10-K 1 h85663e10-k.txt KELLEY PARTNERS 1992 DEVELOPMENT DRILLING PROGRAM 1 ================================================================================ SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D. C. 20549 FORM 10-K ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE FISCAL YEAR ENDED DECEMBER 31, 2000 COMMISSION FILE NO. 0-20998 KELLEY PARTNERS 1992 DEVELOPMENT DRILLING PROGRAM (EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER) TEXAS 76-0373428 (STATE OR OTHER JURISDICTION OF (I.R.S. EMPLOYER IDENTIFICATION NO.) INCORPORATION OR ORGANIZATION) 601 JEFFERSON ST. SUITE 1100 HOUSTON, TEXAS 77002 (ADDRESS OF PRINCIPAL EXECUTIVE OFFICES) (ZIP CODE) REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE: (713) 652-5200 SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT: None (TITLE OF CLASS) SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT: Units of Limited and General Partner Interests (TITLE OF CLASS) Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes [X] No [ ] Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K under the Securities Exchange Act of 1934 is not contained herein, and will not be contained, to the best of the Registrant's knowledge, in definitive proxy or information statements incorporated in Part III of this Form 10-K or any amendments to this Form 10-K. [ ] As of March 23, 2001, Kelley Partners 1992 Development Drilling Program had 16,033,009 units of limited and general partner interests (the "Units") outstanding. The Units are not publicly traded. ================================================================================ 2 PART I ITEMS 1 AND 2. BUSINESS AND PROPERTIES INTRODUCTION General. Kelley Partners 1992 Development Drilling Program, a Texas limited partnership (the "Partnership"), was formed in 1992 to develop oil and gas properties located onshore in Louisiana. The Partnership issued a total of 16,033,009 units of limited and general partner interests ("Units"), representing 96.04% of the total interests in the Partnership, for $48,099,027. The Units consist of 1,647,500 Units of limited partner interests ("LP Units") and 14,385,509 Units of general partner interests ("GP Units"). In addition, the Partnership issued managing and special general partner ("General Partner") interests, representing the other 3.96% of the total interests in the Partnership, for $1,983,258. In the aggregate, Kelley Oil Corporation, a Delaware corporation, the managing general partner of the Partnership (the "Managing General Partner" or "Kelley Oil"), owns 92.12% of the total interests of the Partnership. Kelley Oil is a subsidiary of Contour Energy Co., collectively with its subsidiaries ("Contour"). In December 2000, Kelley Oil invited the unit holders for the Partnership to tender their units for cash. The cash offer was $0.123 per unit for all of the Partnership units not held by Kelley Oil. A total of 1,298,724 Partnership units (50% of units eligible for tender) were tendered. The total cost was approximately $200,000, including transaction costs. After the tender, Kelley Oil owns 91.82% of the Units and a 3.94% General Partner interest. As used in this Annual Report on Form 10-K (the "Report"), "Mcf" means thousand cubic feet, "Mmcf" means million cubic feet, "Bcf" means billion cubic feet, "Bbl" means barrel or 42 U.S. gallons liquid volume, "Mbbl" means thousand barrels, "Mcfe" means thousand cubic feet of natural gas equivalent using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate and natural gas liquids, "Mmcfe" means million cubic feet of natural gas equivalent, "Bcfe" means billion cubic feet of natural gas equivalent, and "Mmbtu" means million British thermal units. This Report includes various other capitalized terms that are defined when first used. The Partnership has received the benefits of a dramatic increase in the level of commodity prices (mainly natural gas) during 2000. However, the commodity markets are volatile and there is no certainty that current oil and natural gas prices can be sustained at these levels. Historically, Contour on behalf of the Partnership periodically enters into hedge contracts to protect against commodity price declines. However, effective 2001 the Partnership no longer plans to enter into hedging transactions because small production volumes makes doing so no longer feasible. Operations. Development activities of the Partnership are conducted through a joint venture (the "Joint Venture") between the Partnership and Kelley Operating Company, Ltd. ("Kelley Operating"), a subsidiary partnership of Kelley Oil. The Partnership contributed to the Joint Venture substantially all of the partners' contributed capital to finance the costs of drilling, completing, equipping and, when necessary, abandoning the wells drilled by the Joint Venture, proportionate with the Joint Venture's working interest in each well. Kelley Operating contributed to the Joint Venture specific drilling rights for development wells on its properties selected by the Managing General Partner. In return for the contributed drilling rights, Kelley Operating has reserved a 20% reversionary interest after Payout (as defined in the Joint Venture Agreement) in the costs and revenues of the Joint Venture. In addition to its reversionary interest, Kelley Operating retained one third of its working interest associated with the drilling rights contributed to the Joint Venture. Accordingly, Kelley Operating has contributed proportionately to the development and operating costs of all Partnership wells and receives a proportionate share of the revenues attributable to the sale of production from those wells. Development and Production. From inception through the completion of drilling activities in 1994, the Partnership participated in drilling 39 gross wells, of which 30 gross (11.07 net) wells were productive and 9 gross (4.16 net) wells were dry. Subsequently, two producing Partnership wells were plugged when production declined to 1 3 noncommercial levels. From its inception through 2000, the Partnership produced 10.7 Bcf of natural gas and 212,513 barrels of oil and natural gas liquids, generating total oil and gas revenues of $25,635,000, as restated, of which $4,823,000 or $0.29 per Unit has been distributed to the partners. To enable the Partnership to fund part of its drilling and recompletion expenses in excess of contributed capital, quarterly distributions were suspended in October 1994, reinstated for only one quarter in 1995, and suspended again thereafter. In February 2001, the fourth quarter 2000 earnings distribution was paid to the managing and special general partners and the unitholders in the amounts of $13,000 and $304,000, or $0.02 per Unit, respectively. However, future distributions to the unitholders are dependent on the future operating results of the Partnership. See "Management's Discussion and Analysis of Financial Condition and Results of Operations." MANAGEMENT, OPERATIONS AND PROPERTIES Kelley Oil's principal executive offices are located at 601 Jefferson Street, Suite 1100, Houston, Texas 77002, and its main telephone number is (713) 652-5200. As Managing General Partner, Kelley Oil makes all decisions regarding the business and operations of the Partnership. The Partnership has no employees and utilizes the officers and staff of Kelley Oil to perform all management and administrative functions. Kelley Oil's staff includes employees experienced in geology, geophysics, petroleum engineering, land acquisition and management, finance and accounting. Kelley Oil is also the managing general partner of Kelley Operating. See "Employees" below and "Directors and Executive Officers of Kelley Oil Corporation." On March 8, 2001, Contour announced that John F. Bookout, Contour's President and Chief Executive Officer had informed the Board of Directors of his intention to retire effective April 30, 2001, and to step down as Chairman and a member of the Board of Directors effective May 30, 2001. Kenneth R. Sanders will assume the position of President and Chief Executive Officer effective April 30, 2001. Additionally, Rick G. Lester, Contour's Chief Financial Officer, was appointed Executive Vice President. Both Messrs. Sanders and Lester were elected directors of Contour. The General Partners receive no management or other fees or promoted interests from the Partnership or the Joint Venture. The Partnership reimburses Kelley Oil for all direct costs incurred in managing the Partnership and all indirect costs allocable to the Partnership, principally comprised of general and administrative expenses. These arrangements are the same for all development drilling programs ("DDPs") sponsored by Kelley Oil. ESTIMATED PROVED RESERVES General. The estimated gross quantities of proved and proved developed reserves for properties in which the Partnership owns interests were prepared as of January 1, 1999, 2000 and 2001, by an independent petroleum engineering firm. For the reserves at January 1, 2000 and 2001, Contour applied appropriate Partnership revenue interests to determine the Partnership's net proved reserves shown below. Quantities. The following table sets forth the Partnership's estimated quantities of proved and proved developed reserves of crude oil (including condensate and natural gas liquids) and natural gas as of January 1, 1999, 2000 and 2001. Proved developed reserves are reserves that can be expected to be recovered from existing wells with existing equipment and operating methods. Proved undeveloped reserves are proved reserves that are expected to be recovered from new wells drilled to known reservoirs on undrilled acreage for which the existence and recoverability of reserves can be estimated with reasonable certainty, or from existing wells where a relatively major expenditure is required for recompletion. 2 4 ESTIMATED PROVED RESERVES

Detailed information concerning the Partnership's estimated proved reserves and discounted net future cash flows is contained in the Supplementary Financial Information included in Note 7 in Notes to the Financial Statements. The Partnership has not filed any estimates of reserves with any federal authority or agency during the past year other than estimates contained in its last annual report filed with the Securities and Exchange Commission ("SEC"). Uncertainties in Estimating Reserves. Oil and gas proved reserves cannot be measured exactly. Reserve estimates are inherently imprecise and may be expected to change as additional information becomes available. Estimates of oil and gas reserves, of necessity, are projections based on engineering data, and there are uncertainties inherent in the interpretation of such data as well as the projection of future rates of production and the timing of development expenditures. Reserve estimates are based on many factors related to reservoir performance which require evaluation by the engineers interpreting the available data, as well as price and other economic factors. The reliability of these estimates at any point in time depends on the quality and quantity of the technical and economic data, the production performance of the reservoirs as well as extensive engineering judgment. Further, estimates of the economically recoverable quantities of oil and natural gas attributable to any particular group of properties, classifications of such reserves based on risk of recovery and estimates of the future net revenues expected therefrom prepared by different engineers or by the same engineers at different times may vary substantially. Consequently, reserve estimates are subject to revision as additional data becomes available during the producing life of a reservoir. There also can be no assurance that the reserves set forth herein will ultimately be produced. In addition, the estimates of future net revenues from proved reserves of the Partnership and the present value thereof are based upon certain assumptions about future production levels, prices and costs that may not be correct when judged against actual subsequent experience. DESCRIPTION OF SIGNIFICANT PROPERTIES General. The properties of the Partnership consist primarily of interests in producing wells located in the Hosston, Smackover, Miocene and Oligocene trends in Louisiana. All of the Partnership's oil and gas reserves are located within the continental United States. 3 5 Significant Fields. The following table sets forth certain information as of January 1, 2001 with respect to the Partnership's interests in its most significant fields, together with information for all other fields combined. SIGNIFICANT PROVED PROPERTIES (IN THOUSANDS)

Additional information regarding these fields is set forth below. Unless otherwise noted, acreage and well information is provided as of December 31, 2000, and reserve information is provided as of January 1, 2001. NORTH LOUISIANA Ada Field. The Ada field is located in Bienville and Webster Parishes, Louisiana. The Partnership has an interest in 1 gross (.14 net) well producing from the Sligo and Hosston formations at a depth of 8,600 feet. The well is operated by a third party. The Ada field reserves are 100% proved developed. Sibley Field. The Sibley field is located in Webster Parish, Louisiana. The Partnership has interests in 5 gross (.34 net) wells producing from the Hosston formation at depths ranging from 7,300 to 10,000 feet. Kelley Oil operates one of the wells. The Sibley field reserves are 100% proved developed. SOUTH LOUISIANA Orange Grove/Humphreys Field. The Orange Grove/Humphreys field is located in Terrebonne Parish, Louisiana. The Partnership has an interest in 1 gross (.33 net) well producing from the 1st Hollywood formation at a depth of approximately 11,600 feet that Kelley Oil operates. The Orange Grove/Humphreys field reserves are 100% proved developed. Ouiski Bayou Field. The Ouiski Bayou field is located in Terrebonne Parish, Louisiana. The Partnership has an interest in 1 gross (.33 net) well producing from the Cib op formation at a depth of 17,000 feet that Kelley Oil operates. The Ouiski Bayou field reserves are 100% proved developed. 4 6 PRODUCTION, PRICE AND COST DATA The following tables set forth the oil and gas production, average sales price and average production costs per equivalent unit of oil and gas produced by the Partnership for the years ended December 31, 1998, 1999 and 2000. Detailed additional information concerning the Partnership's oil and gas producing activities is contained in the Supplementary Financial Information included in Note 7 in Notes to the Financial Statements. OIL AND GAS PRODUCTION

AVERAGE SALES PRICES AND PRODUCTION COSTS

(1) Includes effect of new accounting pronouncement requiring shipping and handling expenses (i.e. compression and transportation expenses) to be included in production costs rather than netted in revenues. The impact on production costs are increases of $.15/Mcfe, $.13/Mcfe and $.03/Mcfe for the years 1998, 1999 and 2000, respectively. Realized prices for natural gas per Mcf and oil and gas revenues per Mcfe have been restated accordingly. See Note 6 in Notes to the Financial Statements. OIL AND GAS WELLS As of December 31, 2000, the Partnership owned interests in productive oil and gas wells (including producing wells and wells capable of production) as follows:

(1) One or more completions in the same hole are counted as one well; none of the wells have multiple completions. Wells Drilled. All of the wells drilled by the Partnership are development wells based on definitions in the Partnership Agreement of the Partnership. The following table sets forth the number of gross and net productive and dry development wells and exploratory wells drilled by the Partnership during the periods indicated, based on a narrower definition for development wells under SEC guidelines. 5 7

MARKETING OF NATURAL GAS AND CRUDE OIL The Partnership does not refine or process any of the oil and natural gas it produces. The natural gas production of the Partnership is sold to various purchasers typically in the areas where the natural gas is produced. The Partnership currently is able to sell all of its natural gas at current market prices. Its revenue streams are therefore sensitive to changes in current market prices. The Partnership's sales of crude oil, condensate and natural gas liquids generally are related to posted field prices. In addition to marketing natural gas and crude oil produced on Partnership properties, a subsidiary of Kelley Oil aggregates volumes to increase market power, provides gas transportation arrangements, provides nomination and gas control services, supervises gas gathering operations and performs revenue receipt and disbursement services as well as regulatory filing, recordkeeping, inspection, testing, monitoring functions, coordinating the connection of wells to various pipeline systems, performing gas market surveys and overseeing gas balancing with its various gas gatherers and transporters. The Partnership believes that its activities are not currently constrained by a lack of adequate transportation systems or system capacity and does not foresee any material disruption in available transportation for its production. However, there can be no assurance that the Partnership will not encounter constraints in the future. In that event, the Partnership would be forced to seek alternate sources of transportation and may face increased costs. COMPETITION The oil and gas industry is highly competitive. Major oil and gas companies, independent concerns, drilling and production purchase programs and individual producers and operators are active bidders for desirable oil and gas properties, as well as the equipment and labor required to operate those properties. Many competitors have financial resources substantially greater than those of the Partnership and staffs and facilities substantially larger than those of Kelley Oil. The availability of a ready market for the oil and gas production of the Partnership depends in part on the cost and availability of alternative fuels, the level of consumer demand, the extent of other domestic production of oil and gas, the extent of importation of foreign oil and gas, the cost of and proximity to pipelines and other transportation facilities, regulations by state and federal authorities and the cost of complying with applicable environmental regulations. EMPLOYEES The Partnership has no employees and utilizes the management and staff of Kelley Oil. As of December 31, 2000, Kelley Oil had 45 employees. Kelley Oil's staff includes employees experienced in geology, geophysics, petroleum engineering, land acquisition and management, finance and accounting. See "Directors and Executive Officers of Kelley Oil Corporation." None of Kelley Oil's employees are represented by a union. Kelley Oil has never experienced an interruption in its operations from any kind of labor dispute, and its working relationship with its employees is satisfactory. 6 8 REGULATION The Partnership's operations are subject to extensive and continually changing regulation, as legislation affecting the oil and natural gas industry is under constant review for amendment and expansion. Many departments and agencies, both federal and state, are authorized by statute to issue and have issued rules and regulations binding on the oil and natural gas industry and its individual participants. The failure to comply with such rules and regulations can result in substantial penalties. The regulatory burden on the oil and natural gas industry increases the Partnership's cost of doing business and, consequently, affects its profitability. However, the Partnership does not believe that it is affected in a significantly different manner by these regulations than are its competitors in the oil and natural gas industry. Because of the numerous and complex federal and state statutes and regulations that may affect the Partnership, directly or indirectly, the following discussion of certain statutes and regulations should not be relied upon as an exhaustive review of all matters affecting the Partnership's operations. Transportation and Production Transportation and Sale of Natural Gas and Crude Oil. Sales of natural gas, crude oil and condensate ("Products") can be made by the Partnership at market prices not subject at this time to price controls. The price that the Partnership receives from the sale of these Products is affected by the ability to transport and cost of transporting the Products to market. Under applicable laws, the Federal Energy Regulation Commission ("FERC") regulates both the construction of pipeline facilities and the transportation of Products in interstate commerce. Regulation of Drilling and Production. Drilling and production operations of the Partnership are subject to regulation under a wide range of state and federal statutes, rules, orders and regulations. State and federal statutes and regulations govern, among other matters, the amounts and types of substances and materials that may be released into the environment, the discharge and disposition of waste materials, the reclamation and abandonment of wells and facility sites and remediation of contaminated sites, and require permits for drilling operations, drilling bonds and reports concerning operations. Most states in which the Partnership owns and operates properties have regulations governing conservation matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum rates of production from oil and natural gas wells and the regulation of the spacing, plugging and abandonment of wells. Many states also restrict production to the market demand for oil and natural gas and several states have indicated interest in revising applicable regulations. The effect of these regulations is to limit the amount of oil and natural gas the Partnership can produce from its wells and to limit the number of wells or the locations at which it can drill. Moreover, each state generally imposes an ad valorem, production or severance tax with respect to the production and sale of crude oil, natural gas and gas liquids within its jurisdiction. Environmental Regulations General. The various federal environmental laws, including the National Environmental Policy Act; the Clean Air Act of 1990, as amended ("CAA"); Oil Pollution Act of 1990, as amended ("OPA"); Water Pollution Control Act, as amended ("FWPCA"); the Resource Conservation and Recovery Act as amended ("RCRA"); the Toxic Substances Control Act; and the Comprehensive Environmental Response, Compensation and Liability Act, as amended ("CERCLA"), and the various state and local environmental laws, and the regulations adopted pursuant to such law, governing the discharge of materials into the environment, or otherwise relating to the protection of the environment, continue to be taken seriously by the Partnership. In particular, the Partnership's drilling, development and production operations, its activities in connection with storage and transportation of crude oil and other liquid hydrocarbons and its use of facilities for treating, processing or otherwise handling hydrocarbons and wastes therefrom are subject to stringent environmental regulation, and violations are subject to reporting requirements, civil penalties and criminal sanctions. As with the industry generally, compliance with existing regulations increases the Company's overall cost of business. The increased costs are not reasonably ascertainable. Such areas affected include unit production expenses primarily related to the control and limitation of air emissions and the disposal of produced water, capital costs to drill exploration and development wells resulting from expenses primarily related to the management and disposal of drilling 7 9 fluids and other oil and natural gas exploration wastes and capital costs to construct, maintain and upgrade equipment and facilities and plug and abandon inactive well sites and pits. Environmental regulations historically have been subject to frequent change by regulatory authorities, and the Partnership is unable to predict the ongoing cost of compliance with these laws and regulations or the future impact of such regulations on its operations. However, the Partnership does not believe that changes to these regulations will materially adversely affect its competitive position because the Partnership's competitors are similarly affected. A discharge of hydrocarbons or hazardous substances into the environment could subject the Partnership to substantial expense, including both the cost to comply with applicable regulations pertaining to the remediation of releases of hazardous substances into the environment and claims by neighboring landowners and other third parties for personal injury and property damage. The Partnership maintains insurance, which may provide protection to some extent against environmental liabilities, but the coverage of such insurance and the amount of protection afforded thereby cannot be predicted with respect to any particular possible environmental liability and may not be adequate to protect the Partnership from substantial expense. The OPA and regulations thereunder impose a variety of regulations on "responsible parties" related to the prevention of oil spills and liability for damages resulting from such spills in United States waters. A "responsible party" includes the owner or operator of an onshore facility, vessel, or pipeline, or the lessee or permittee of the area in which an offshore facility is located. The OPA assigns liability to each responsible party for oil removal costs and a variety of public and private damages. The FWPCA imposes restrictions and strict controls regarding the discharge of produced waters and other oil and natural gas wastes into navigable waters. State laws for the control of water pollution also provide varying civil, criminal and administrative penalties and impose liabilities in the case of a discharge of petroleum or its derivatives, or other hazardous substances, into state waters. In addition, the Environmental Protection Agency ("EPA") has promulgated regulations that require many oil and natural gas production operations to obtain permits to discharge storm water runoff. The CAA requires or will require most industrial operations in the United States to incur capital expenditures in order to meet air emission control standards developed by the EPA and state environmental agencies. Although no assurances can be given, the Company believes implementation of such amendments will not have a material adverse effect on its financial condition or results of operations. RCRA is the principal federal statute governing the treatment, storage and disposal of hazardous wastes. RCRA imposes stringent operating requirements (and liability for failure to meet such requirements) on a person who is either a "generator" or "transporter" of hazardous waste or an "owner" or "operator" of a hazardous waste treatment, storage or disposal facility. At present, RCRA includes a statutory exemption that allows oil and natural gas exploration and production wastes to be classified as non-hazardous waste. As a result, the Partnership is not required to comply with a substantial portion of RCRA's requirements because its operations generate minimal quantities of hazardous wastes. CERCLA, also known as "Superfund", imposes liability, without regard to fault or the legality of the original act, on certain classes of persons that contributed to the release of a "hazardous substance" into the environment. These persons include the "owner" or "operator" of the site and companies that disposed or arranged for the disposal of the hazardous substances found at the site. CERCLA also authorizes the EPA and, in some instances, third parties to act in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. In the course of its ordinary operations, the Partnership may generate waste that may fall within CERCLA's definition of a "hazardous substance". As a result, the Partnership may be jointly and severally liable under CERCLA or under analogous state laws for all or part of the costs required to clean up sites at which such wastes have been disposed. The Partnership 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 natural gas. Although the Partnership 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 Partnership 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 actions with respect to the treatment and disposal or release of hydrocarbons or other wastes were 8 10 not under the Partnership's control. These properties and wastes disposed thereon may be subject to CERCLA, RCRA and analogous state laws. Under such laws, the Partnership could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators), to clean up contaminated property (including contaminated groundwater) or to perform remedial plugging operations to prevent future contamination. CAUTION AS TO FORWARD-LOOKING STATEMENTS Statements contained in this Report and other materials filed or to be filed by the Partnership with the Securities and Exchange Commission (as well as information included in oral or other written statements made or to be made by the Company or its representatives) that are forward-looking in nature are intended to be "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended, relating to matters such as anticipated operating and financial performance, business prospects, developments and results of the Partnership. Actual performance, prospects, developments and results may differ materially from any or all anticipated results due to economic conditions and other risks, uncertainties and circumstances partly or totally outside the control of the Partnership, including rates of inflation, natural gas prices, uncertainty of reserve estimates, rates and timing of future production of oil and gas, exploratory and development activities, acquisition risks and activities, changes in the level and timing of future costs and expenses related to drilling and operating activities and those risks described under "Risk Factors" below. Words such as "anticipated," "expect," "estimate," "project" and similar expressions are intended to identify forward-looking statements. Forward-looking statements include the risks described in "Risk Factors". RISK FACTORS The Partnership cautions that the following risk factors could affect its actual results in the future, in addition to "Uncertainties in Estimating Reserves" and "Liquidity and Capital Resources" discussed elsewhere in this Report. Depletion of Reserves. Producing oil and natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. The Partnership's future oil and natural gas reserves and production, and, therefore, cash flow and income, are highly dependent upon its success in efficiently producing its reserves. Volatility of Oil, Natural Gas and Natural Gas Liquids Prices. The Partnership's financial results are affected significantly by the prices received for its oil, natural gas and natural gas liquids production. Historically, the markets for oil, natural gas and natural gas liquids have been volatile and are expected to continue to be volatile in the future. The Partnership's future financial condition and results of operations will depend, in part, upon the prices received for its oil and natural gas production, as well as the costs of developing and producing reserves. Because the Partnership will no longer plans to hedge its production, prices realized by the Partnership may be more volatile than historically. Operating Hazards and Uninsured Risks. Oil and gas drilling activities are subject to numerous risks, many of which are uninsurable, including the risk that no commercially viable oil or natural gas production will be obtained; many of such risks are beyond the Partnership's control. The decision to develop a prospect or property will depend in part on the evaluation of data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations. The cost of drilling, completing and operating wells is often uncertain, and overruns in budgeted expenditures are common risks that can make a particular project uneconomical. Technical problems encountered in actual drilling, completion and workover activities can delay such activity and add substantial costs to a project. Further, drilling may be curtailed, delayed or canceled as a result of many factors, including title problems, weather conditions, compliance with government permitting requirements, shortages of or delays in obtaining equipment, reductions in product prices and limitations in the market for products. 9 11 The availability of a ready market for the Partnership's oil and natural gas production also depends on a number of factors, including the demand for and supply of oil and natural gas and the proximity of reserves to pipelines or trucking and terminal facilities. Natural gas wells may be partially or totally shut in for lack of a market or because of inadequacy or unavailability of natural gas pipeline or gathering system capacity. The Partnership's oil and natural gas business also is subject to all of the operating risks associated with the drilling for and production of oil and natural gas, including, but not limited to, uncontrollable flows of oil, natural gas, brine or well fluids into the environment (including groundwater and shoreline contamination), blowouts, cratering, mechanical difficulties, fires, explosions, pollution and other risks, any of which could result in substantial losses to the Partnership. Although the Partnership maintains insurance at levels that it believes are consistent with industry practices, it is not fully insured against all risks. Losses and liabilities arising from uninsured and underinsured events could have a material adverse effect on the financial condition and operations of the Partnership. ITEM 3. LEGAL PROCEEDINGS Contour, through its subsidiaries, is involved in various claims and lawsuits incidental to its business. In the opinion of management, the ultimate liability thereunder, if any, will not have a material effect on the financial condition of Kelley Oil or the Partnership. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS Not applicable. 10 12 PART II ITEM 5. MARKET FOR UNITS AND RELATED UNITHOLDER MATTERS There is no market for the Units of the Partnership. Transfer of the Units was substantially restricted by the provisions of the Partnership Agreement until the Partnership Agreement was amended in December 2000 to allow unitholders to buy or sell units from existing unitholders. As of March 23, 2001, there were 477 holders of record of the Partnership's Units. The following table sets forth the cash distributions per Unit paid by the Partnership during the periods indicated.

Distribution levels are affected by numerous factors, including oil and gas prices, production levels and operating costs, together with any working capital or debt service requirements. To enable the Partnership to fund part of its drilling and recompletion expenses in excess of contributed capital, distributions were suspended in the fourth quarter of 1994 and reinstated only for the third quarter of 1995. In the third quarter 2000, the final payment on the $6,000,000 Initial Loan from Kelley Oil was paid. In February 2001, the fourth quarter 2000 earnings distribution was paid to the managing and special general partners and the unitholders in the amounts of $13,000 and $304,000, or $0.02 per Unit, respectively. Future distributions to the unitholders and the managing and special general partners are contingent on future operating results. See "Management's Discussion and Analysis of Financial Condition and Results of Operations." 11 13 ITEM 6. SELECTED FINANCIAL DATA The following table presents selected financial data for the Partnership. The financial information presented below is derived from the Partnership's audited Financial Statements presented elsewhere in this Report and in previously filed Form 10Ks, and should be read in conjunction with those Financial Statements and the related Notes thereto. KELLEY PARTNERS 1992 DEVELOPMENT DRILLING PROGRAM (IN THOUSANDS, EXCEPT PER UNIT AMOUNTS)

(1) Total Revenues and Production expenses have been restated for the years 1997, 1998 and 2000 in accordance with a new accounting pronouncement. See Note 6 in Notes to the Financial Statements and "Management's Discussion and Analysis of Financial Condition and Results of Operations". (2) Per Unit amounts are based on the Unitholders' 96.04% share of net income and loss. (3) 1999 revenues include gain on sale of properties of $850. 12 14 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS GENERAL In 1992, the Partnership issued a total of 16,033,009 units of limited and general partner interests ("Units") at $3.00 per Unit for a total of $48,099,027. The Units represent 96.04% of the total interests in the Partnership and consist of 1,647,500 Units of limited partner interests ("LP Units") and 14,385,509 Units of general partner interests ("GP Units") at December 31, 2000. In addition, the Partnership issued managing and special general partner interests on a pro rata basis for $1,983,258, representing 3.96% of the total interests in the Partnership. In the aggregate, Kelley Oil Corporation, a Delaware corporation, the managing general partner of the Partnership (the "Managing General Partner" or "Kelley Oil"), owns 92.12% of the total interests of the Partnership. Kelley Oil is a subsidiary of Contour Energy Co., collectively with its subsidiaries ("Contour"). In December 2000, Kelley Oil invited the unit holders for the Partnership to tender their units for cash. The cash offer was $0.123 per unit for the Partnership units not held by Kelley Oil. A total of 1,298,724 Partnership units (50% of units eligible for tender) were tendered. The total cost was approximately $200,000, including transaction costs. After the tender, Kelley Oil owns 91.82% of the Units and a 3.94% General Partner interest. Drilling Operations. Since inception, the Partnership participated in drilling 39 gross (15.23 net) wells, of which 30 gross (11.07 net) wells were found productive and 9 gross (4.16 net) wells were dry. Hedging Activities. Historically, Contour on behalf of the Partnership periodically enters into hedge contracts to protect against commodity price declines. Contour normally employs the average NYMEX price for the last three days of the contract for natural gas and the monthly average of the closing NYMEX price for crude oil as the underlying index ("Index Price"). See Note 5 in the Notes to the Financial Statements. However, effective 2001 the Partnership no longer plans to enter into hedging transactions because small production volumes makes doing so no longer feasible. Through natural gas price swap agreements, the Partnership hedged approximately 49% and 50%, respectively, of its natural gas production for 1998 and 1999, respectively, at average NYMEX quoted prices of $2.31 and $2.17 per Mmbtu, respectively, before transaction and transportation costs. For 2000, the Partnership hedged approximately 72% of its natural gas production using price swap agreements (48%) and a costless collar (24%). The average price received under the swap agreements was $2.59/Mmbtu. The costless collar included a ceiling of $4.98/Mmbtu and a floor of $4.00/mmbtu at the closing Index Price. As of December 31, 2000, none of the Partnership's anticipated natural gas production for 2001 has been hedged Through crude oil price swap agreements, the Partnership hedged approximately 29% of its crude oil production for 1999 at an average NYMEX quoted price of $20.00 per bbl, before transaction and transportation costs. No crude oil was hedged in 1998. For 2000, the Company hedged approximately 66% of its crude oil production using price swap agreements (41%) and costless collars (25%). The average price received under the swap agreements was $26.21/Bbl. The costless collars included an average ceiling of $32.21/Bbl and an average floor of $26.11/Bbl at the closing Index Price. As of December 31, 2000, none of the Partnership's crude oil production for 2001 had been hedged. Hedging activities decreased Partnership oil and natural gas revenues by approximately $17,000 and $109,000 in 1999 and 2000, respectively, and increased such revenues by approximately $50,000 in 1998 as compared to estimated revenues had no hedging activities been conducted. The credit risk exposure from counterparty nonperformance on natural gas forward sales contracts and derivative financial instruments is generally the amount of unrealized gains under the contracts. The Partnership has not experienced counterparty nonperformance on these agreements. 13 15 RESULTS OF OPERATIONS Years Ended December 31, 2000 and 1999. Oil and gas revenues were $800,000 for 2000 as compared to $843,000 in the corresponding period of 1999, primarily as a result of lower oil and gas production offset by higher oil and natural gas prices. Production of natural gas decreased 53% from 314,000 Mcf in 1999 to 149,000 Mcf in 2000. Production of crude oil in the current year totaled 9,031 barrels compared to 9,398 barrels last year, representing a decrease of 4%. Oil and gas production decreased due to the sale of properties to Phillips Petroleum Company ("Phillips") in the second quarter of 1999 and natural depletion. Lease operating expenses and severance taxes were $256,000 in 2000 versus $378,000 in 1999, a decrease of 32%, primarily related to the sale of properties to Phillips. On a unit of production basis, these expenses increased to $1.26 per Mcfe in 2000 from $1.02 per Mcfe in 1999. Transportation and compression expenses of $48,000 ($0.13 per Mcfe) and $7,000 ($0.03 per Mcfe) were included in lease operating expense for 1999 and 2000, respectively, as a result of a new accounting pronouncement. See Note 6 in Notes to Financial Statements. General and administrative expenses of $62,000 in 2000 decreased 33% from $92,000 in 1999. On a unit of production basis, these expenses increased from $0.25 per Mcfe in 1999 to $0.31 per Mcfe in 2000. In 2000 and 1999, the Partnership incurred interest expense of $6,000 and $174,000, respectively, on a loan advanced to it by Kelley Oil in August 1994 to fund part of its drilling expenses in excess of contributed capital. The reduction reflects the lower average note payable balance outstanding in 2000 as compared to 1999. In 2000, the final payment of $166,000 was made on the $6,000,000 Initial Loan. See "Liquidity and Capital Resources". Depreciation, depletion and amortization ("DD&A") expense decreased 47% from $225,000 in 1999 to $120,000 in 2000 due to lower production levels related to the sale of properties to Phillips and lower depletion rates. On a unit of production basis, DD&A expense decreased from $0.61 per Mcfe in 1999 to $0.59 per Mcfe in 2000. The Partnership recognized net income in 2000 of $356,000 or $0.02 per Unit compared to net income in 1999 of $824,000, including a $850,000 gain on sale of properties, or $0.05 per Unit. The reasons for the variance between 2000 and 1999 are described in the foregoing discussion. Years Ended December 31, 1999 and 1998. Oil and gas revenues of $843,000 for 1999 decreased 43% compared to $1,495,000 in the corresponding period of 1998 primarily as a result of lower oil and gas production. Production of natural gas decreased 48% from 601,000 Mcf in 1998 to 314,000 Mcf in 1999. Production of crude oil in the current year totaled 9,398 barrels compared to 10,172 barrels last year, representing a decrease of 8%. Oil and gas production decreased due to the sale of properties to Phillips and natural depletion. In 1999, the Partnership recognized a $850,000 gain on the sale of the north Louisiana fields to Phillips. Lease operating expenses and severance taxes were $378,000 in 1999 versus $594,000 in 1998, a decrease of 36%, primarily related to the sale of properties to Phillips. On a unit of production basis, these expenses increased to $1.02 per Mcfe in 1999 from $0.90 per Mcfe in 1998. Transportation and compression expenses of $97,000 ($0.15 per Mcfe) and $48,000 ($0.13 per Mcfe) were included in lease operating expense for 1998 and 1999, respectively, as a result of a new accounting pronouncement. General and administrative expenses of $92,000 in 1999 decreased 31% from $134,000 in 1998. On a unit of production basis, these expenses increased from $0.20 per Mcfe in 1998 to $0.25 per Mcfe in 1999. In 1999 and 1998, the Partnership incurred interest expense of $174,000 and $287,000, respectively, on a loan advanced to it by Kelley Oil in August 1994 to fund part of its drilling expenses in excess of contributed capital. The 14 16 reduction reflects the lower average note payable balance outstanding in 1999 as compared to 1998. See "Liquidity and Capital Resources" below. DD&A expense decreased 47% from $427,000 in 1998 to $225,000 in 1999 due to lower production levels related to the sale of properties to Phillips and lower depletion rates. On a unit of production basis, DD&A expense decreased from $0.64 per Mcfe in 1998 to $0.61 per Mcfe in 1999. In 1998, the Partnership recognized a non-cash impairment charge of $466,000 against the carrying values of its proved oil and gas properties, for the year ended December 31, 1998 (see "Oil and Gas Properties" in Note 1 to the Financial Statements). The Partnership recognized net income in 1999 of $824,000 or $0.05 per Unit compared to a net loss in 1998 of $413,000 or $(0.02) per Unit. The reasons for the variance between 1999 and 1998 are described in the foregoing discussion. LIQUIDITY AND CAPITAL RESOURCES Liquidity. Net cash provided by the Partnership's operating activities during 2000, as reflected on its statement of cash flows, totaled $460,000. During the period, funds used in financing activities included a reduction in the Initial Loan principal of $166,000 and partnership distributions of $317,000. As a result of these activities, the Partnership's cash and cash equivalents remained at zero at December 31, 2000. The Partnership has received the benefits of a dramatic increase in the level of commodity prices (mainly natural gas) during 2000. However, the commodity markets are volatile and there is no certainty that current oil and natural gas prices can be sustained at these levels. Historically, Contour on behalf of the Partnership periodically enters into hedge contracts to protect against commodity price declines. However, effective 2001 the Partnership no longer plans to enter into hedging transactions because small production volumes makes doing so no longer feasible. Capital Resources. The partners' equity at December 31, 2000 increased to $926,000 as compared to $887,000 at December 31, 1999. The Partnership has completed its development stage. Accordingly, cash flow from operations should be adequate to meet its expected capital and general working capital needs. As of December 31, 2000, the Partnership was fully capitalized with contributions aggregating $50,082,285. Distribution Policy. The Partnership maintains a policy of distributing cash which is not required for the conduct of Partnership business to Unitholders on a quarterly basis. To meet its financial obligations for drilling overexpenditures, the Partnership suspended distributions commencing in October 1994 and reinstated a quarterly distribution for only one quarter in 1995. In 2000, the final payment of $166,000 was made on the $6,000,000 Initial Loan. In February 2001, the fourth quarter 2000 earnings distribution was paid to the managing and special general partners and the unitholders in the amounts of $13,000 and $304,000, or $0.02 per Unit, respectively. However, future distributions to the unitholders and the managing and special general partners are contingent on future operating results. 15 17 Inflation and Changing Prices. Oil and natural gas prices, as with most commodities, are highly volatile, have fluctuated during recent years and generally have not followed the same pattern as inflation. The following table shows the changes in the average oil and natural gas prices (including the effects of hedging) received by Partnership during the periods indicated.

Accounting Pronouncements. The Partnership adopted Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities" ("SFAS 133") effective January 1, 2001. The statement, as amended, requires that all derivatives be recognized as either assets or liabilities and measured at fair value, and changes in the fair value of derivatives be reported in current earnings, unless the derivative is designated and effective as a hedge. If the intended use of the derivative is to hedge the exposure to changes in the fair value of an asset, a liability or firm commitment, then the changes in the fair value of the derivative instrument will generally be offset in the income statement by the change in the item's fair value. However, if the intended use of the derivative is to hedge the exposure to variability in expected future cash flows then the changes in fair value of the derivative instrument will generally be reported in Other Comprehensive Income (OCI). The gains and losses on the derivative instrument that are reported in OCI will be reclassified to earnings in the period in which earnings are impacted by the hedged item. As of January 1, 2001, the Partnership is not party to any derivative instruments and as such there is no impact on its financial statements as a result of the adoption of SFAS 133. In the fourth quarter of 2000, the Partnership adopted Emerging Issues Task Force Issue No. 00-10 ("EITF No. 00-10") accounting for Shipping and Handling Fees and Costs. EITF No. 00-10 addresses how shipping and handling fees should be classified in the income statement. As a result of EITF No. 00-10, the Partnership has reclassified its transportation and compression expenses from oil and gas revenues to production expenses. 16 18 ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK See discussion in Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations-Hedging 17 19 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA INDEX TO FINANCIAL STATEMENTS KELLEY PARTNERS 1992 DEVELOPMENT DRILLING PROGRAM:

18 20 INDEPENDENT AUDITORS' REPORT To the Partners of Kelley Partners 1992 Development Drilling Program: We have audited the accompanying balance sheets of Kelley Partners 1992 Development Drilling Program (a Texas limited partnership) as of December 31, 1999 and 2000, and the related statements of operations, cash flows, and changes in partners' equity (deficit) for each of the three years in the period ended December 31, 2000. These financial statements are the responsibility of the Partnership's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. 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 audits provide a reasonable basis for our opinion. In our opinion, such financial statements present fairly, in all material respects, the financial position of Kelley Partners 1992 Development Drilling Program as of December 31, 1999 and 2000, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2000, in conformity with accounting principles generally accepted in the United States of America. DELOITTE & TOUCHE LLP Houston, Texas March 22, 2001 19 21 KELLEY PARTNERS 1992 DEVELOPMENT DRILLING PROGRAM BALANCE SHEETS (IN THOUSANDS)

See Notes to Financial Statements. 20 22 KELLEY PARTNERS 1992 DEVELOPMENT DRILLING PROGRAM STATEMENTS OF OPERATIONS (IN THOUSANDS, EXCEPT PER UNIT DATA)

See Notes to Financial Statements. 21 23 KELLEY PARTNERS 1992 DEVELOPMENT DRILLING PROGRAM STATEMENTS OF CASH FLOWS (IN THOUSANDS)

See Notes to Financial Statements. 22 24 KELLEY PARTNERS 1992 DEVELOPMENT DRILLING PROGRAM STATEMENTS OF CHANGES IN PARTNERS' EQUITY (DEFICIT) (IN THOUSANDS)

See Notes to Financial Statements. 23 25 KELLEY PARTNERS 1992 DEVELOPMENT DRILLING PROGRAM NOTES TO FINANCIAL STATEMENTS NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Cash and Cash Equivalents. The Partnership considers all highly liquid investments with an original maturity of three months or less when purchased to be cash equivalents. Income Taxes. The income or loss of the Partnership for federal income tax purposes is includable in the tax returns of the individual partners of the Partnership. Accordingly, no recognition has been given to income taxes in the accompanying financial statements. Oil and Gas Properties. Oil and gas properties are located in the United States, and are held of record by Kelley Operating Company, Ltd. The Partnership utilizes the successful efforts method of accounting for its oil and gas operations. Under the successful efforts method, the costs of successful wells and development dry holes are capitalized and amortized on a unit-of-production basis over the life of the related reserves. Exploratory drilling costs are initially capitalized pending determination of proved reserves but are charged to expense if no proved reserves are found. Estimated future abandonment and site restoration costs, net of anticipated salvage values, are taken into account in depreciation, depletion and amortization. The Partnership's proved oil and gas properties are reviewed for indications of impairment whenever events or circumstances indicate that the carrying value of its oil and gas properties may not be recoverable. As a result of a decline in its proved reserves at January 1, 1999 from year-earlier levels, the Partnership performed an assessment of the fair value of its oil and gas properties which indicated an impairment should be recognized. Under this analysis, the fair value for the Partnership's proved oil and gas properties was estimated using escalated pricing and present value discount factors reflecting risk assessments. Based on this analysis, the Partnership recognized a non-cash impairment charge of $466,000 against the carrying value of its proved oil and gas properties at December 31, 1998. Oil and Gas Revenues. The Partnership recognizes oil and gas revenue from its interests in producing wells as oil and gas is produced and sold from those wells. Oil and gas sold is not significantly different from the Partnership's production entitlement. Net Income or Loss Per Unit. Net income or loss per Unit is computed based on the weighted average number of Units outstanding during the period divided into the net income or loss allocable to the Unitholders. Financial Instruments. The Partnership's financial instruments consist of cash and cash equivalents, receivables, payables, debt and commodity derivatives. See Note 5 - "Hedging Activities". Management believes the carrying amounts of the financial instruments classified in current assets or liabilities approximate fair value due to their short-term nature. Derivative Financial Instruments. From time to time, the Partnership has entered into transactions in derivative financial instruments covering future oil and natural gas production principally as a hedge against natural gas price declines. See Note 5 - "Hedging Activities" for a discussion of the Partnership's accounting policies related to hedging activities. Concentration of Credit Risk and Significant Customers. Substantially all of the Partnership's receivables are due from the marketing subsidiary of Kelley Oil Corporation ("Kelley Oil"), which purchases approximately 80% of the Partnership's natural gas for resale to a limited number of natural gas transmission companies and other gas purchasers. To date, this concentration has not had a material adverse effect on the financial condition of the Partnership. 24 26 Use of Estimates. The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America 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 those estimates. Reclassifications. Certain financial statement items in 1998 and 1999 have been reclassified to conform to the 2000 presentation. See Note 6. NOTE 2 - LONG-TERM DEBT In August 1994, one of the credit facilities maintained by Kelley Oil was modified to add the Partnership as a borrower, and $6 million was advanced to the Partnership to fund part of its drilling overexpenditures. The Partnership's bank debt was subsequently replaced by a $6 million loan from Kelley Oil (the "Initial Loan") funded with borrowings by Kelley Oil under a credit facility. Interest has been paid by the Partnership based on Contour's borrowing cost resulting in an effective rate of 10 3/8% for 1998, 1999 and 2000. In 2000, the final payment of $166,000 was made on the $6,000,000 Initial Loan. NOTE 3 - CASH DISTRIBUTIONS The Partnership maintains a policy of distributing cash that is not required for the conduct of Partnership business to Unitholders on a quarterly basis. To meet its financial obligations for drilling overexpenditures, the Partnership suspended distributions commencing in October 1994 and reinstated a quarterly distribution for only one quarter in 1995. Operating cash flows since 1995 through the third quarter 2000 have been used to service the Partnership's debt. See Note 3 - Long Term Debt. In February 2001, the fourth quarter 2000 earnings distribution was paid to the managing and special general partners and the unitholders in the amounts of $13,000 and $304,000, or $0.02 per Unit, respectively. However, future distributions to the unitholders and the managing and special general partners are contingent on future operating results. NOTE 4 - RELATED PARTY TRANSACTIONS The Unitholders have a 96.04% share and the general partners a 3.96% share in the costs and revenues of the Partnership. The Partnership reimburses Kelley Oil for all direct costs incurred in managing the Partnership and all indirect costs (principally general and administrative expenses) allocable to the Partnership. Overhead allocated to the Partnership by Kelley Oil for the years ended December 31, 1998, 1999 and 2000 related to general and administrative expenses aggregated $134,000, $92,000 and $62,000, respectively. Substantially all of the Partnership's gas sales are made to an affiliated company, Concorde Gas Marketing, Inc., an indirect wholly-owned subsidiary of Kelley Oil ("CGM"), which remarkets gas to third parties. For 1998, 1999 and 2000, a fee of 2% of the resale price was charged to the Partnership by CGM for its marketing services. In December 2000, Kelley Oil invited the unit holders for the Partnership to tender their units for cash. The cash offer was $0.123 per unit for all of the Partnership units not held by Kelley Oil. A total of 1,298,724 Partnership units (50% of units eligible for tender) were tendered. The total cost was approximately $200,000, including transaction costs. After the tender, Kelley Oil owns 91.82% of the Units and a 3.94% General Partner interest. 25 27 NOTE 5 - HEDGING ACTIVITIES Historically, Contour has entered into hedge agreements on behalf of the Partnership to protect against commodity price declines. Because of small production volumes, beginning 2001, the Partnership production will no longer be hedged. Contour periodically uses forward sales contracts, natural gas and crude oil price swap agreements, collars and options to reduce exposure to downward price fluctuations on its natural gas and crude oil production. Contour does not engage in speculative transactions. During 2000, Contour used price swap agreements and collars. Price swap agreements generally provide for Contour to receive or make counterparty payments on the differential between a fixed price and a variable indexed price for natural gas and crude oil. Collars combine put and call options to establish a ceiling and a floor. Contour normally employs the average NYMEX price for the last three days of the contract for natural gas and the monthly average of closing NYMEX prices for crude oil as the underlying index ("Index Price"). To the extent the Index Price closes above the established ceiling Contour must make payments to the counterparty on the differential between the Index Price and the ceiling. Conversely, if the Index Price closes below the established floor, the counterparty must make payments to Contour on the differential between the Index Price and the floor. If the Index Price closes between the ceiling and the floor, no settlement is due. Gains and losses realized by the Partnership from hedging activities are included in oil and gas revenues and average sales prices in the period that the related production is sold. Contour's hedging activities also cover the oil and gas production attributable to the interest in such production of the public unitholders in its subsidiary partnerships, including the production of the Partnership, for 1998, 1999 and 2000. Through natural gas price swap agreements, the Partnership hedged approximately 49% and 50%, respectively, of its natural gas production for 1998 and 1999, respectively, at average NYMEX quoted prices of $2.31 and $2.17 per Mmbtu, respectively, before transaction and transportation costs. For 2000, the Partnership hedged approximately 72% of its natural gas production using price swap agreements (48%) and a costless collar (24%). The average price received under the swap agreements was $2.59/Mmbtu. The costless collar included a ceiling of $4.98/Mmbtu and a floor of $4.00/mmbtu at the closing Index Price. As of December 31, 2000, none of the Partnership's anticipated natural gas production for 2001 has been hedged Through crude oil price swap agreements, the Partnership hedged approximately 29% of its crude oil production for 1999 at an average NYMEX quoted price of $20.00 per bbl, before transaction and transportation costs. No crude oil was hedged in 1998. For 2000, the Company hedged approximately 66% of its crude oil production using price swap agreements (41%) and costless collars (25%). The average price received under the swap agreements was $26.21/Bbl. The costless collars included an average ceiling of $32.21/Bbl and an average floor of $26.11/Bbl at the closing Index Price. As of December 31, 2000, none of the Partnership's crude oil production for 2001 had been hedged. Hedging activities decreased Partnership oil and natural gas revenues by approximately $17,000 and $109,000 in 1999 and 2000, respectively, and increased such revenues by approximately $50,000 in 1998 as compared to estimated revenues had no hedging activities been conducted. The credit risk exposure from counterparty nonperformance on natural gas forward sales contracts and derivative financial instruments is generally the amount of unrealized gains under the contracts. The Partnership has not experienced counterparty nonperformance on these agreements. NOTE 6 - NEW ACCOUNTING PRONOUNCEMENTS The Partnership adopted Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities" ("SFAS 133") effective January 1, 2001. The statement, as amended, requires that all derivatives be recognized as either assets or liabilities and measured at fair value, and changes in the fair value of derivatives be reported in current earnings, unless the derivative is designated and effective as a hedge. If the intended 26 28 use of the derivative is to hedge the exposure to changes in the fair value of an asset, a liability or firm commitment, then the changes in the fair value of the derivative instrument will generally be offset in the income statement by the change in the item's fair value. However, if the intended use of the derivative is to hedge the exposure to variability in expected future cash flows then the changes in fair value of the derivative instrument will generally be reported in Other Comprehensive Income (OCI). The gains and losses on the derivative instrument that are reported in OCI will be reclassified to earnings in the period in which earnings are impacted by the hedged item. As of January 1, 2001, the Partnership is not party to any derivative instruments and as such there is no impact on its financial statements as a result of the adoption of SFAS 133. In the fourth quarter of 2000, the Partnership adopted Emerging Issues Task Force Issue No. 00-10 ("EITF No. 00-10") accounting for Shipping and Handling Fees and Costs. EITF No. 00-10 addresses how shipping and handling fees should be classified in the income statement. As a result of EITF No. 00-10, the Partnership has reclassified its transportation and compression expenses from oil and gas revenues to production expenses. As a result, $97,000, $48,000 and $7,000 of expenses were reclassified from oil and gas revenues to production expenses for the years ended December 31, 1998, 1999 and 2000, respectively. NOTE 7 - SUPPLEMENTARY FINANCIAL INFORMATION ON OIL AND GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED) This section provides information required by Statement of Financial Accounting Standards No. 69, "Disclosures about Oil and Gas Producing Activities." Capitalized costs. Capitalized costs and accumulated depreciation, depletion and amortization relating to oil and gas producing activities, all of which are conducted within the continental United States, are summarized below. (IN THOUSANDS)

Costs Incurred. All costs were incurred in oil and gas property development activities (as defined in the Partnership Agreement) and aggregated $52,000, $14,000 and $(23,000) in 1998, 1999 and 2000, respectively. Reserves. The following table summarizes the Partnership's net ownership interests in estimated quantities of proved oil and gas reserves and changes in net proved reserves, all of which are located in the continental United States, for the years ended December 31, 1998, 1999 and 2000. Oil and gas proved reserves cannot be measured exactly. Reserve estimates are inherently imprecise and may be expected to change as additional information becomes available. Estimates of oil and gas reserves, of necessity, are projections based on engineering data, and there are uncertainties inherent in the interpretation of such data as well as the projection of future rates of production and the timing of development expenditures. Reserve estimates are based on many factors related to reservoir performance which require evaluation by the engineers interpreting the available data, as well as price and other economic factors. The reliability of these estimates at any point in time depends on the quality and quantity of the technical and economic data, the production performance of the reservoirs as well as extensive engineering judgment. Further, estimates of the economically recoverable quantities of oil and natural gas attributable to any particular group of properties, classifications of such reserves based on risk of recovery and estimates of the future net revenues expected therefrom prepared by different engineers or by the same engineers at different times 27 29 may vary substantially. Consequently, reserve estimates are subject to revision as additional data becomes available during the producing life of a reservoir. There also can be no assurance that the reserves set forth herein will ultimately be produced. In addition, the estimates of future net revenues from proved reserves of the Partnership and the present value thereof are based upon certain assumptions about future production levels, prices and costs that may not be correct when judged against actual subsequent experience.

Standardized Measure. The following table of the Standardized Measure of Discounted Future Net Cash Flows concerning the standardized measure of future cash flows from proved oil and gas reserves are presented in accordance with Statement of Financial Accounting Standards No. 69. As prescribed by this statement, the amounts shown are based on prices and costs at the end of each period, and with a 10% annual discount factor. Extensive judgments are involved in estimating the timing of production and the costs that will be incurred throughout the remaining lives of the fields. Accordingly, the estimates of future net revenues from proved reserves and the present value thereof may not be materially correct when judged against actual subsequent results. Further, since prices and costs do not remain static, and no price or cost changes have been considered, and future production and development costs are estimates to be incurred in developing and producing the estimated proved oil and gas reserves, the results are not necessarily indicative of the fair market value of estimated proved reserves, and the results may not be comparable to estimates disclosed by other oil and gas producers. (IN THOUSANDS)

Future cash inflows are computed by applying year-end prices of oil and gas to year-end quantities of proved oil and gas reserves. Future production and development costs are computed by Kelley Oil's petroleum engineers by estimating the expenditures to be incurred in developing and producing the Partnership's proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions. 28 30 A discount factor of 10% was used to reflect the timing of future net cash flows. The standardized measure of discounted future net cash flows is not intended to represent the replacement cost or fair market value of the Partnership's oil and gas properties. The standardized measure of discounted future net cash flows as of December 31, 1998, 1999 and 2000 was calculated using prices in effect as of those dates, which averaged $9.88, $25.46 and $26.45, respectively, per barrel of oil and $2.06, $2.15 and $10.05, respectively, per Mcf of natural gas. Changes in Standardized Measure. Changes in standardized measure of future net cash flows relating to proved oil and gas reserves are summarized below. (IN THOUSANDS)

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURES None. 29 31 PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF KELLEY OIL CORPORATION GENERAL The Partnership has no directors, officers or employees. Directors and officers of Kelley Oil perform all management functions for the Partnership. Kelley Oil had 45 employees as of December 31, 2000, and its staff includes employees experienced in geology, geophysics, petroleum engineering, land acquisition and management, finance, accounting, and administration. BACKGROUND OF KELLEY OIL Kelley Oil is an oil and gas operating company formed in April 1983. Since January 1986, Kelley Oil has been engaged in the management of the DDPs. Since the Consolidation in February 1995, Kelley Oil has been a wholly-owned subsidiary of Contour Energy Co. (formerly Kelley Oil & Gas Corporation). EXECUTIVE OFFICERS OF KELLEY OIL Set forth below are the names, ages and positions of the current executive officers and directors of Kelley Oil. All directors are elected for a term of one year and serve until their successors are duly elected and qualified. All executive officers hold office until their successors are duly appointed and qualified.

John F. Bookout joined Kelley Oil as Chairman of the Board, President and Chief Executive Officer in February 1996. He served as Chairman of the Board of Contour Production Company L.L.C. ("Contour") since its inception in 1993. Rick G. Lester was elected Senior Vice President and Chief Financial Officer and a director of Kelley Oil in October 1998. Previously, he was Vice President and Chief Financial Officer of Domain Energy Corporation. Kenneth R. Sanders has served as Senior Vice President - Exploration and Production and a director of Kelley Oil since August 1999. Previously, he was Vice-President - Exploitation, Acquisitions & Engineering of Seagull Energy E&P, Inc. BENEFICIAL OWNERSHIP REPORTING Not applicable. 30 32 ITEM 11. EXECUTIVE COMPENSATION Not applicable. See "Certain Relationships and Related Transactions." ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT BENEFICIAL OWNERS The following table sets forth information as of December 31, 2000 with respect to the only Unitholder known by the Partnership to own beneficially more than five percent of the Partnership's Units.

MANAGEMENT The following table sets forth information as of December 31, 2000 with respect to Units beneficially owned, directly or indirectly, by each of the directors of Kelley Oil and by all officers and directors of Kelley Oil as a group.

(1) Represents direct beneficial ownership. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS The Unitholders have a 96.04% share and the General Partners a 3.96% share in the costs and revenues of the Partnership. Allocations of costs and revenues to Unitholders are made in accordance with the number of Units owned. The General Partners contributed $1,983,258 to the Partnership for their 3.96% interest in the same proportion as the deferred subscriptions for Units were payable. Kelley Oil is reimbursed for its direct costs and an allocable portion of its general and administrative expenses incurred as Managing General Partner. See Note 4 in the Notes to Financial Statements. It is the policy of the Partnership to engage in transactions with related parties only on terms that are no less favorable to the Partnership than could be obtained on an arm's-length basis from unrelated parties. The Partnership believes that all payments to related parties are reasonable and in amounts not greater than fees that would be charged on an arm's-length basis by unrelated parties. 31 33 PART IV ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K (a) FINANCIAL STATEMENTS AND SCHEDULES: (1) Financial Statements: The financial statements required to be filed are included under Item 8 of this Report. (2) Schedules: Schedules for which provision is made in applicable accounting regulations of the SEC are not required under the related instructions or are inapplicable, and therefore have been omitted. (3) Exhibits: EXHIBIT NUMBER: EXHIBIT 4.1 Amended and Restated Agreement of Limited Partnership of the Registrant (included as Exhibit A to the Prospectus forming part of the Registrant's Registration Statement on Form S-1 (File No. 33-51250) filed on August 26, 1992, as amended (the "Registration Statement") and incorporated herein by reference). 4.2 Joint Venture Agreement of Kelley Partners 1992 Development Drilling Joint Venture (incorporated by reference to Exhibit B to the Prospectus forming part of the Registration Statement). 4.3 Amendment to Amended and Restated Agreement of Limited Partnership of the Registrant. (b) REPORTS ON FORM 8-K: No reports on Form 8-K were filed by the Registrant during the fourth quarter of 2000. 32 34 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, this 28 day of March 2001. KELLEY PARTNERS 1992 DEVELOPMENT DRILLING PROGRAM By: KELLEY OIL CORPORATION, Managing General Partner By: /s/ John F. Bookout By: /s/ Rick G. Lester --------------------------------- -------------------------------- John F. Bookout Rick G. Lester Chief Executive Officer Senior Vice President and Chief Financial Officer Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed as of the 28 day of March 2001 by the following persons in their capacity as directors of the Registrant's managing general partner. /s/ John F. Bookout /s/ Kenneth R. Sanders --------------------------------- -------------------------------- John F. Bookout Kenneth R. Sanders /s/ Rick G. Lester --------------------------------- Rick G. Lester 33 35 INDEX TO EXHIBITS

KELLEY PARTNERS 1992 DEVELOPMENT DRILLING PROGRAM 10-K