in the independent energy industry is the ability to generate high levels of cash flow that can be successfully reinvested in a technologically-driven exploration program.
Management's Substantial Equity Ownership. At June 30, 1996, the Company's management and directors beneficially owned (including outstanding vested options of management) an aggregate of approximately 44% of the Company's outstanding shares of Common Stock. Management believes this substantial equity ownership provides a strong alignment of management's and investors' interests and creates an entrepreneurial culture within the Company.
PRIMARY OPERATING AREAS
The Company's activities are concentrated in three primary operating areas: (i) the Navasota River and Independence areas of the downdip Giddings Field in southern Texas, (ii) the Knox, Sholem Alechem, and Golden Trend Fields of southern Oklahoma, and (iii) the South Brookeland, Leesville, Masters Creek, St. Landry, Baton Rouge and Livingston areas of the Louisiana Trend.
The following table sets forth the Company's proved reserves in its primary operating areas (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 drilling locations required to develop the Company's proved undeveloped reserves at June 30, 1996:
GIDDINGS FIELD. Chesapeake's second largest concentration of proved reserves and its highest concentration of present value is located in the Giddings Field, which is currently one of the most active oil and natural gas fields in the U.S. The primary producing formation in Giddings is the Austin Chalk formation, a fractured carbonate reservoir found at depths ranging from 7,000 feet to 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 Company believes the downdip Giddings area is one of the largest discoveries of onshore gas in the U.S. in recent years.
The Company believes that its success in the downdip Giddings Field is attributable to four principal factors: (i) limited reservoir drainage from previously drilled vertical wells; (ii) the Company's aggressive leasehold acquisition program, which has permitted the creation of larger spacing units, thus reducing competition for reserves from offsetting wells; (iii) continued technological advances in horizontal drilling, which have significantly lowered development costs, expanded the field's boundaries into deeper areas, and increased per well productivity through the ability to drill within a more precisely defined target zone; and (iv) the geological setting of the downdip Austin Chalk, which is characterized by greater reservoir pressure and more intensive fracturing than in the updip area of the Giddings Field. As a result of these factors, the Company's downdip wells have, on average, produced greater reserves per well while also exhibiting lower decline rates than average wells in other areas of Austin Chalk production.
Navasota River. In February 1994, the Company drilled its first well in the Navasota River leasehold block, located in Brazos and Grimes Counties, Texas. As of June 30, 1996, the Company had drilled and completed 77 Navasota River wells and was drilling seven additional wells. The Company has budgeted $30 million in fiscal 1997 to drill 28 gross (16 net) wells in the Navasota River area.
Independence. The Company's Independence block is located in Grimes and Washington Counties to the south and southwest (and further downdip) from the Navasota River area. As of June 30, 1996, the Company had drilled 24 Independence wells and was drilling two additional wells. The Company has budgeted $7 million to drill six gross (3 net) wells in fiscal 1997 in the Independence area.
SOUTHERN OKLAHOMA. Chesapeake's largest concentration of proved reserves is located in southern Oklahoma and is comprised of the Knox, Golden Trend and Sholem Alechem Fields. Based on the
Company's drilling success in late 1993 with its deeper wells (12,000 to 14,000 feet) in the Bradley area of the Golden Trend Field, the Company initiated a deeper drilling project in 1994 in the Knox area. The Company's first two wells in Knox were the first wells in Oklahoma to establish commingled commercial production from the Sycamore, Woodford, Hunton and Viola formations at depths below 15,000 feet. This success led to an aggressive and successful acreage acquisition and drilling program during fiscal 1995 and fiscal 1996.
As of June 30, 1996, Chesapeake had successfully completed 41 of 42 wells drilled in the Knox Field and was drilling six additional wells. The Company's acreage inventory in the Knox area is large enough to support the drilling of approximately 50 proved undeveloped locations and the Company believes this inventory could increase by an additional 200 increased density or step-out wells, subject to applicable spacing requirements. The Company has budgeted $36 million in fiscal 1997 to drill 19 gross (15 net) wells in the Knox area. During fiscal 1996, Chesapeake doubled its assets in Knox through its acquisition of Amerada Hess Corporation's interests in Chesapeake wells.
The Company's horizontal drilling project in the Sholem Alechem portion of southern Oklahoma's Sho-Vel-Tum Field was initiated on the Company's belief that the application of horizontal drilling technology could result in a significant increase in the recovery of remaining reserves in this field. Since its discovery more than 80 years ago, the Sho-Vel-Tum Field has produced more than one billion barrels of oil and one trillion cubic feet of natural gas. To date the Company has drilled 25 gross (11 net) horizontal wells and has successfully completed all of these wells. The Company has budgeted $8 million to drill 10 gross (5 net) wells during fiscal 1997. Texaco Exploration and Production, Inc. is the Company's 50% working interest partner in this area.
LOUISIANA AUSTIN CHALK TREND. The Louisiana Trend is the newest of the Company's three primary operating areas and will be the focus of the Company's exploration and development activities in the foreseeable future. In late 1994, Occidental Petroleum Corporation ("Occidental") announced the completion of a single lateral 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.
Based on management's belief that the Occidental well confirmed the Company's geological premise that the Austin Chalk would be productive across a large portion of central and southeastern Louisiana, Chesapeake invested approximately $103 million through June 30, 1996 to acquire approximately 1,000,000 acres of leasehold in the Louisiana Trend. This large acreage position provides the Company with the opportunity to drill up to 300-500 horizontal Austin Chalk wells, assuming spacing units of approximately 2,000 acres and assuming continued drilling success by Chesapeake and others in the Louisiana Trend.
During fiscal 1996, Chesapeake operated five wells (4.9 net) in the Louisiana Trend and participated in the second well drilled by Occidental in this area. Production commenced from Chesapeake's first well, the Laddie James #7-1, on June 30, 1996, and the other wells were drilling at that date. Chesapeake has budgeted $125 million to drill 25 gross and net wells in the Louisiana Trend during fiscal 1997, including several wells that will test the deeper Tuscaloosa formation.
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, 1996 owned approximately 550,000 gross acres. The primary focus of Chesapeake's exploration efforts in this area is the horizontally-drilled, oil-prone Red River "B" formation in Bowman and Slope Counties, North Dakota and in Fallon County, Montana. Approximately 75 Red River "B" horizontal wells have been drilled to date by other companies in this area. The Company has budgeted $6 million to drill six gross and net wells during fiscal 1997.
PERMIAN BASIN. In late 1994, 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.
The Company has identified approximately 25 prospects in the Lovington area, where the Company is targeting oil reserves at depths from 11,000 to 13,000 feet. The Company drilled its first well during fiscal 1996 and has budgeted $4 million to drill six gross (5 net) wells during fiscal 1997.
ARKOMA BASIN. The Arkoma Basin is Oklahoma's second largest gas basin. In late 1994, the Company initiated a seismic and leasehold acquisition program in the Jackfork and Deep Spiro areas of the Arkoma Basin of southeastern Oklahoma. The Jackfork and Deep Spiro plays are located in the southern portion of the basin, a deeper and more geologically complex area that has been less heavily explored than the updip northern portion.
The Company believes recent developments in 3-D seismic technology and in drilling and completion technologies have created an excellent opportunity for the Company to establish a significant project area in the Arkoma Basin. The Company is targeting gas reserves at depths from 4,000 to 16,000 feet. As of June 30, 1996, the Company had drilled 14 gross (6 net) Arkoma Basin wells on its acreage position of approximately 125,000 gross acres. The Company has budgeted $3 million to drill eight gross (4 net) wells during fiscal 1997.
OTHER. The Company maintains significant interests in other acreage, primarily in Fayette, Grimes, and Karnes Counties, Texas, where the Company conducts horizontal drilling operations targeting the Austin Chalk, Buda, Georgetown, and Edwards formations. The Company has budgeted $6 million to drill six gross (4 net) horizontal wells in these and other areas of Texas during fiscal 1997.
HORIZONTAL DRILLING OPERATIONS
Horizontal drilling involves the drilling of a horizontal borehole within a narrow segment of a single stratigraphic formation. Through June 30, 1996, Chesapeake had drilled 275 horizontal wells in southern Texas, southern Oklahoma and Louisiana.
In general, horizontal drilling permits the operator to intersect a greater number of fractures than in conventional vertical drilling. This can result in both increased initial production rates and greater ultimate recoveries of hydrocarbons on a per well basis. Based on the Company's experience, the typical production profile of a horizontal well reflects relatively higher production in the early life of the well, allowing for more of the drilling costs to be quickly recovered, followed by a significant decline in production and a stabilization of production at lower rates thereafter. The Company believes that horizontal drilling tends to decrease field development costs by reducing the number of wells needed to drain a given reservoir.
The technology enabling the Company to drill profitable horizontal wells in the Giddings Field in southern Texas, the Sholem Alechem Field in southern Oklahoma and recently in the Louisiana Trend has progressed rapidly and has resulted in lower finding costs. Advances in drilling technology such as "measurement-while-drilling" tools, which provide a continuous analysis of the drillbit's location when drilling horizontally, assist the Company's engineers in guiding the drillbit into a more tightly defined target zone, or "sweet spot," in the formation. Additionally, innovations in downhole motor, drillbit, and whipstock technology have doubled the rate of drilling penetration during the past two years and have enabled the Company to drill multiple lateral horizontal wells. The Company's geologists are using "logging-while-drilling" and enhanced seismic technology to more accurately locate the existence of hydrocarbon-bearing fractures within target formations. Further innovations in horizontal drilling tools and techniques continue at a rapid pace and management believes such innovations will enable the Company to expand its drilling success further downdip in the Louisiana Trend and in Giddings and into other horizontal drilling projects elsewhere in the United States.
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.
At June 30, 1996, the Company was drilling 28 gross (16.2 net) exploratory or development wells, of which 24 gross (12.6 net) have been successfully completed and four gross (3.6 net) are still being drilled or tested. The Company was also participating with minority interests in nine non-operated wells being drilled at that date.
WELL DATA
At June 30, 1996, the Company had interests in approximately 474 producing wells, of which 93 (29.9 net) were classified as primarily oil producing wells and 381 (124.0 net) were classified as primarily gas producing wells.
VOLUMES, REVENUE, PRICES AND PRODUCTION COSTS
The following table sets forth certain information regarding the production volumes, revenue, average prices received and average production costs associated with the Company's sale of oil and gas for the periods indicated:
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:
ACREAGE
The following table sets forth as of June 30, 1996 the gross and net acres of both developed and undeveloped oil and gas leases which the Company holds. "Gross" acres are the total number of acres in which the Company owns a working interest. "Net" acres refer to gross acres multiplied by the Company's fractional working interest. Acreage numbers are stated in thousands.
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 1996, the following three customers individually accounted for 10% or more of the Company's total oil and gas sales:
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.
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 swap arrangements that establish an index-related price above which the Company pays the hedging partner and below which the Company is paid by the hedging partner, the purchase of index-related puts that provide for a "floor" price to the Company to be paid by the counter-party to the extent the price of the commodity is below the contracted floor, and basis protection swaps. 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.
As of June 30, 1996, the Company had NYMEX-based crude oil swap agreements for 1,000 Bbl per day for July 1, 1996 through August 31, 1996 at an average price of $17.85 per Bbl. The counter-party has the option exercisable monthly for an additional 1,000 Bbl per day for the period July 1, 1996 through December 31, 1996 to cause a swap if the price exceeds an average $17.74 per Bbl. The actual settlements for July and August resulted in a $0.5 million payment to the counter-party. The Company estimates, based on NYMEX prices as of August 30, 1996, that the effect of the September through December hedges would be a $0.4 million payment to the counter-party.
The Company has purchased Houston Ship Channel put options which guarantee the Company an average floor price of $2.21/Mmbtu for 20,000 Mmbtu per day for the period of November 1, 1996 through February 28, 1997. The average cost of these puts was $0.14 per Mmbtu.
As of June 30, 1996, the Company had NYMEX-based natural gas swaps and NYMEX/Houston Ship Channel Basis swaps for the months of July through October 1996. These transactions resulted in payments to the Company's counter-party of approximately $2 million for the month of July 1996 and $1.5 million for the month of August 1996. The Company estimates, based on NYMEX prices as of August 30, 1996, that the effect of the September and October hedges would be a $0.2 million payment to the counter-party.
The Company has only limited involvement with derivative financial instruments, as defined in Statement of Financial Accounting Standards No. 119 ("SFAS 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 counter-parties and to basis risk.
COMPETITION
The oil and gas industry is highly competitive. The Company competes for the acquisition of oil and gas properties with numerous other entities, including major oil companies, other independent oil and gas concerns and individual producers and operators. 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 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 project 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.
Marketing and Transportation
Historically, the transportation and sale for resale of natural gas in interstate commerce have been regulated pursuant to the Natural Gas Act of 1938, the Natural Gas Policy Act of 1978 (the "NGPA"), and the regulations promulgated thereunder by the Federal Energy Regulatory Commission (the "FERC"). Since 1978, maximum selling prices of certain categories of natural gas sold in "first sales," whether sold in interstate or intrastate commerce, have been regulated pursuant to the NGPA. The NGPA established various categories of natural gas and provided for graduated deregulation of price controls of several categories of natural gas and the deregulation of sales of certain categories of natural gas. Most "first sale" price deregulation contemplated under the NGPA has already occurred. Moreover, in July 1989, the Natural Gas Wellhead Decontrol Act was enacted. This Act amended the NGPA to remove both price and non-price controls from natural gas sold in "first sales" as of January 1, 1993.
Several major regulatory changes have been implemented by the FERC from 1985 to the present that affect the economics of natural gas production, transportation and sales. In addition, the FERC continues to promulgate revisions to various aspects of the rules and regulations affecting those segments of the natural gas industry, most notably interstate natural gas transmission companies, which remain subject to the FERC's jurisdiction. These initiatives may also affect the intrastate transportation of gas under certain circumstances. The stated purposes of many of these regulatory changes is to promote competition among the various sectors of the gas industry. The ultimate impact of these complex and overlapping rules and regulations, many of which are repeatedly subjected to judicial challenge and interpretation, 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 regulating the release of materials in the environment or otherwise relating to the protection of the environment 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 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 Environmental Protection Agency ("EPA"). Such regulation has increased the cost of planning, designing, drilling, operating and in some instances, abandoning wells. In most instances, the regulatory requirements relate to the handling and disposal of drilling and production waste products and waste created by water and air pollution control procedures. Although the Company believes that compliance with environmental regulations will not have a material adverse effect on operations or earnings, risks of substantial costs and liabilities are inherent in oil and gas operations, and there can be no assurance that significant costs and liabilities, including criminal penalties, will not be incurred. Moreover, it is possible that other developments, such as stricter environmental laws and regulations, and claims for damages 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 is 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 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 an owner of sites on which "hazardous substances" have been released by previous owners or operators. 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 have been named a potentially responsible party under CERCLA or similar state superfund laws affecting property owned or leased by the Company.
Air Emissions. The operations of the Company are subject to local, state and federal regulations for the control of emissions of air pollution. Legal and regulatory requirements in this area are increasing, and there can be no assurance that significant costs and liabilities will not be incurred in the future as a result of new regulatory developments. In particular, regulations promulgated under the Clean Air Act Amendments of 1990 may impose additional compliance requirements that could affect the Company's operations. However, it is impossible to predict accurately the effect, if any, of the Clean Air Act Amendments on the Company at this time. The Company may in the future be subject to civil or administrative enforcement actions for failure to comply strictly with air regulations or permits. These enforcement actions are generally resolved by payment of monetary fines and correction of any identified deficiencies. Alternatively, regulatory agencies could require the Company to forego construction or operation of certain air emission sources.
OSHA. The Company is subject to the requirements of the federal Occupational Safety and Health Act ("OSHA") and comparable state statutes. The OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act and similar state statutes require the Company to organize information about hazardous materials used 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 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 $5 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 $25 million umbrella policy. The Company and its subsidiaries carry workers' compensation insurance in all states in which they operate. 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 344 full-time employees as of June 30, 1996 of which 68 were involved in the oil and gas service operations of the Company. The sale of the oil and gas service operations as of June 30, 1996 resulted in a transfer of the service employees to the purchaser. No employees are represented by organized labor unions. The Company considers its employee relations to be good.
FACILITIES
The Company owns 11 buildings totaling approximately 74,000 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, Texas and in Lafayette, Louisiana.
GLOSSARY
The terms defined in this section are used throughout this Form 10-K.
BCF. Billion cubic feet.
BCFE. Billion cubic feet of gas equivalent.
BBL. One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in reference to crude oil or other liquid hydrocarbons.
BTU. British thermal unit, which is the heat required to raise the temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.
COMMERCIAL WELL; COMMERCIALLY PRODUCTIVE WELL. An oil and gas well which produces oil and gas in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.
DEVELOPED ACREAGE. The number of acres which are allocated or assignable to producing wells or wells capable of production.
DEVELOPMENT WELL. A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.
DRY HOLE; DRY WELL. A well found to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well.
EXPLORATORY WELL. A well drilled to find and produce oil or gas in an unproved area, to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir or to extend a known reservoir.
FARMOUT. An assignment of an interest in a drilling location and related acreage conditional upon the drilling of a well on that location.
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.
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.
ITEM 2.
ITEM 2. PROPERTIES
OIL AND GAS RESERVES
The tables below set forth information as of June 30, 1996 with respect to the Company's estimated net proved reserves, the estimated future net revenue therefrom and the present value thereof at such date, based on estimates prepared by Williamson Petroleum Consultants, Inc. ("Williamson") and the Company's petroleum engineers. The reserves evaluated internally by the Company constituted 0.6% of total proved reserves for fiscal 1996. The estimates were prepared based upon a review of production histories and other geologic, economic, ownership and engineering data developed by the Company. The present value of estimated future net revenue shown is not intended to represent the current market value of the estimated oil and gas reserves owned by the Company. For further information concerning the present value of future net revenue from these proved reserves, see Note 10 of Notes to the Company's Consolidated Financial Statements included in Item 8.
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(a) Estimated future net revenue represents estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development costs, using prices and costs in effect at June 30, 1996. The amounts shown do not give effect to non-property related expenses, such as general and administrative expenses, debt service and future income tax expense or to depreciation, depletion and amortization. The prices used in the Williamson report yield average prices of $20.90 per barrel of oil and $2.41 per Mcf of gas.
The future net revenue attributable to the Company's estimated proved undeveloped reserves of $454.8 million at June 30, 1996, and the $305 million present value thereof, have been calculated assuming that the Company will expend approximately $135.6 million to develop these reserves through June 30, 2000. The amount and timing of these expenditures will depend on a number of factors, including actual drilling results, product prices and the availability of capital.
No estimates of proved reserves comparable to those included herein have been included in reports to any federal agency other than the Securities and Exchange Commission.
The Company's interest used in calculating proved reserves and the estimated future net revenue therefrom was determined after giving effect to the assumed maximum participation by other parties to the Company's farmout and participation agreements. The prices used in calculating the estimated future net revenue attributable to proved reserves do not necessarily reflect market prices for oil and gas production sold subsequent to June 30, 1996. There can be no assurance that all of the estimated proved reserves will be produced and sold at the assumed prices or that existing contracts will be honored or judicially enforced.
There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond the control of the producer. The reserve data set forth herein represent only estimates. Reserve engineering is a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact way, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, estimates made by different engineers often vary. In
addition, results of drilling, testing and production subsequent to the date of an estimate may justify revision of such estimates, and such revisions may be material. Accordingly, reserve estimates are often different from the actual quantities of oil and gas that are ultimately recovered. Furthermore, the estimated future net revenue from proved reserves and the present value thereof are based upon certain assumptions, including prices, future production levels and cost, that may not prove correct. Predictions about prices and future production levels are subject to great uncertainty, and this is particularly true as to proved undeveloped reserves, which are inherently less certain than proved developed reserves and which comprise a significant portion of the Company's proved reserves.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
The Company is involved in ordinary routine litigation incidental to its business. There are presently no material pending legal proceedings to which the Company is a party or of which any of its property is subject.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matters were submitted to a vote of the Company's security holders during the fourth quarter of the Company's fiscal year ended June 30, 1996.
PART II
ITEM 5.
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
PRICE RANGE OF COMMON STOCK
The Common Stock was quoted through the Nasdaq National Market under the symbol "CSPK" from February 4, 1993 through April 27, 1995. On April 28, 1995 the Common Stock began trading on the New York Stock Exchange under the symbol "CHK." The following table sets forth, for the periods indicated, the high and low sales prices per share (adjusted for a 2-for-1 stock split on December 16, 1994 and 3-for-2 stock splits on December 15, 1995 and June 28, 1996) of the Common Stock as reported by the Nasdaq National Market through April 27, 1995, and the New York Stock Exchange thereafter:
At August 31, 1996 there were 167 holders of record of Common Stock and approximately 7,815 beneficial owners.
DIVIDENDS
The Company has never paid cash dividends on its Common Stock. The Company's policy is to retain its earnings to support the growth of the Company's business. The Board of Directors of the Company does not intend to pay cash dividends on the Company's Common Stock in the foreseeable future. The payment of future cash dividends, if any, will be reviewed periodically by the Board of Directors and will depend upon,
among other things, the Company's financial condition, funds from operations, the level of its capital and development expenditures, its future business prospects and any restrictions imposed by the Company's present or future credit facilities.
The Indentures governing the Company's outstanding Senior Notes and its revolving bank credit facility contain certain restrictions on the Company's ability to declare and pay dividends. The revolving credit facility prohibits the Company from declaring or paying any dividends in respect of its Common Stock unless the lender otherwise consents in writing. Under the Indentures, the Company may not pay any cash dividends in respect of its Common Stock if (i) a default or an event of default has occurred and is continuing at the time of or immediately after giving effect to the dividend payment, (ii) the Company would not be able to incur at least $1 of additional indebtedness under the terms of the Indentures, or (iii) immediately after giving effect to the dividend payment, the aggregate of all Restricted Payments (as defined) declared or made after the respective issue dates of the notes exceeds the sum of specified income, proceeds from the issuance of stock and debt by the Company and other amounts from the quarter in which the respective note issuances occurred to the quarter immediately preceding the date of the dividend payment.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA
The following table sets forth selected consolidated financial data of the Company for each of the five fiscal years ended June 30, 1996. The data is derived from the Consolidated Financial Statements of the Company, including the Notes thereto, appearing elsewhere in this report. The data set forth in this table should be read in conjunction with "Management's Discussion and Analysis of Financial Condition and Results of Operations" and the Consolidated Financial Statements, including the Notes thereto included elsewhere in this report.
ITEM 7.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
OVERVIEW
Chesapeake's revenue, net income, operating cash flow, and production reached record levels in 1996. Increased cash flow from operations, in combination with the issuance of $120 million of 9.125% Senior Notes and the sale of 3 million shares of common stock in April 1996, allowed the Company to fund its net capital expenditures of $344 million. The Company also repaid all amounts outstanding under its $125 million Revolving Credit Facility and currently has $75 million of available bank credit committed under this expanded credit facility.
During fiscal 1996, the Company participated in 148 gross wells (69.0 net), of which 111 were operated by the Company. The Company's proved reserves increased by 183 Bcfe to 425 Bcfe as a result of this drilling and the purchase of proved reserves from Amerada Hess Corporation compared to 60.2 Bcfe of production, resulting in reserve replacement in excess of 300% compared to production.
The Company's business strategy has continued to emphasize the acquisition of large prospective leasehold positions to provide a multi-year inventory of drilling locations. By June 1996, the Company had increased its acreage position to approximately 200,000 gross acres of developed leasehold and approximately 2 million gross acres of undeveloped leasehold. During 1996, the Company continued the expansion of its exploration focus in the Louisiana Austin Chalk Trend and began a significant acreage acquisition program in the Williston Basin. The Company also conducted or participated in 3-D seismic programs in the Lovington area, the Giddings Field, the Knox Field and in the Williston and Arkoma Basin areas to evaluate the Company's acreage inventory.
The following table sets forth certain operating data of the Company for the periods presented:
RESULTS OF OPERATIONS
General. For the fiscal year ended June 30, 1996, the Company realized net income of $23.4 million, or $0.80 per common share, on total revenues of $149.4 million. This compares to net income of $11.7 million, or $0.42 per common share, on total revenues of $67.3 million in 1995, and net income of $3.9 million, or $0.16
per common share, on total revenues of $29.8 million in fiscal 1994. The significantly higher earnings in 1996 as compared to 1995 and 1994 were largely the result of higher production and prices per Mcfe, partially offset by higher oil and gas depreciation, depletion and amortization and higher interest costs.
Oil and Gas Sales. During fiscal 1996, oil and gas sales increased 94% to $110.8 million versus $57.0 million for fiscal 1995 and 395% from the fiscal 1994 amount of $22.4 million. The increase in oil and gas sales resulted primarily from strong growth in production volumes. For fiscal 1996, the Company produced 60.2 Bcfe, at a weighted average price of $1.84 per Mcfe, compared to 31.9 Bcfe produced in fiscal 1995 at a weighted average price of $1.78 per Mcfe, and 10.2 Bcfe produced in fiscal 1994 at a weighted average price of $2.21 per Mcfe. This represents production growth of 89% for fiscal 1996 compared to 1995 and 490% compared to 1994.
These increases in production volumes reflect the Company's successful exploration and development program. The following table shows the Company's production by major field area for fiscal 1996 and fiscal 1995:
The Company's gas production represented approximately 86% of the Company's total production volume on an equivalent basis in fiscal 1996. This is compared to 79% in fiscal 1995 and 68% in 1994. This is a result of the Company's drilling in deeper, more gas-prone areas of the Giddings and Knox Fields.
For fiscal 1996, the Company realized an average price per barrel of oil of $17.85, compared to $17.36 in fiscal 1995 and $15.09 in fiscal 1994. 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. The Company realized $0.9 million less in oil revenues than it would have received from unhedged market prices in fiscal 1996.
Gas price realizations increased from fiscal 1995 to 1996 by approximately 12%, despite lower gas revenue realized by the Company during the fourth fiscal quarter of 1996 as a result of the hedging activity. As a result of hedging, the Company had gas revenues during that period that were approximately $5.1 million less than unhedged market prices. Although gas prices generally increased during 1996, the weighted average realization per Mcf in 1996 was still 19% less than 1994. The lower prices realized in 1995 were the result of lower natural gas prices, and the fact that an increased portion of the Company's gas production was from areas that contain leaner gas that is either not processed for liquids or contains less energy value (Btu's) per Mcf. The Company anticipates gas production in Louisiana will receive premium prices at least equivalent to Henry Hub indexes due to the high Btu content and favorable market location of the production.
Gas Marketing Sales. In December 1995, the Company entered into the gas marketing business by acquiring all of the outstanding stock of an Oklahoma City-based natural gas marketing company for total consideration of $725,000. This subsidiary provides natural gas marketing services including commodity price structuring, contract administration and nomination services for the Company, its partners and other natural gas producers in the geographical areas in which the Company is active.
As a result of this purchase, the Company realized $28.4 million in gas marketing sales for third parties in fiscal 1996, with corresponding costs of gas marketing sales of $27.5, resulting in a gross margin of $0.9 million. There were no gas marketing activities in 1995 or 1994.
Oil and Gas Service Operations. Revenues from oil and gas service operations were $6.3 million in fiscal 1996, down 28% from $8.8 million in fiscal 1995, and down 2% from $6.4 million in 1994. The related costs and expenses of these operations were $4.9 million, $7.7 million and $5.2 million for the three years ended June 30, 1996, 1995 and 1994, respectively. The gross profit margin of 22% in fiscal 1996 was up from the 12% margin in fiscal 1995, and up slightly from the 19% gross margin in fiscal 1994. The gross profit margin derived from these operations is a function of drilling activities in the period, costs of materials and supplies and the mix of operations between lower margin trucking operations versus higher margin labor oriented service operations.
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 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. 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 will be accounted for using the equity method.
Interest and Other. Interest and other income for fiscal 1996 was $3.8 million which compares to $1.5 million in 1995 and $1 million in 1994. 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 and 1994, 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 $8.3 million in fiscal 1996, as compared to $4.3 million in fiscal 1995, and $3.6 million in fiscal 1994. 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 $0.14 per Mcfe as compared to $0.13 per Mcfe in fiscal 1995 and $0.36 per Mcfe in 1994. Severance tax exemptions for production were available in fiscal 1996 and 1995, and certain of the exemptions in Giddings are applicable for production through 2001 for wells spud prior to September 1, 1996 and on a more limited basis for qualifying wells spud thereafter. The Company expects that operating costs in fiscal 1997 will increase based on the Company's expansion of drilling efforts into the Louisiana Trend and the Williston Basin, because both are oil prone areas which generally have higher operating costs than gas prone areas and because limited severance tax exemptions will be applicable in these areas as compared to existing exemptions in Giddings.
Depreciation, Depletion and Amortization. Depreciation, depletion and amortization ("DD&A") of oil and gas properties for fiscal 1996 was $50.9 million, $25.5 million higher than fiscal 1995's expense of $25.4 million, and $42.8 million higher than fiscal 1994's expense of $8.1 million. The average DD&A rate per Mcfe, which is a function of capitalized costs, future development costs, and the related underlying reserves in the periods presented, increased to $0.85 in fiscal 1996 compared to $0.80 in fiscal 1995 and 1994. 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 could trend upward in 1997 based on projected higher finding costs for the Louisiana Trend.
Depreciation and Amortization of Other Assets. Depreciation and amortization ("D&A") of other assets increased to $3.2 million in fiscal 1996, compared to $1.8 million in fiscal 1995, and $1.9 million in 1994. This increase in fiscal 1996 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 the
Senior Notes in May 1995 and in April 1996. The Company anticipates an increase in D&A in fiscal 1997 as a result of a full year of debt issuance cost amortization on the 9.125% Senior Notes issued in April 1996 and higher building depreciation expense on the Company's corporate offices, offset by a reduction in depreciation expense associated with the sale of the service company assets.
General and Administrative. General and administrative ("G&A") expenses, which are net of capitalized internal payroll and non-payroll expenses (see Note 10 of Notes to Consolidated Financial Statements), were $4.8 million in fiscal 1996, up 33% from $3.6 million in fiscal 1995, and up from $3.1 million in fiscal 1994. The increases in fiscal 1996 compared to 1995 and 1994 result primarily from increased personnel expenses required by the Company's growth. The Company capitalized $1.7 million of internal costs in fiscal 1996 directly related to the Company's oil and gas exploration and development efforts, as compared to $0.6 million in 1995 and $1.0 million in 1994. The Company anticipates that G&A costs for fiscal 1997 will increase by approximately 25% as a result of the Company's continued growth and increased budgets for exploration and development activities, increasing operations activities, and attendant personnel and overhead requirements.
Interest and Other. Interest and other expense increased to $13.7 million in fiscal 1996 as compared to $6.6 million in 1995 and $2.7 million in fiscal 1994. Interest expense in the fourth quarter of fiscal 1996 was approximately $4 million, reflecting the issuance of $120 million of 9.125% Senior Notes in April 1996. In addition to the interest expense reported, the Company capitalized $6.4 million of interest during fiscal 1996, as compared to $1.6 million capitalized in 1995 and $0.4 million in 1994. Interest expense will increase significantly in fiscal 1997 as compared to 1996 as a result of the 9.125% Senior Notes issued in April 1996.
Income Tax Expense. The Company recorded income tax expense of $12.9 million in fiscal 1996, as compared to $6.3 million in fiscal 1995, and $1.3 million in 1994. All of the income tax expense in 1996 was deferred due to a current year tax net operating loss resulting from the Company's active drilling program. A substantial portion of the Company's drilling costs are currently deductible for income tax purposes. The effective tax rate was approximately 35.5% in fiscal 1996 compared to a tax rate of 35% in 1995 and 24% in 1994. The Company anticipates an effective tax rate of between 36 and 36.5% for fiscal 1997 as a result of Louisiana state taxes and higher activity levels in Louisiana. Based upon the anticipated level of drilling activities in fiscal 1997, the Company anticipates that substantially all of its fiscal 1997 income tax expense will be deferred.
Hedging. Periodically the Company utilizes hedging strategies to hedge the price of a portion of its future oil and gas production. These strategies include swap arrangements that establish an index-related price above which the Company pays the hedging partner and below which the Company is paid by the hedging partner, the purchase of index-related puts that provide for a "floor" price to the Company to be paid by the counter-party to the extent the price of the commodity is below the contracted floor, and basis protection swaps. Recognized gains and losses on hedge contracts are reported as a component of the related transaction. Results from hedging transactions are reflected in oil and gas sales to the extent related to the Company's oil and gas production.
As of June 30, 1996, the Company had NYMEX-based crude oil swap agreements for 1,000 Bbl per day for July 1, 1996 through August 31, 1996 at an average price of $17.85 per Bbl. The counter-party has the option exercisable monthly for an additional 1,000 Bbl per day for the period July 1, 1996 through December 31, 1996 to cause a swap if the price exceeds an average $17.74 per Bbl. The actual settlements for July and August resulted in a $0.5 million payment to the counter-party. The Company estimates, based on NYMEX prices as of August 30, 1996, that the effect of the September through December hedges would be a $0.4 million payment to the counter-party.
The Company has purchased Houston Ship Channel put options which guarantee the Company an average floor price of $2.21/Mmbtu for 20,000 Mmbtu per day for the period of November 1, 1996 through February 28, 1997. The average cost of these puts was $0.14 per Mmbtu.
As of June 30, 1996, the Company had NYMEX-based natural gas swaps and NYMEX/Houston Ship Channel Basis swaps for the months of July through October, 1996. These transactions resulted in payments to the Company's counter-party of approximately $2 million for the month of July 1996 and $1.5 million for
the month of August 1996. The Company estimates, based on NYMEX prices as of August 30, 1996, that the effect of the September and October hedges would be a $0.2 million payment to the counter-party.
The Company has only limited involvement with derivative financial instruments, as defined in SFAS 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 to its counter-parties and to basis risk.
LIQUIDITY AND CAPITAL RESOURCES
FINANCING ACTIVITIES
On April 9, 1996 the Company completed a public offering of 2,475,000 shares of Common Stock at a price of $35.33 per share resulting in net proceeds to the Company of approximately $82.1 million. On April 12, 1996, the underwriters exercised an over-allotment option to purchase an additional 519,750 shares of Common Stock at a price of $35.33 per share, resulting in additional net proceeds to the Company of approximately $17.3 million.
On April 9, 1996 the Company also concluded the sale of $120 million of 9.125% Senior Notes due 2006 (the "9.125% Senior Notes"), which offering resulted in net proceeds to the Company of approximately $116 million. The 9.125% Senior Notes were issued at 99.931% of par. Approximately $44 million of the proceeds of these offerings was used to retire all amounts outstanding under the Company's revolving credit facility. 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 the proceeds of any equity offering. 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.
In fiscal 1995, cash flows from financing activities were $97.3 million, largely as the result of issuance of $90 million of 10.5% Senior Notes due 2002 (the "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 prior to June 1, 1998 up to $30 million of the 10.5% Senior Notes with the proceeds of an equity offering at 110% of the principal amount thereof.
In fiscal 1994, the Company received proceeds from long term borrowings of $48.8 million, primarily from the issuance of $47.5 million of 12% Senior Notes due 2001 (the "12% Senior Notes") and warrants to purchase 2,190,937 shares of the Company's Common Stock at an aggregate exercise price of $4,870. The 12% Senior Note Indenture provides for mandatory redemption of $11.9 million on each of March 1, 1998, 1999 and 2000. The 12% Senior Notes are redeemable at the option of the Company at any time on or after March 1, 1998.
All of the Company's subsidiaries except Chesapeake Gas Development Corporation ("CGDC") and Chesapeake Energy Marketing, Inc. ("CEMI") have fully and unconditionally guaranteed on a joint and several basis all three issues of Senior Notes, and the securities of the guaranteeing subsidiaries have been pledged to secure obligations under the 12% Senior Notes. See Note 2 of Notes to the Company's Consolidated Financial Statements included in Item 8
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors and Stockholders of Chesapeake Energy Corporation
We have audited the accompanying consolidated balance sheet of Chesapeake Energy Corporation and its subsidiaries as of June 30, 1996, and the related consolidated statements of income, stockholders' equity and cash flows for the year 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 audit.
We conducted our audit in accordance with generally accepted auditing standards. Those standards 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. 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 audit provides 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, 1996, and the consolidated results of their operations and their cash flows for the year then ended in conformity with generally accepted accounting principles.
COOPERS & LYBRAND L.L.P.
Oklahoma City, Oklahoma September 13, 1996
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors and Stockholders of Chesapeake Energy Corporation
In our opinion, the consolidated balance sheet and the related consolidated statements of income, of cash flows and of stockholders' equity as of and for each of the two years in the period ended June 30, 1995 present fairly, in all material respects, the financial position, results of operations and cash flows of Chesapeake Energy Corporation and its subsidiaries as of and for each of the two years in the period 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 audits. We conducted our audits of these statements in accordance with generally accepted auditing standards which 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, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for the opinion expressed above. We have not audited the consolidated financial statements of Chesapeake Energy Corporation for any period subsequent to June 30, 1995.
PRICE WATERHOUSE LLP
Houston, Texas September 20, 1995, except for Note 9 which is as of September 23, 1996
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
ASSETS
The accompanying notes are an integral part of these consolidated financial statements.
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
The accompanying notes are an integral part of these consolidated financial statements.
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
The accompanying notes are an integral part of these consolidated financial statements.
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, 1996, 1995 and 1994 were $3,156,000, $6,513,000 and $5,952,000, respectively. No cash consideration is exchanged for inventory under this financing arrangement until actual draws on the inventory are made.
In fiscal 1996 and 1995, the Company recognized income tax benefits of $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 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 March 31, 1994, the Company issued 8,000 units (see Note 2) to Trust Company of the West ("TCW") primarily in consideration for the surrender of 576,923 shares of the Company's 9% convertible preferred stock, including its rights to dividends, warrants to purchase Common Stock and an overriding royalty interest.
In February 1994, pending litigation was settled pursuant to an agreement requiring COI to pay $1.25 million, of which $250,000 plus interest was paid in July 1994, and the balance of which was paid in June 1995.
The accompanying notes are an integral part of these consolidated financial statements.
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
The accompanying notes are an integral part of these consolidated financial statements.
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Principles of Consolidation
The accompanying consolidated financial statements of Chesapeake Energy Corporation (the "Company" or "Parent") include the accounts of Chesapeake Operating, Inc. ("COI"), Chesapeake Exploration Limited Partnership ("CEX"), a limited partnership, Chesapeake Gas Development Corporation ("CGDC"), Chesapeake Energy Marketing, Inc. ("CEMI"), Lindsay Oil Field Supply, Inc. ("LOF"), Sander Trucking Company, Inc. ("STCO") and subsidiaries of those entities. All significant intercompany accounts and transactions have been eliminated.
In December 1995, the Company entered into the gas marketing business by acquiring all of the outstanding stock of an Oklahoma City-based natural gas marketing company for total consideration of $725,000. This subsidiary was subsequently named CEMI. CEMI provides natural gas marketing services including commodity price structuring, contract administration and nomination services for the Company, its partners and other natural gas producers in the geographical areas in which the Company is active.
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.
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.
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. The average composite rates used for depreciation, depletion and amortization were $0.85, $0.80 and $0.80 per equivalent Mcf in 1996, 1995, and 1994, 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. Unamortized costs as reduced by related deferred taxes are subject to a ceiling which limits such amounts to the estimated present value of oil and gas reserves, reduced by operating expenses, future development costs and income taxes. The costs of unproved properties are excluded from amortization until the properties are evaluated.
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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 $35 million, subject to adjustment for activity after the effective date of January 1, 1996. The properties are located in the Knox and Golden Trend fields of southern Oklahoma, most of which are operated by the Company.
Other Property and Equipment
Other property and equipment primarily consists of vehicles, 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
Included in other property and equipment in the consolidated balance sheets is computer equipment and software held under capital leases. Minimum lease payments under these capital leases and other operating leases are as follows:
Capitalized Interest
During fiscal 1996, 1995 and 1994, interest of approximately $6,428,000, $1,574,000 and $356,000 was capitalized on significant investments in unproved properties that are not being currently depreciated, depleted, or amortized and on which exploration or development activities are in progress.
Service Operations
Certain subsidiaries of the Company performed contractual services on wells the Company operates 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 income 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 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 the industry. The Company sold its
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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 will be 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 Per Share
Primary and fully diluted earnings 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.
Gas Imbalances
The Company follows the "sales method" of accounting for its oil and gas revenue whereby the Company recognizes sales revenue on all oil or gas sold to its purchasers, regardless of whether the sales are proportionate to the Company's ownership in the property. A liability is recognized only to the extent that the Company has a net imbalance in excess of the reserves on the underlying properties. The Company's net imbalance positions at June 30, 1996 and 1995 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.
Debt Issue Costs
Other assets relate primarily to debt issue costs associated with the issuance of the 12% Senior Notes on March 31, 1994, the 10.5% Senior Notes on May 25, 1995, and the 9.125% Senior Notes on April 9, 1996 (see Note 2). The remaining unamortized costs on these issuances of Senior Notes at June 30, 1996 totaled $8.7 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 plans to continue to retain its current method of accounting for stock compensation and adopt the disclosure requirements of this Statement in fiscal 1997.
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Reclassifications
Certain reclassifications have been made to the consolidated financial statements for the years ended June 30, 1995 and 1994 to conform to the presentation used for the June 30, 1996 consolidated financial statements.
2. SENIOR NOTES
On April 9, 1996, the Company completed an offering of $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 at the redemption or make-whole prices set forth in the indenture. 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 completed a private offering of $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 any time prior to June 1, 1998 up to $30 million of the 10.5% Senior Notes at 110% of the principal amount thereof with the proceeds of an equity offering. In September 1995, the Company exchanged the 10.5% Senior Notes for substantially identical notes in a registered exchange offer (also referred to as the "10.5% Senior Notes").
On March 31, 1994, the Company completed a private offering of 47,500 Units consisting of an aggregate of $47.5 million principal amount of 12% Senior Notes due 2001 ("12% Senior Notes") and warrants ("Warrants") to purchase 2,190,937 shares of the Company's Common Stock at an aggregate exercise price of $4,870. The Warrants were valued at $3 million creating a discount on the 12% Senior Notes. All of the Warrants were subsequently exercised. In exchange for 8,000 Units, the Company acquired from Trust Company of the West ("TCW") 576,923 shares of the Company's 9% cumulative convertible preferred stock and all rights to dividends thereon, warrants to purchase 1,404,004 shares of the Company's Common Stock and 50% of an outstanding overriding royalty interest held by TCW. The 12% Senior Notes are redeemable at the option of the Company at any time on or after March 1, 1998 at an initial premium of 106% of the principal amount thereof, declining to no premium in 2000. The Company is required to redeem $11,875,000 principal amount of 12% Senior Notes on each of March 1, 1998, 1999 and 2000. In November 1994, the Company exchanged the 12% Senior Notes for substantially identical notes in a registered exchange offer (also referred to as the "12% Senior Notes").
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 12% Senior Notes, the 10.5% Senior Notes and the 9.125% 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 Notes): COI, LOF, STCO, Whitmire Dozer Service, Inc. and CEX (collectively, the "Subsidiary Guarantors"). The only subsidiaries of the Company that are not Subsidiary Guarantors are CGDC and CEMI (together, the "Non-Guarantor Subsidiaries"). Each of the Subsidiary Guarantors is a direct or indirect wholly-owned subsidiary of the Company. The securities of the Subsidiary Guarantors have been pledged to secure performance of the Company's obligations under the 12% Senior Notes. The only affiliate securities constituting a substantial portion of the collateral for the 12% Senior Notes are the partnership interests in CEX.
The 12%, 10.5% and 9.125% Senior Note Indentures contain certain covenants, including covenants limiting the Company and the Subsidiary Guarantors 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 Subsidiary Guarantors; mergers or consolidations; and transactions with affiliates. The Company is also obligated to repurchase 12%,
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
10.5% and 9.125% Senior Notes if it fails to maintain a specified ratio of assets to debt and in the event of a change of control or certain asset sales.
The Company's bank credit agreement prohibits any distributions by CEX to its partners (the Company and COI) if the maturity of any obligations to the lender has been accelerated. The pledge agreement relating to the 12% Senior Notes requires that all dividends and distributions from Subsidiary Guarantors be paid to the collateral agent thereunder upon an event of default under the 12% Senior Notes Indenture. There are no other restrictions on the payment of cash dividends by Subsidiary Guarantors.
CEX is a limited partnership which is 10% owned by COI, as sole general partner, and 90% owned directly by the Company, as sole limited partner. CEX owns 94% and CGDC owns 6% of the Company's producing oil and gas properties, based on the present value of future net revenue at June 30, 1996 (discounted at 10%).
Set forth below are condensed consolidating financial statements of CEX, the other Subsidiary Guarantors, all Subsidiary Guarantors combined, the Non-Guarantor Subsidiaries and the Company. The CEX limited partnership condensed financial statements were prepared on a separate entity basis as reflected in the Company's books and records and include all material costs of doing business as if the partnership were on a stand-alone basis except that interest is not charged or allocated. No provision has been made for income taxes because the partnership is not a taxpaying entity. Separate audited financial statements of each Subsidiary Guarantor, other than CEX, have not been provided because management has determined that they are not material to investors.
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
CONDENSED CONSOLIDATING BALANCE SHEET
AS OF JUNE 30, 1996 (IN THOUSANDS)
ASSETS
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
CONDENSED CONSOLIDATING BALANCE SHEET
AS OF JUNE 30, 1995 (IN THOUSANDS)
ASSETS
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS ($ IN THOUSANDS)
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS ($ IN THOUSANDS)
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
3. NOTES PAYABLE AND LONG-TERM DEBT
Notes payable and long-term debt consist of the following:
The aggregate scheduled maturities of notes payable and long-term debt for the next five fiscal years ending June 30, 2001 and thereafter were as follows as of June 30, 1996 (in thousands of dollars):
In April 1993, CEX entered into an oil and gas reserve-based reducing revolving credit facility (the "Revolving Credit Facility") with Union Bank. The Revolving Credit Facility has been amended from time to
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
time, most recently in September 1996. Concurrent with the September 1996 amendment, the Company increased the facility size to $125 million and expanded its bank group with Union Bank remaining as agent.
The maturity date of the Revolving Credit Facility is April 30, 2001. The facility provides for interest at the Union Bank reference rate (8.25% at June 30, 1996) or, at the option of the Company the Eurodollar rate plus 1.375% to 1.875% depending on the ratio of the amount outstanding to the borrowing base. Borrowings are collateralized by a first priority lien on substantially all of CEX's proved producing reserves, and are unconditionally guaranteed by the Company. At June 30, 1996 and 1995 there was $0 and $10,000 outstanding under the Revolving Credit Facility, respectively.
The amount of credit available at any time under the Revolving Credit Facility is the lesser of the commitment amount or the borrowing base. The borrowing base is reduced each month by a specified amount. Both the borrowing base and the monthly reduction amount are redetermined by Union Bank each May 1 and November 1 and may be redetermined at any other time upon the request of CEX or Union Bank. To the extent the amount outstanding at any time exceeds the borrowing base, CEX must reduce the amount outstanding or add additional collateral. At June 30, 1996, the commitment amount and the borrowing base under the Revolving Credit Facility were $35 million, and the monthly reduction amount was $700,000. The Revolving Credit Facility was amended in September 1996 to provide for a borrowing base and a commitment amount of $75 million, with a monthly reduction amount of $1,750,000. The Revolving Credit Facility contains customary financial covenants, limitations on indebtedness and liabilities, liens, prepayments of other indebtedness (including the 12%, 10.5% and 9.125% Senior Notes) and loans, investments and guarantees by the Company and prohibits the payment of dividends on the Company's Common Stock.
The Company's wholly-owned subsidiary, CGDC, has a credit facility with Union Bank (the "Term Credit Facility"), with an outstanding balance of $12.9 million at June 30, 1996. Collateral for the Term Credit Facility is limited to CGDC's producing oil and gas properties. The Term Credit Facility has not been guaranteed by the Company or any of its other subsidiaries and is recourse only to the assets of CGDC. CGDC acquired producing oil and gas properties from CEX in December 1994, June 1995 and December 1995 in exchange for $5.5 million, $6 million and $5.3 million in cash, respectively, using proceeds borrowed under this facility. CGDC has not guaranteed the payment of the Company's 12%, 10.5% or 9.125% Senior Notes, nor has the capital stock of CGDC been pledged as collateral for such indebtedness. The terms of the Term Credit Facility prohibit the payment of dividends by CGDC.
4. CONTINGENCIES AND COMMITMENTS
The Company is currently involved in various 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 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 June 30, 1997 through June 30, 1998.
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 environmental issues or claims.
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
5. INCOME TAXES
As discussed in Note 1, the Company has adopted SFAS 109. The components of the income tax provision for each of the periods are as follows:
The effective income tax rate differed from the computed "expected" federal income tax rate on earnings before income taxes for the following reasons:
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:
At June 30, 1996, the Company had regular tax net operating loss carryforwards of approximately $140 million and alternative minimum tax net operating loss carryforwards of approximately $15 million. These loss carryforward amounts will expire during the years 2007 through 2011. The Company also had a percentage depletion carryforward of approximately $2.3 million at June 30, 1996, 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
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
the Internal Revenue Service, the Company does not believe that an Ownership Change has occurred as of June 30, 1996.
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, 1996, 1995 and 1994 the Company had accounts receivable for these costs of $2.9 million, $4.4 million and $1.7 million, respectively.
During fiscal 1996, 1995 and 1994 the Company incurred legal expenses of $347,000, $516,000 and $631,000, respectively, for legal services provided by the law firm of which a director is a member.
7. EMPLOYEE BENEFIT PLANS
Effective October 1, 1989, the Company established a 401(K) profit sharing plan. On December 1, 1993, the Company amended the plan and established the Chesapeake Energy Savings and Incentive Plan. On January 1, 1996 the Company amended the plan and established the Chesapeake Energy Corporation Savings and Incentive Stock Bonus Plan (the "Savings and Incentive Stock Bonus Plan"). Eligible employees may make voluntary contributions to the Savings and Incentive Stock Bonus 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 Savings and Incentive Stock Bonus Plan. The Company may, at its discretion, make additional contributions to the Savings and Incentive Stock Bonus Plan. The Company contributed $187,000, $95,000 and $70,000 to the Savings and Incentive Stock Bonus Plan during the fiscal years ended June 30, 1996, 1995 and 1994, respectively.
8. MAJOR CUSTOMERS
Sales to individual customers constituting 10% or more of total oil and gas sales were as follows:
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.
9. STOCKHOLDERS' EQUITY
On April 9, 1996 the Company completed a public offering of 2,475,000 shares of Common Stock at a price of $35.33 per share, resulting in net proceeds (after offering costs) to the Company of approximately $82.1 million. On April 12, 1996, the underwriters exercised an over-allotment option to purchase an
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
additional 519,750 shares of Common Stock at a price of $35.33 per share, resulting in additional net proceeds (after offering costs) to the Company of approximately $17.3 million. The net proceeds from the offering were used to fund a portion of the Company's exploration and development capital expenditures and for general corporate purposes.
On March 31, 1994, the Company issued 12% Senior Notes and Warrants for 2,190,937 shares of the Company's Common Stock (see Note 2). The Warrants were valued at $3.04 million and are recorded as Common Stock Warrants and paid-in capital on the accompanying consolidated balance sheets. A portion of the 12% Senior Notes and Warrants were issued to Trust Company of the West in exchange for preferred stock, warrants to purchase Common Stock and an overriding royalty interest.
A 1.8-for-1 stock split of the Common Stock in January 1993, a 2-for-1 stock split of the Common Stock in December 1994, and 3-for-2 stock splits of the Common Stock in December 1995 and June 1996 have been given retroactive effect in these financial statements.
Stock Option Plans
Under the Company's 1992 Incentive Stock Option Plan (the "ISO Plan"), options to purchase Common Stock may be granted only to employees of the Company and its subsidiaries. Subject to any adjustment as provided by the ISO Plan, the aggregate number of shares which may be issued and sold may not exceed 1,881,000 shares. The maximum period for exercise of an option may not be more than ten 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 1,566,000 shares. The maximum period for exercise of an option may not be more than ten 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"), 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 1994 Plan, the aggregate number of shares which may be issued and sold may not exceed 2,443,455 shares. The maximum period for exercise of an option may not be more than ten 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.
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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 1996 and 1995, $7,950,000 and $1,229,000 was recorded as an adjustment 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 counter-parties and to basis risk.
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 swap arrangements that establish an index-related price above which the Company pays the hedging partner and below which the Company is paid by the hedging partner, the purchase of index-related puts that provide for a "floor" price to the Company to be paid by the counter-party to the extent the price of the commodity is below the contracted floor, and basis protection swaps.
As of June 30, 1996, the Company had established NYMEX-based crude oil swap agreements for 1,000 Bbl per day for July 1, 1996 through August 31, 1996 at an average price of $17.85 per Bbl. The counter-party has the option exercisable monthly for an additional 1,000 Bbl per day for the period July 1, 1996 through December 31, 1996 to cause a swap if the price exceeds an average $17.74 per Bbl. The actual settlements for July and August resulted in a $0.5 million payment to the counter-party. The Company estimates, based on NYMEX prices as of August 30, 1996, that the effect of the September through December hedges would be a $0.4 million payment to the counter-party.
The Company has purchased Houston Ship Channel put options which guarantee the Company an average floor price of $2.21/Mmbtu for 20,000 Mmbtu per day for the period of November 1, 1996 through February 28, 1997. The average cost of these puts was $0.14 per Mmbtu.
As of June 30, 1996, the Company had NYMEX-based natural gas swaps and NYMEX/Houston Ship Channel Basis swaps for the months of July through October 1996. These transactions resulted in payments to
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
the Company's counter-party of approximately $2 million for the month of July 1996 and $1.5 million for the month of August 1996. The Company estimates, based on NYMEX prices as of August 30, 1996, that the effect of the September and October hedges would be a $0.2 million payment to the counter-party.
Concentration of Credit Risk
Financial instruments which potentially subject the Company to concentrations of credit risk consist principally of trade receivables. The Company's accounts receivable are primarily from purchasers of oil and natural gas products and exploration and production companies which own interests in properties operated by the Company. The industry concentration has the potential to impact the Company's overall exposure to credit risk, either positively or negatively, in that the customers may be similarly affected by changes in economic, industry or other conditions. The Company generally requires letters of credit for receivables from customers which are not considered investment grade, unless the credit risk can otherwise be mitigated.
Fair Value of Financial Instruments
The following disclosure of the estimated fair value of financial instruments is made in accordance with the requirements of Statement of Financial Accounting Standards No. 107, "Disclosures About Fair Value of Financial Instruments." The estimated fair value amounts have been determined by the Company using available market information and valuation methodologies. Considerable judgment is required in interpreting market data to develop the estimates of fair value. The use of different market assumptions or valuation methodologies may have a material effect on the estimated fair value amounts.
The carrying values of items comprising current assets and current liabilities approximate fair values due to the short-term maturities of these instruments. The Company estimates the fair value of its long-term, fixed-rate debt using quoted market prices. The Company's carrying amount for such debt at June 30, 1996 and 1995 was $255.6 million and $135.2 million, respectively, compared to approximate fair values of $261.2 million and $137.8 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:
Unproved properties not subject to amortization at June 30, 1996 and 1995, consist mainly of lease acquisition costs. The Company capitalized approximately $6,428,000 and $1,574,000 of interest during the years ended June 30, 1996 and 1995 on significant investments in unproved properties that are not being currently depreciated, depleted, or amortized and on which exploration or development activities are 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.
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:
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, 1996, 1995 and 1994, 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.
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(a) Production costs include lease operating expenses and production taxes.
(b) The imputed income tax provision is hypothetical and determined without regard to the Company's deduction for general and administrative expenses, interest costs and other income tax credits and deductions.
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") as of June 30, 1996, 1995 and 1994 and the Company's petroleum engineers as of June 30, 1996 and 1995. The reserves evaluated internally by the Company constituted approximately 0.6% and 0.5% of total proved reserves as of June 30, 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
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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.
Presented below is a summary of changes in estimated reserves of the Company based upon the reports prepared by Williamson for 1996, 1995 and 1994, along with those prepared by the Company's petroleum engineers for 1996 and 1995:
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 $35 million, subject to adjustment for activity after the effective date of January 1, 1996. The properties are located in the Knox and Golden Trend fields of southern Oklahoma, most of which are operated by the Company.
In October 1993, the Company entered into a joint development agreement covering a 20,000 gross acre development area in the Fayette County portion of the Giddings Field in southern Texas. The Company's ownership interests in the proved undeveloped properties covered by the joint development agreement were significantly less than those used in the June 30, 1993 reserve report. The impact of the reduced ownership percentages is reflected as sales of reserves in place in fiscal 1994 in the preceding table.
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
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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:
The principal sources of change in the standardized measure of discounted future net cash flows are as follows:
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
12. QUARTERLY FINANCIAL DATA (unaudited)
Summarized unaudited quarterly financial data for fiscal 1996 and 1995 are as follows ($ in thousands except per share data):
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(a) Total revenue excluding interest and other income, less total costs and expenses excluding interest and other expense.
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
Effective July 1, 1996, Price Waterhouse LLP sold its Oklahoma City practice to Coopers & Lybrand L.L.P. and resigned as the Company's independent accountants. The Company's decision to change independent accountants and retain Coopers & Lybrand L.L.P. was approved by the Audit Committee of the Board of Directors and by the Board of Directors. During the period Price Waterhouse LLP was engaged by the Company, Price Waterhouse LLP did not issue any report on the Company's financial statements containing an adverse opinion, disclaimer of opinion, or qualification. There were no disagreements between the Company and Price Waterhouse LLP on any matter of accounting principles or practices, financial statement disclosure or auditing scope or procedure, nor were there any reportable events.
PART III
ITEM 10.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The information called for by this Item 10 is incorporated herein by reference to the definitive Proxy Statement to be filed by the Company pursuant to Regulation 14A of the General Rules and Regulations under the Securities Exchange Act of 1934 not later than October 28, 1996.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
The information called for by this Item 11 is incorporated herein by reference to the definitive Proxy Statement to be filed by the Company pursuant to Regulation 14A of the General Rules and Regulations under the Securities Exchange Act of 1934 not later than October 28, 1996.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The information called for by this Item 12 is incorporated herein by reference to the definitive Proxy Statement to be filed by the Company pursuant to Regulation 14A of the General Rules and Regulations under the Securities Exchange Act of 1934 not later than October 28, 1996.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information called for by this Item 13 is incorporated herein by reference to the definitive Proxy Statement to be filed by the Company pursuant to Regulation 14A of the General Rules and Regulations under the Securities Exchange Act of 1934 not later than October 28, 1996.
PART IV
ITEM 14.
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. The Financial Statements of Chesapeake Exploration Limited Partnership are included in this Item 14. Reference is made to the accompanying Index to Chesapeake Exploration Limited Partnership Financial Statements.
3. Exhibits. The following exhibits are filed herewith pursuant to the requirements of Item 601 of Regulation S-K:
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* Filed herewith.
+ Management contract or compensatory plan or arrangement.
(b) Reports on Form 8-K
During the quarter ended June 30, 1996, the Company filed a Current Report on Form 8-K dated April 30, 1996 (filed on May 15, 1996) reporting the acquisition of interest in certain producing and nonproducing oil and gas properties from Amerada Hess Corporation. Form 8-K/A was filed July 15, 1996 to add financial information to such Current Report.
INDEX TO CHESAPEAKE EXPLORATION LIMITED PARTNERSHIP FINANCIAL STATEMENTS
REPORT OF INDEPENDENT ACCOUNTANTS
To the General Partner and Limited Partner of Chesapeake Exploration Limited Partnership
We have audited the accompanying balance sheet of Chesapeake Exploration Limited Partnership ("CEX") as of June 30, 1996, and the related consolidated statements of income, partners' capital and cash flows for the year then ended. These financial statements are the responsibility of the CEX management. Our responsibility is to express an opinion on these financial statements based on our audit.
We conducted our audit in accordance with generally accepted auditing standards. Those standards 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. 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 audit provides a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of CEX as of June 30, 1996, and the results of its operations and its cash flows for the year then ended in conformity with generally accepted accounting principles.
As more fully described in Note 1, CEX is a limited partnership owned by Chesapeake Energy Corporation ("CEC") and Chesapeake Operating, Inc. ("COI"). CEX has no employees and it is dependent on the financial resources of CEC and COI as well as being dependent on management by COI. Accordingly, CEX has significant transactions with CEC and COI which are disclosed in Note 4. The financial statements of CEX should be read in conjunction with the consolidated financial statements of CEC.
COOPERS & LYBRAND L.L.P.
Oklahoma City, Oklahoma September 13, 1996
REPORT OF INDEPENDENT ACCOUNTANTS
To the General Partner and Limited Partner of Chesapeake Exploration Limited Partnership
In our opinion, the balance sheet and the related statements of income, of partners' capital and of cash flows as of and for each of the two years in the period ended June 30, 1995 present fairly, in all material respects, the financial position, results of operations and cash flows of Chesapeake Exploration Limited Partnership ("CEX" formerly Chesapeake Exploration Company) as of and for each of the two years in the period ended June 30, 1995, in conformity with generally accepted accounting principles. These financial statements are the responsibility of CEX's management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with generally accepted auditing standards which require that we plan and perform the 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, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for the opinion expressed above. We have not audited the financial statements of CEX for any period subsequent to June 30, 1995.
As more fully described in Note 1, CEX is a limited partnership owned by Chesapeake Energy Corporation ("CEC") and Chesapeake Operating, Inc. ("COI"). CEX has no employees and it is dependent on the financial resources of CEC and COI as well as being dependent on management by COI. Accordingly, CEX has significant transactions with CEC and COI which are disclosed in Note 4. The financial statements of CEX should be read in conjunction with the consolidated financial statements of CEC.
PRICE WATERHOUSE LLP
Houston, Texas September 20, 1995
CHESAPEAKE EXPLORATION LIMITED PARTNERSHIP (A WHOLLY-OWNED PARTNERSHIP OF CHESAPEAKE ENERGY CORPORATION)
BALANCE SHEETS
ASSETS
The accompanying notes are an integral part of these financial statements.
CHESAPEAKE EXPLORATION LIMITED PARTNERSHIP (A WHOLLY-OWNED PARTNERSHIP OF CHESAPEAKE ENERGY CORPORATION)
STATEMENTS OF INCOME
The accompanying notes are an integral part of these financial statements.
CHESAPEAKE EXPLORATION LIMITED PARTNERSHIP (A WHOLLY-OWNED PARTNERSHIP OF CHESAPEAKE ENERGY CORPORATION)
STATEMENTS OF PARTNERS' CAPITAL
The accompanying notes are an integral part of these financial statements.
CHESAPEAKE EXPLORATION LIMITED PARTNERSHIP (A WHOLLY-OWNED PARTNERSHIP OF CHESAPEAKE ENERGY CORPORATION)
STATEMENTS OF CASH FLOWS
SUPPLEMENTAL SCHEDULE OF NON-CASH INVESTING AND FINANCING ACTIVITIES:
During the three years ended June 30, 1996, CEX had non-cash intercompany transactions with the Company consisting primarily of allocated general and administrative expenses. In fiscal 1996 and 1995, the difference between the net book value and the proceeds from the sale of oil and gas properties sold to CGDC of $782,000 and $2,852,000, respectively, resulted in a non-cash transfer.
The accompanying notes are an integral part of these consolidated financial statements.
CHESAPEAKE EXPLORATION LIMITED PARTNERSHIP (A WHOLLY-OWNED PARTNERSHIP OF CHESAPEAKE ENERGY CORPORATION)
NOTES TO FINANCIAL STATEMENTS
1. BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Chesapeake Exploration Limited Partnership, an Oklahoma limited partnership ("CEX"), was formed on December 27, 1994 and acquired Chesapeake Exploration Company ("Exploration") by merger on such date. Exploration was a general partnership which was 10% owned by Chesapeake Operating, Inc. ("COI") and 90% owned by Chesapeake Energy Corporation ("CEC" or the "Company"). CEC owns 100% of the Common Stock of COI. CEX is 10% owned by COI as the sole general partner, and 90% owned directly by the Company, as the sole limited partner.
Effective December 31, 1994, COI transferred to CEX all of the Company's undeveloped leasehold acreage, thereby formalizing their prior economic arrangement. Historically, COI had transferred undeveloped leasehold acreage to CEX on a property-by-property basis as drilling commenced. CEX also owns substantially all of the Company's proved developed oil and gas properties. Accordingly, the financial statements of CEX include costs related to proved undeveloped properties and unevaluated properties, as well as proved producing properties. The change in partnership structure and the transfer of undeveloped leasehold by COI to CEX have been accounted for as a reorganization of entities under common control in a manner similar to a pooling-of-interests.
The CEX financial statements were prepared on a separate entity basis as reflected in the Company's books and records and include all material costs of doing business as if the partnership were on a stand-alone basis, except that interest is not charged on intercompany accounts, or allocated.
Capital is provided by advances from CEC and COI, and to a lesser extent directly by CEX's bank credit facilities.
These financial statements should be read in conjunction with CEC's consolidated financial statements.
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 date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from these estimates.
Oil and Gas Properties
CEC, and therefore CEX, follows the full cost method of accounting under which all costs associated with property acquisition, exploration and development activities are capitalized. CEX capitalizes internal costs that can be directly identified with its acquisition, exploration and development activities. Such costs do not include any costs related to production, general corporate overhead or similar activities (see Note 7). Capitalized costs are amortized on a composite unit-of-production method based on proved oil and gas reserves. CEX's oil and gas reserves are estimated annually by independent petroleum engineers. The average composite rates used for depreciation, depletion and amortization were $.85, $.80 and $.80 per equivalent Mcf in 1996, 1995 and 1994, 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. Unamortized costs, as reduced by related deferred taxes, are subject to a ceiling which limits such amounts to the estimated present value of oil and gas reserves, reduced by operating expenses, future development costs and income taxes. The costs of unproved properties are excluded from amortization until the properties are evaluated.
CHESAPEAKE EXPLORATION LIMITED PARTNERSHIP (A WHOLLY-OWNED PARTNERSHIP OF CHESAPEAKE ENERGY CORPORATION)
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
On April 30, 1996, CEX 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 $35 million, subject to adjustment for activity after the effective date of January 1, 1996. The properties are located in the Knox and Golden Trend fields of southern Oklahoma, most of which are operated by the Company.
Capitalized Interest
During fiscal 1996, 1995 and 1994, interest of approximately $6,428,000, $1,574,000 and $356,000 was capitalized on significant investments in unproved properties that are not being currently depreciated, depleted, or amortized and on which exploration or development activities are in progress.
Intercompany Transactions
COI, as operator of the majority of CEX's producing properties, bills CEX, as non-operator, on a monthly basis for services performed as operator pursuant to a standard operating agreement which is common in the industry. Expenses related to the operations of CEX are recorded via such joint interest billings and via intercompany expense allocations to CEX by COI. CEX has no employees. In the CEC consolidated group, COI employs all management personnel and employees, except for employees of the service company subsidiaries, and the preponderance of general and administrative expenses are reflected in the financial records of COI. COI allocates a portion of its general and administrative expenses to CEX each period. This allocation is based on a per well charge at a rate common in the industry plus an estimate of time spent on CEX activities by officers and employees of COI.
CEC makes advances to CEX as needed. Certain of CEC's service subsidiaries perform contractual services on CEX's wells for third parties. These subsidiaries bill COI, as operator, and COI in turn bills CEX through monthly joint interest billings in accordance with the terms of the standard operating agreement.
It is CEC's policy not to demand payment of intercompany accounts. Interest is not allocated by the Company, nor is interest charged on intercompany accounts. CEC may, at its discretion, but it is not required to, contribute intercompany accounts to capital.
Income Taxes
CEX is a partnership and, accordingly, its taxable income or loss is allocated to the limited partner and the general partner and is ultimately included in CEC's consolidated tax returns.
Gas Imbalances
CEX follows the "sales method" of accounting for its oil and gas revenue whereby CEX recognizes sales revenue on all oil or gas sold to its purchasers, regardless of whether the sales are proportionate to CEX's ownership in the property. A liability is recognized only to the extent that CEX has a net imbalance in excess of the reserves on the underlying properties. CEX's net imbalance positions at June 30, 1996 and 1995 were not material.
Hedging
The Company, on behalf of CEX, 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 CEX's oil and gas production.
CHESAPEAKE EXPLORATION LIMITED PARTNERSHIP (A WHOLLY-OWNED PARTNERSHIP OF CHESAPEAKE ENERGY CORPORATION)
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
Reclassifications
Certain reclassifications have been made to the CEX financial statements for the years ended June 30, 1995 and 1994 to conform to the presentation used for the June 30, 1996 financial statements.
2. LONG-TERM DEBT
In April 1993, CEX entered into an oil and gas reserve-based reducing revolving credit facility (the "Revolving Credit Facility") with Union Bank. The Revolving Credit Facility has been amended from time to time, most recently in September 1996. Concurrent with the September 1996 amendment, CEX increased the facility size to $125 million and expanded its bank group with Union Bank remaining as agent.
The maturity date of the Revolving Credit Facility is April 30, 2001. The facility provides for interest at the Union Bank reference rate (8.25% at June 30, 1996) or, at the option of CEX the Eurodollar rate plus 1.375% to 1.875% depending on the ratio of the amount outstanding to the borrowing base. Borrowings are collateralized by a first priority lien on substantially all of CEX's proved producing reserves, and are unconditionally guaranteed by the Company. At June 30, 1996 and 1995 there was $0 and $10,000 outstanding under the Revolving Credit Facility, respectively.
The amount of credit available at any time under the Revolving Credit Facility is the lesser of the commitment amount or the borrowing base. The borrowing base is reduced each month by a specified amount. Both the borrowing base and the monthly reduction amount are redetermined by Union Bank each May 1 and November 1 and may be redetermined at any other time upon the request of CEX or Union Bank. To the extent the amount outstanding at any time exceeds the borrowing base, CEX must reduce the amount outstanding or add additional collateral. At June 30, 1996, the commitment amount and the borrowing base under the Revolving Credit Facility were $35 million, and the monthly reduction amount was $700,000. The Revolving Credit Facility was amended in September 1996 to provide for a borrowing base and a commitment amount of $75 million, with a monthly reduction amount of $1,750,000. The Revolving Credit Facility contains customary financial covenants, limitations on indebtedness and liabilities, liens, prepayments of other indebtedness and loans, investments and guarantees by the Company and prohibits the payment of dividends on the Company's Common Stock.
3. CONTINGENCIES AND COMMITMENTS
CEX has fully and unconditionally guaranteed CEC's obligations under the $47.5 million principal amount of 12% Senior Notes due 2001, issued March 31, 1994, the $90 million principal amount of 10.5% Senior Notes due 2002, issued May 25, 1995, and the $120 million principal amount of 9.125% Senior Notes due 2006, issued April 9, 1996. In addition, the CEX partnership interests have been pledged as collateral under the 12% Senior Notes.
4. RELATED PARTY TRANSACTIONS
CEX has significant transactions with COI, CEC, CGDC and other affiliated companies included in the CEC consolidated group, including:
COI as operator for CEX:
(a) acquires oil and gas properties,
(b) drills and equips wells,
(c) operates the majority of CEX's wells,
(d) sells interests in proved undeveloped properties to third parties, and
CHESAPEAKE EXPLORATION LIMITED PARTNERSHIP (A WHOLLY-OWNED PARTNERSHIP OF CHESAPEAKE ENERGY CORPORATION)
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
(e) contracts services from affiliated entities in the CEC consolidated group and from third parties on behalf of CEX.
Capitalized costs associated with these transactions are reflected in the balance sheet as oil and gas properties and unevaluated properties for each period presented. Production expenses and taxes included in the statement of operations for each of the periods presented reflect expenses billed by COI to CEX for operations. Allocated general and administrative expenses reflect amounts allocated to CEX by COI.
The Company makes periodic advances (and contributions) to CEX.
The transactions included in the following intercompany balances are summarized as follows:
CHESAPEAKE EXPLORATION LIMITED PARTNERSHIP (A WHOLLY-OWNED PARTNERSHIP OF CHESAPEAKE ENERGY CORPORATION)
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
5. MAJOR CUSTOMERS
Sales to individual customers constituting 10% or more of total oil and gas sales were as follows:
Management believes that the loss of any of the above customers would not have a material impact on CEX's results of operations or its financial position.
6. FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES
The Company, on behalf of CEX, 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 counter-parties and to basis risk.
Hedging Activities
Periodically the Company, on behalf of CEX, utilizes hedging strategies to hedge the price of a portion of its future oil and gas production. These strategies include swap arrangements that establish an index-related price above which the Company pays the hedging partner and below which the Company is paid by the hedging partner, the purchase of index-related puts that provide for a "floor" price to the Company to be paid by the counter-party to the extent the price of the commodity is below the contracted floor, and basis protection swaps.
As of June 30, 1996, the Company had NYMEX-based crude oil swap agreements for 1,000 Bbl per day for July 1, 1996 through August 31, 1996 at an average price of $17.85 per Bbl. The counter-party has the option exercisable monthly for an additional 1,000 Bbl per day for the period July 1, 1996 through December 31, 1996 to cause a swap if the price exceeds an average $17.74 per Bbl. The actual settlements for July and August resulted in a $0.5 million payment to the counter-party. The Company estimates, based on NYMEX prices as of August 30, 1996 that the effect of the September through December hedges would be a $0.4 million payment to the counter-party.
The Company has purchased Houston Ship Channel put options which guarantee the Company an average floor price of $2.21/Mmbtu for 20,000 Mmbtu per day for the period of November 1, 1996 through February 28, 1997. The average cost of these puts was $0.14 per Mmbtu.
As of June 30, 1996, the Company had NYMEX-based natural gas swaps and NYMEX/Houston Ship Channel Basis swaps for the months of July through October 1996. These transactions resulted in payments to
CHESAPEAKE EXPLORATION LIMITED PARTNERSHIP (A WHOLLY-OWNED PARTNERSHIP OF CHESAPEAKE ENERGY CORPORATION)
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
the Company's counter-party of approximately $2 million for the month of July 1996 and $1.5 million for the month of August 1996. The Company estimates, based on NYMEX prices as of August 30, 1996, that the effect of the September and October hedges would be a $0.2 million payment to the counter-party.
Concentration of Credit Risk
Financial instruments which potentially subject CEX to concentrations of credit risk consist principally of trade receivables. CEX'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 CEX's overall exposure to credit risk, either positively or negatively, in that the customers may be similarly affected by changes in economic, industry or other conditions. The Company generally requires letters of credit for receivables from customers which are not considered investment grade, unless the credit risk can otherwise be mitigated.
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. Based on the borrowing rates currently available to CEX for bank loans with similar terms and average maturities, the fair value of long-term debt approximates the carrying value.
7. DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES
Net Capitalized Costs
Evaluated and unevaluated capitalized costs related to CEX's oil and gas producing activities are summarized as follows:
Unproved properties not subject to amortization at June 30, 1996 and 1995, consist mainly of lease acquisition costs. CEX capitalized approximately $6,428,000 and $1,574,000 of interest during the years ended June 30, 1996 and 1995 on significant investments in unproved properties that are not being currently depreciated, depleted, or amortized and on which exploration or development activities are in progress. CEX will continue to evaluate its unevaluated properties; however, the timing of the ultimate evaluation and disposition of the properties has not been determined.
CHESAPEAKE EXPLORATION LIMITED PARTNERSHIP (A WHOLLY-OWNED PARTNERSHIP OF CHESAPEAKE ENERGY CORPORATION)
NOTES TO 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:
Results of Operations from Oil and Gas Producing Activities (unaudited)
CEX's results of operations from oil and gas producing activities are presented below for the years ended June 30, 1996, 1995 and 1994, respectively. The following table includes revenues and expenses associated directly with CEX's oil and gas producing activities. It does not include any allocation of CEC's interest costs and, therefore, is not necessarily indicative of the contribution to consolidated net operating results of CEX's oil and gas operations.
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(a) Production costs include lease operating expenses and production taxes.
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") as of June 30, 1996, June 30, 1995 and June 30, 1994 and the Company's petroleum engineers as of June 30, 1996 and 1995. The reserves evaluated by the Company's petroleum engineers constituted approximately 0.6% and 0.5% of total proved reserves as of June 30, 1996 and 1995, respectively. The information is presented in accordance with regulations prescribed by the Securities and Exchange Commission. CEX emphasizes that reserve estimates are inherently imprecise. CEX'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
CHESAPEAKE EXPLORATION LIMITED PARTNERSHIP (A WHOLLY-OWNED PARTNERSHIP OF CHESAPEAKE ENERGY CORPORATION)
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
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.
Presented below is a summary of changes in estimated reserves of CEX based upon the reports prepared by Williamson for 1996, 1995 and 1994 along with those prepared by the Company's petroleum engineers for 1996 and 1995.
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 $35 million, subject to adjustment for activity after the effective date of January 1, 1996. The properties are located in the Knox and Golden Trend fields of southern Oklahoma, most of which are operated by the Company.
In October 1993, CEX entered into a joint development agreement covering a 20,000 gross acre development area in the Fayette County portion of the Giddings Field in southern Texas. CEX's ownership interests in the proved undeveloped properties covered by the joint development agreement were significantly less than those used in the June 30, 1993 reserve report. The impact of the reduced ownership percentages is reflected as sales of reserves in place in fiscal 1994 in the preceding table.
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. CEX 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 income tax effect of these future cash inflows will be recognized by CEX's partners. 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 CEX's expectations of actual revenue to
CHESAPEAKE EXPLORATION LIMITED PARTNERSHIP (A WHOLLY-OWNED PARTNERSHIP OF CHESAPEAKE ENERGY CORPORATION)
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
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 CEX's future net cash flows relating to proved oil and gas reserves based on the standardized measure prescribed in SFAS 69:
The principal sources of change in the standardized measure of discounted future net cash flows are as follows:
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
CHESAPEAKE ENERGY CORPORATION
By /s/ AUBREY K. McCLENDON ------------------------------------ Aubrey K. McClendon Chairman of the Board and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
INDEX TO EXHIBITS
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* Filed herewith.
+ Management contract or compensatory plan or arrangement.