ITEM 3. LEGAL PROCEEDINGS
KOGC, 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.

ITEM 5. MARKET FOR UNITS AND RELATED UNITHOLDER MATTERS
There is no market for the Units of the Partnership, and transfer of the Units is substantially restricted by the provisions of the Partnership Agreement. As of February 28, 1997, there were 798 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.
DISTRIBUTIONS 1994: First quarter.................................$ .08 Second quarter................................ .07 Third quarter................................. .04 Fourth quarter................................ --
1995: First quarter................................. -- Second quarter................................ -- Third quarter................................. .02 Fourth quarter................................ --
1996: First quarter................................. -- Second quarter................................ -- Third quarter................................. -- Fourth quarter................................ --
1997: First quarter................................. --
The distribution for each quarter in which payments were made represents substantially all of the Partnership's net available cash from the preceding quarter's operations. 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. Quarterly distributions are not expected to be reinstated until all Partnership indebtedness has been repaid. See "Management's Discussion and Analysis of Financial Condition and Results of Operations."
ITEM 6.

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 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)
YEAR ENDED DECEMBER 31, 1994 1995 1996 -------- ------- ------- SUMMARY OF OPERATIONS: Total revenues ............................. $ 7,171 5,713 4,991 Production expenses ........................ 1,261 1,223 816 Exploration and dry hole costs ............. 2,706 148 (3) General and administrative expenses ........ 599 474 325 Interest expense ........................... 157 672 810 Depreciation, depletion and amortization ... 8,497 4,945 1,280 Impairment of oil and gas properties ....... 9,638 11,082 -- Net income (loss) .......................... (15,687) (12,831) 1,763 Net income (loss) per Unit(1) .............. (.94) (.77) .11 Net available cash from operations(2) ...... 5,154 3,344 3,040 Net available cash per Unit(1)(2) .......... .31 .20 .18 Distributions paid per Unit(1) ............. .19 .02 -- Units outstanding .......................... 16,033 16,033 16,033
AS OF DECEMBER 31, 1994 1995 1996 -------- ------ ----- SUMMARY BALANCE SHEET DATA: Working capital (deficit) ............. $ (3,962) (1,857) 1,582 Oil and gas properties, net ........... 21,417 6,263 3,987 Long term debt ........................ 6,000 6,000 5,400 Total partners' equity (deficit) ...... 11,455 (1,594) 169 Total assets .......................... 23,149 7,724 6,169
(1) Per Unit amounts are based on the Unitholders' 96.04% share of net income and loss.
(2) The Partnership's net available cash generally corresponds to the sum of its net income or loss plus exploration and dry hole costs and noncash charges for impairment of oil and gas properties and depreciation, depletion and amortization.
ITEM 7.

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
GENERAL
PROPERTY IMPAIRMENT UNDER FAS 121. In the fourth quarter of 1995, the Partnership implemented the Financial Accounting Standards Board's Statement No. 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of ("FAS 121"). Under FAS 121, certain assets are required to be reviewed periodically for impairment whenever circumstances indicate their carrying amount exceeds their fair value and may not be recoverable. As a result of a decline in its proved reserves at January 1, 1996 from year-earlier levels, the Partnership performed an assessment of the carrying value of its oil and gas properties indicating an impairment should be recognized at year end. Under this analysis, the fair value of the Partnership's oil and gas properties was estimated on a depletable unit basis using escalated pricing and present value discount factors reflecting risk assessments. Based on this analysis, the Partnership recognized a noncash impairment charge of $8.7 million against the carrying value of its oil and gas properties under FAS 121 at December 31, 1995.
HEDGING ACTIVITIES. Kelley periodically has used forward sales contracts, natural gas swap agreements and options to reduce exposure to downward price fluctuations on its natural gas production. The swap agreements generally provide for Kelley to receive or make counterparty payments on the differential between a fixed price and a variable indexed price for natural gas. Gains and losses realized by Kelley from hedging activities are included in oil and gas revenues and average sales prices. Kelley's hedging activities also cover the oil and gas production attributable to the interest in such production
of the public unitholders in Kelley's subsidiary partnerships. Through a combination of natural gas swap agreements, forward sales contracts and options, approximately 55% of Kelley's natural gas production for 1996 was affected by Kelley's hedging transactions at an average NYMEX quoted price of $2.25 per MMBtu before transaction and transportation costs. Approximately 44% of Kelley's anticipated natural gas production for the first eight months of 1997 has been hedged by natural gas swap agreements at an average NYMEX quoted price of $2.42 per MMBtu before transaction and transportation costs. Hedging activities related to swaps and options reduced revenues by approximately $3.1 million in 1996 and increased revenues by approximately $1.8 million in 1995 as compared to estimated revenues had no hedging activities been conducted. Hedging activities were not material in 1994. At December 31, 1996, the Company had an unrealized loss of $2.6 million.
RESULTS OF OPERATIONS
YEAR ENDED DECEMBER 31, 1996 COMPARED TO YEAR ENDED DECEMBER 31, 1995. Oil and gas revenues of $4,807,000 in 1996 decreased 15.8% compared to $5,708,000 in 1995. Production of natural gas decreased 32.9% to 1,838,000 Mcf in 1996 from 2,741,000 Mcf in 1995, while the average price of natural gas increased 28.2% to $2.27 per Mcf in 1996 from $1.77 per Mcf in 1995. Production of crude oil in 1996 totaled 27,133 barrels, with an average sales price of $21.74 per barrel, compared to 40,936 barrels at $18.66 per barrel in 1995 the prior year, representing a volume decrease of 33.7% and a price increase of 16.5%. The decrease in oil and gas production and revenues iin 1996 reflects remedial requirements for several wells, normal depletion of other wells and the sale of 50% of the Partnership's interest in four wells, effective December 1, 1996.
Lease operating expenses and severance taxes were $816,000 in 1996 and $1,223,000 in 1995, a decrease of 33.3%, reflecting lower production levels and reduced workover costs. On a unit of production basis, these expenses remained constant at $0.41 per Mcfe in 1996 and 1995.
General and administrative expenses of $325,000 in 1996 decreased 31.4% from $474,000 in 1995, reflecting a reduction in the Partnership's share of administration costs associated with development operations of Kelley. On a unit of production basis, these expenses remained constant at $0.16 per Mcfe in 1996 and 1995.
In 1995 and 1996, the Partnership incurred interest expenses of $672,000 and $810,000, respectively, on a loan advanced in August 1994 to fund part of its drilling expenses in excess of contributed capital. See "Liquidity and Capital Resources" below.
Depreciation, depletion and amortization ("DD&A") decreased 74.1% from $4,945,000 in 1995 to $1,280,000 in 1996 due to lower production levels and lower depletion rates following noncash impairment charges aggregating $8,747,000 recognized in the fourth quarter of 1995 against the carrying value of the Partnership's oil and gas properties under FAS 121. See "General-Property Impairment under FAS 121" above. On a unit of production basis, DD&A decreased to $0.64 per Mcfe in 1996 from $1.66 per Mcfe in 1995.
The Partnership realized net income in 1996 of $1,763,000 or $0.11 per Unit compared to a net loss of $12,831,000 or $0.77 per Unit in 1995, reflecting the foregoing developments. Net available cash from Partnership operations (representing its net income or loss plus exploration and dry hole costs and noncash charges for DD&A and impairment of oil and gas properties) aggregated $3,040,000 or $0.18 per Unit in 1996 compared to $3,344,000 or $0.20 per Unit in 1995. In 1996, available cash was used to pay down loan costs.
YEAR ENDED DECEMBER 31, 1995 COMPARED TO YEAR ENDED DECEMBER 31, 1994. Oil and gas revenues of $5,708,000 in 1995 decreased 19.8% compared to $7,115,000 in 1994. During 1995, production of natural gas decreased 14.3% from 3,198,000 Mcf in 1994 to 2,741,000 Mcf, while the average price of natural gas decreased 3.3% from $1.83 per Mcf in 1994 to $1.77 per Mcf in 1995. Production of crude oil in 1995 totaled 40,936 barrels, with an average sales price of $18.66 per barrel compared to 73,706 barrels at $16.59 per barrel in the prior year, representing a volume decrease of 44.5% and a price increase of 12.5%.
The decrease in oil and gas production and revenues in 1995 reflected remedial requirements for several significant wells, normal depletion of other wells and the sale of one well. In addition, while natural gas prices remained depressed, hedging activities contributed $367,000 to oil and gas revenues in 1995.
Lease operating expenses and severance taxes were $1,223,000 in 1995 versus $1,261,000 in 1994, a decrease of 3.0%, reflecting lower production offset by higher workover costs in 1995. On a unit of production basis, these expenses increased to $0.41 per Mcfe in 1995 from $0.35 per Mcfe in the prior year.
In 1995 and 1994, the Partnership expensed exploration and dry hole costs of $148,000 and $2,706,000, respectively. The Partnership's exploration and dry hole costs for both years were incurred primarily for geological and geophysical expenses.
General and administrative expenses of $474,000 in 1995 decreased 20.9% from $599,000 in 1994, reflecting the Partnership's share of administration costs associated with development operations of Kelley. On a unit of production basis, these expenses remained constant at $0.16 per Mcfe in 1995 and the prior year.
In 1995 and 1994, the Partnership incurred interest expenses of $672,000 and $157,000, respectively, on a loan advanced in August 1994 to fund part of its drilling expenses in excess of contributed capital. See "Liquidity and Capital Resources" below.
DD&A decreased 41.8% from $8,497,000 in 1994 to $4,945,000 in 1995 as a result of lower net capitalized costs to amortize. On a unit of production basis, these noncash charges decreased to $1.66 per Mcfe in 1995 from $2.33 per Mcfe in the prior year. The Partnership also recognized noncash charges of $11,082,000 in 1995 and $9,638,000 in 1994 for impairment of its oil and gas properties. See "General-Property Impairment under FAS 121" above.
The Partnership recognized a net loss of $12,831,000 or $0.77 per Unit for 1995 compared to a net loss of $15,687,000 or $0.94 per Unit in the prior year, reflecting the foregoing developments. Net available cash from Partnership operations (representing its net loss plus exploration and dry hole costs and noncash charges for DD&A and impairment of oil and gas properties) aggregated $3,344,000 or $0.20 per Unit in 1995 compared to $5,154,000 or $0.31 per Unit in 1994.
LIQUIDITY AND CAPITAL RESOURCES
LIQUIDITY. Net cash used in the Partnership's operating activities during 1996, as reflected on its statement of cash flows, totaled $573,000. During the period, funds were provided by investing activities comprised of the sale of oil and gas properties and other non-current assets aggregating $1,321,000 and $99,000, respectively, partially offset by property and equipment expenditures of $239,000. In addition, cash was used in financing activities for the repayment of long-term borrowings. As a result of these activities, the Partnership's cash and cash equivalents increased to $22,000 at December 31, 1996 from $14,000 at December 31, 1995.
CAPITAL RESOURCES. The partners' equity at December 31, 1996 increased to $169,000. 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.
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 Kelley's borrowing cost resulting in an effective rate of 11.2% and 13.5% for 1995 and 1996, respectively. On December 31, 1996 the interest rate for the Initial Loan was reduced to 103/8% following the repayment of KOGC's 13 1/2% Senior Notes, which were replaced by 103/8% Senior Subordinated Notes during the fourth quarter.
In December 1996, KOGC entered into a $125 million revolving credit facility with a group of banks (the "Credit Facility"). The agreement for the Credit Facility requires the payment of interest only until December 2000, when all borrowings will be repayable. The Partnership and Joint Venture are guarantors under the Credit Facility. Although the Credit Facility is secured by all the oil and gas assets of Kelley Oil, Kelley Operating and the various guarantors, the lenders' recourse to Partnership and Joint Venture assets upon any default is limited after Partnership debt repayment to Kelley Oil's interest in the remaining assets.
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. During 1996, the Partnership's operating cash flow in excess of distributions was applied to pay interest on the Initial Loan and to reduce unfunded payables for third party drilling overexpenditures.
DISTRIBUTION POLICY. The Partnership maintains a policy of distributing the maximum amount of its net available cash to Unitholders on a quarterly basis. For these purposes, net available cash generally represents the net operating cash flow of the Partnership after deducting working capital requirements. To meet its financial obligations for the Drilling Overexpenditures, the Partnership suspended distributions commencing in October 1994 and reinstated a quarterly distribution for only one quarter in 1995. The Partnership's operating cash flow in excess of distributions in 1995 and all of its operating cash flow in 1996 were applied to pay interest on the Initial Loan and to reduce unfunded payables for third party Drilling Overexpenditures. While $5,400,000 of the $6,000,000 Initial Loan remained outstanding at December 31, 1996, the balance of the outstanding Drilling Overexpenditures was repaid in 1996. By continuing to service its debt from operating cash flow, the Partnership expects to further reduce the outstanding balance of the Initial Loan in 1997.
Net available cash per Unit from operations in the quarter and year ended December 31, 1996 was determined as follows:
QUARTER YEAR ENDED ENDED DECEMBER 31, DECEMBER 31, 1996 1996 -------- ------ Net income (loss) per Unit ..................... $ .04 .11 Depreciation, depletion and amortization charges per Unit.............................. .01 .07 -------- ------ Net available cash per Unit .................. $ .05 .18 ======== ======
INFLATION AND CHANGING PRICES. Oil and natural gas prices 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 gas prices received by Kelley Partners during the periods indicated.
AVERAGE AVERAGE OIL PRICE GAS PRICE ($/BBL) ($/MCF) YEAR ENDED: -------- --------- December 31, 1994..................................... $16.59 1.83 December 31, 1995..................................... 18.66 1.77 December 31, 1996..................................... 21.74 2.27
FORWARD-LOOKING STATEMENTS
FROM TIME TO TIME, THE PARTNERSHIP MAY PUBLISH 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, RESERVE ESTIMATES, RATES AND TIMING OF FUTURE PRODUCTION OF OIL AND GAS, AND CHANGES IN THE LEVEL AND TIMING OF FUTURE COSTS AND EXPENSES RELATED TO DRILLING AND OPERATING ACTIVITIES.
WORDS SUCH AS "ANTICIPATED," "EXPERT," "ESTIMATE," "PROJECT" AND SIMILAR EXPRESSIONS ARE INTENDED TO IDENTIFY FORWARD-LOOKING STATEMENTS. FORWARD-LOOKING STATEMENTS MAY BE MADE IN MANAGEMENT'S STATEMENTS (ORALLY OR IN WRITING) INCLUDING PRESS RELEASES, AND IN FILINGS OF THE SEC, INCLUDING THIS REPORT.
In addition to "Uncertainties in Estimating Reserves" and other such factors mentioned in this Report, the following additional risk factors should be considered:
SUBSTANTIAL LEVERAGE. As of December 31, 1996, the Partnership has total indebtedness for money borrowed of approximately $5.4 million and partners' equity of approximately $0.2 million. The Partnership's ability to make scheduled payments of principal, to pay interest on or to refinance its indebtedness for money borrowed depends on its future performance, which is subject not only to its own actions but also to general economic, financial, competitive, legislative, regulatory and other factors beyond its control, as well as to the prevailing market prices for oil, natural gas and natural gas liquids.
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 business plan does not contemplate developing or acquiring additional 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 prices received by the Partnership for its oil, natural gas and natural gas liquids production and the levels of production are subject to government regulation, legislation and policies. 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 producing its reserves.
OPERATING HAZARDS AND UNINSURED RISKS. The Partnership's oil and natural gas business also is subject to all of the operating risks associated with the production of oil and natural gas, including uncontrollable flows of oil, natural gas, brine or well fluids into the environment (including groundwater and shoreline contamination), cratering, mechanical difficulties, fires, explosions, pollution and other risks, any of which could result in substantial losses. 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.
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 shut in for lack of a market or because of inadequacy or unavailability of natural gas pipeline or gathering system capacity.
ITEM 8.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
KELLEY PARTNERS 1992 DEVELOPMENT DRILLING PROGRAM: PAGE ----
Independent Auditors' Reports............................................ 19 Balance Sheets - December 31, 1996 and 1995.............................. 21 Statements of Operations - For the years ended December 31, 1996, 1995 and 1994...................................... 22 Statements of Cash Flows - For the years ended December 31, 1996, 1995 and 1994...................................... 23 Statements of Changes in Partners' Equity (Deficit) - For the years ended December 31, 1996, 1995 and 1994.................. 24 Notes to Financial Statements............................................ 25
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, 1996 and 1995, and the related statements of operations, cash flows, and changes in partners' equity (deficit) for each of the two years in the period ended December 31, 1996. These financial statements are the responsibility of management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such financial statements present fairly, in all material respects, the financial position of Kelley Partners 1992 Development Drilling Program at December 31, 1996 and 1995, and the results of its operations and its cash flows for each of the two years in the period ended December 31, 1996, in conformity with generally accepted accounting principles.
As discussed in Note 1, in 1995 the Partnership changed its method of accounting for the impairment of long-lived assets to conform with Statement of Financial Accounting Standards No. 121.
DELOITTE & TOUCHE LLP
Houston, Texas March 3, 1997
REPORT OF INDEPENDENT AUDITORS
To the Partners of Kelley Partners 1992 Development Drilling Program
We have audited the balance sheet of Kelley Partners 1992 Development Drilling Program (a Texas limited partnership) as of December 31, 1994, and the related statements of operations, partners' equity, and cash flows for the year then ended. The balance sheet as of December 31, 1994 is not presented separately herein. These financial statements are the responsibility of management. Our responsibility is to express an opinion on these financial statements based on our audits.
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 Kelley Partners 1992 Development Drilling Program at December 31, 1994 and results of its operations and its cash flows for the year then ended, in conformity with generally accepted accounting principles.
Ernst & Young LLP
Houston, Texas March 6, 1995
KELLEY PARTNERS 1992 DEVELOPMENT DRILLING PROGRAM BALANCE SHEETS
($ IN THOUSANDS)
DECEMBER 31, 1995 1996 -------- ------- ASSETS: Cash and cash equivalents ............................. $ 14 22 Accounts receivable - trade ........................... 171 126 Accounts receivable - affiliates ...................... 1,255 2,034 Other assets .......................................... 21 -- -------- ------- Total current assets ................................. 1,461 2,182 -------- -------
Oil and gas properties, successful efforts method: Properties subject to amortization ................... 45,230 44,333 Less: Accumulated depreciation, depletion & amortization ..................................... (38,967) (40,346) -------- ------- Total oil and gas properties ......................... 6,263 3,987 -------- ------- TOTAL ASSETS .......................................... $ 7,724 6,169 ======== =======
LIABILITIES: Accounts payable and accrued expenses ................. $ 375 143 Accounts payable - affiliates ......................... 2,943 457 -------- ------- Total current liabilities ............................ 3,318 600 -------- ------- Notes payable - long term ............................. 6,000 5,400 -------- ------- TOTAL LIABILITIES .................................... 9,318 6,000 -------- -------
PARTNERS' EQUITY (DEFICIT): LP Unitholders' equity (deficit) ...................... (183) (9) GP Unitholders' equity (deficit) ...................... (1,349) 171 Managing and Special General Partners' equity (deficit) (62) 7 -------- ------- TOTAL PARTNERS' EQUITY (DEFICIT) ..................... (1,594) 169 -------- ------- TOTAL LIABILITIES AND PARTNERS' EQUITY ................ $ 7,724 6,169 ======== =======
See Notes to Financial Statements.
KELLEY PARTNERS 1992 DEVELOPMENT DRILLING PROGRAM STATEMENTS OF OPERATIONS
(IN THOUSANDS, EXCEPT PER UNIT DATA)
YEAR ENDED DECEMBER 31, ------------------------------ 1994 1995 1996 -------- ------- ------- REVENUES: Oil and gas sales .......................... $ 7,115 5,708 4,807 Interest and other income .................. 56 5 184 -------- ------- ------- Total revenues ............................ 7,171 5,713 4,991 -------- ------- -------
COSTS AND EXPENSES: Lease operating expenses ................... 856 889 624 Severance taxes ............................ 405 334 192 Exploration and dry hole costs ............. 2,706 148 (3) General and administrative expenses ........ 599 474 325 Interest expense ........................... 157 672 810 Depreciation, depletion and amortization ... 8,497 4,945 1,280 Impairment of oil and gas properties ....... 9,638 11,082 -- -------- ------- ------- Total costs and expenses .................. 22,858 18,544 3,228 -------- ------- ------- NET INCOME (LOSS) ............................ $(15,687) (12,831) 1,763 ======== ======= =======
NET INCOME (LOSS) ALLOCABLE TO LP UNITHOLDERS $ (1,460) (1,262) 174 ======== ======= =======
NET INCOME (LOSS) ALLOCABLE TO GP UNITHOLDERS $(13,606) (11,061) 1,520 ======== ======= =======
NET INCOME (LOSS) ALLOCABLE TO MANAGING AND SPECIAL GENERAL PARTNERS ................... $ (621) (508) 69 ======== ======= =======
NET INCOME (LOSS) PER UNIT ................... $ (.94) (.77) .11 ======== ======= =======
Average Units outstanding .................... 16,033 16,033 16,033 ======== ======= =======
See Notes to Financial Statements.
KELLEY PARTNERS 1992 DEVELOPMENT DRILLING PROGRAM STATEMENTS OF CASH FLOWS
(IN THOUSANDS)
See Notes to Financial Statements.
KELLEY PARTNERS 1992 DEVELOPMENT DRILLING PROGRAM STATEMENTS OF CHANGES IN PARTNERS' EQUITY (DEFICIT)
(IN THOUSANDS)
See Notes to Financial Statements.
KELLEY PARTNERS 1992 DEVELOPMENT DRILLING PROGRAM NOTES TO FINANCIAL STATEMENTS
NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
ORGANIZATION. Kelley Partners 1992 Development Drilling Program, a Texas limited partnership (the "Partnership"), was formed in June 1992 and commenced operations on November 27, 1992 upon completion of a public offering of 16,033,009 units of limited partner interests and general partner interests (the "Units") in the Partnership at $3.00 per Unit. Kelley Oil Corporation ("Kelley Oil") serves as the managing general partner of the Partnership, and David L. Kelley serves as the special general partner of the Partnership.
The sole purpose of the Partnership is to finance the drilling of development wells, as defined in its partnership agreement (the "Partnership Agreement"), on selected properties owned by Kelley Operating Company, Ltd. ("Kelley Operating"), a Texas limited partnership of which Kelley Oil & Gas Partners, Ltd. ("Kelley Partners") was the sole limited partner. The Partnership's development activities have been conducted through a joint venture (the "Joint Venture") between the Partnership and Kelley Operating, which has retained a 20% interest in the Joint Venture after Payout (as defined in the Joint Venture Agreement) in consideration of its contribution of drilling rights. In February 1995, the equity interests in Kelley Partners and Kelley Oil were consolidated (the "Consolidation") in Kelley Oil & Gas Corporation (collectively with its predecessors, "KOGC"). In March 1996, Kelley Partners was merged into KOGC, and Kelley Partners' 98% limited partner interest in Kelley Operating was transferred to Kelley Oil.
The general partners own in the aggregate a 3.96% general partner interest in the Partnership. In addition, as of December 31, 1996, Kelley Oil and its officers and directors owned 13,422,310 (83.72%) Units and 2,000 (.01%) Units, respectively. The Partnership has no officers, directors or employees. The officers and employees of Kelley Oil perform the management and administrative functions of the Partnership. 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.
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. 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. Cost centers for amortization purposes are determined on a field-by-field basis. Estimated future abandonment and site restoration costs, net of anticipated salvage values, are taken into account in depreciation, depletion and amortization.
The successful efforts method imposes limitations on the carrying or book value of oil and gas properties and requires an impairment provision or noncash charge against earnings for any quarter in which the carrying value of oil and gas properties exceeds the standardized measure of undiscounted future net cash flows from its proved oil and gas reserves based on prices received for its oil and gas production as of the end of that quarter or a subsequent date prior to publication of financial results for the quarter. As a result of declines in natural gas prices, the Partnership recognized noncash charges for impairment of oil and gas properties aggregating $9,638,000 during 1994.
PROPERTY IMPAIRMENT UNDER FAS 121. In the fourth quarter of 1995, the Partnership implemented the Financial Accounting Standards Board's Statement No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of" ("FAS 121"). Under FAS 121, certain assets are required to be reviewed periodically for impairment whenever circumstances indicate their carrying amount exceeds their fair value and may not be recoverable. As a result a decline in its proved reserves at January 1, 1996 from year-earlier levels, the Partnership performed an assessment of the carrying value of its oil and gas properties indicating an impairment should be recognized at year end. Under this analysis, the fair value of the Partnership's oil and gas properties was estimated on a depletable unit basis using escalated pricing and present value discount factors reflecting risk assessments. Based on this analysis, the Partnership recognized a noncash impairment charge of $8,747,000 against the carrying value of its oil and gas properties under FAS 121 at December 31, 1995.
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 and debt. As of December 31, 1996, the estimated fair value of the Partnership's debt approximated its carrying value. The estimated fair values at December 31, 1996 were determined using the borrowing rates available for debt with similar terms and maturities.
DERIVATIVE FINANCIAL INSTRUMENTS. From time to time, the Partnership has entered into transactions in derivative financial instruments covering future natural gas production principally as a hedge against natural gas price declines. Realized and unrealized gains and losses are recorded in other assets or liabilities until the underlying natural gas is produced and sold, at which time those gains and losses are included in oil and gas revenues. See Note 6 - Hedging Activities.
CONCENTRATION OF CREDIT RISK. Substantially all of the Partnership's receivables are due from the marketing subsidiary of Kelley Oil, which purchases natural gas for resale to a limited number of natural gas transmission companies and other gas purchasers. See Note 4 - Related Party Transactions.
RISKS AND UNCERTAINTIES. 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 those estimates.
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 Kelley's borrowing cost resulting in an effective rate of 11.2% and 13.5% for 1995 and 1996, respectively. On December 31, 1996, the interest rate for the Initial Loan was reduced to 103/8% following the repayment of KOGC's 13 1/2% Senior Notes, which were replaced by 103/8% Senior Subordinated Notes during the fourth quarter.
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. During 1995 and 1996, the Partnership's operating cash flow in excess of distributions was applied to pay interest on the Initial Loan and to reduce unfunded payables for third party drilling overexpenditures. While $5,400,000 of the $6,000,000 Initial Loan remained outstanding at December 31, 1996, the balance of the outstanding Drilling Overexpenditures was repaid in 1996. By continuing to service its debt from operating cash flow, the Partnership expects to further reduce the outstanding balance of the Initial Loan in 1997.
In December 1996, KOGC entered into a $125 million revolving credit facility with a group of banks (the "Credit Facility"). The agreement for the Credit Facility requires the payment of interest only until December 2000, when all borrowings will be repayable. The Partnership and Joint Venture are guarantors under the Credit Facility. Although the Credit Facility is secured by all the oil and gas assets of Kelley Oil, Kelley Operating and the various guarantors, the lenders' recourse to Partnership and Joint Venture assets upon any default is limited after Partnership debt repayment to Kelley Oil's interest in the remaining assets.
NOTE 3 - CASH DISTRIBUTIONS
The following table sets forth, for the periods indicated, the distributions per Unit. Cash distributions were paid in the quarter indicated and were based upon net available cash generated from operations in the preceding quarter.
1994 1995 1996 ------ ------ -----
First quarter.........................................$ .08 -- -- Second quarter........................................ .07 -- -- Third quarter......................................... .04 .02 -- Fourth quarter........................................ -- -- -- ------ ------ ------ Totals..............................................$ .19 .02 -- ====== ====== ======
To enable to Partnership to fund part of its drilling and recompletion expenditures in excess of contributed capital, distributions were suspended in October 1994 and reinstated for only one quarter in 1995. See Note 2 - Long-Term Debt.
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.
Kelley Oil is reimbursed by the Partnership for costs directly associated with acquisition, exploration and development activities. For the years ended December 31, 1994, 1995 and 1996, these costs aggregated $2,080,000, $220,000, and $1,000, respectively. The Partnership capitalized $1,347,000, $77,000, and $1,000 of allocated direct costs to oil and gas properties for the years ended December 31, 1994, 1995 and 1996, respectively.
Overhead allocated to the Partnership by Kelley Oil for the years ended December 31, 1994, 1995 and 1996 related to general and administrative expenses aggregated $538,000, $391,000 and $227,000, respectively.
Substantially all gas sales of KOGC and its subsidiaries, including the Partnership (collectively, "Kelley"), are made to an affiliated company, Concorde Gas Marketing, Inc., a wholly owned subsidiary of Kelley Oil ("CGM"), which remarkets gas to third parties. During 1994, CGM received for its services either fees or a marketing differential equal to $0.05 per MMBtu of gas sold and delivered. For 1995 and 1996, the fee was modified to 2% of the resale price for marketed natural gas.
NOTE 5 - SALES TO MAJOR CUSTOMERS
Sales to customers in excess of 10% of total oil and gas sales for the years ended December 31, 1994, 1995 and 1996 were as follows:
(IN THOUSANDS)
YEAR ENDED DECEMBER 31, ----------------------------- 1994 1995 1996 ------ ------ -----
Concorde Gas Marketing(1).......................5,769 4,749 3,585 Falco S & D Inc................................. 864 583 176
(1) During 1996, approximately 52% of CGM's gas purchases were made for resale to Sonat Marketing Company (28%), Coral Energy Resources (20%) and LIG Chemical Company (10%). During 1995, approximately 82% of CGM's resales were made to Sonat Marketing Company (22%), Associataed Natural Gas, Inc. (21%), Pontchartrain Natural Gas System (17%), Transok Gas Company (12%) and LIG Chemical Company (10%). During 1994, approximately 73% of GCM's resales were made to Pontchartrain Natural Gas System (23%), LIG Chemical Company (22%), Associated Natural Gas, Inc. (18%) and Fina Natural Gas Company (10%).
NOTE 6 - HEDGING ACTIVITIES
Kelley periodically has used forward sales contracts, natural gas swap agreements and options to reduce exposure to downward price fluctuations on its natural gas production. The swap agreements generally provide for Kelley to receive or make counterparty payments on the differential between a fixed price and a variable indexed price for natural gas. Gains and losses realized by Kelley from hedging activities are included in oil and gas revenues and average sales prices. Kelley's hedging activities also cover the oil and gas production attributable to the interest in such production of the public unitholders in Kelley's subsidiary partnerships. Through a combination of natural gas swap agreements, forward sales contracts and options, approximately 55% of Kelley's natural gas production for 1996 was affected by Kelley's hedging transactions at an average NYMEX quoted price of $2.25 per MMBtu before transaction and transportation costs. Approximately 44% of Kelley's anticipated natural gas production for the first eight months of 1997 has been hedged by natural gas swap agreements at an average NYMEX quoted price of $2.42 per MMBtu before transaction and transportation costs. Hedging activities related to swaps and options reduced revenues by approximately $3.1 million in 1996 and increased revenues by approximately $1.8 million in 1995 as compared to estimated revenues had no hedging activities been conducted. Hedging activities were not material in 1994. At December 31, 1996, the Company had an unrealized loss of $2.6 million.
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 and does not anticipate any in future periods.
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)
YEAR ENDED DECEMBER 31, ----------------------------- 1994 1995 1996 ------ ------ ----- Unevaluated properties ..................... $ -- -- -- Evaluated properties subject to amortization 44,214 45,230 44,333 ------- ------ ------ Total properties subject to amortization . 44,214 45,230 44,333 Accumulated depreciation, depletion and amortization ............................. (22,797) (38,967) (40,346) -------- ------- ------- Net capitalized costs .................... $ 21,417 6,263 3,987 ======== ======= =======
COSTS INCURRED. All costs were incurred in oil and gas property development activities (as defined in the Partnership Agreement) and aggregated $16,903,000, $1,545,000 and $238,593 in 1994, 1995 and 1996, 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, 1994, 1995 and 1996 are summarized below. Reserves estimates contained below were prepared by H.J. Gruy & Associates, Inc. ("Gruy"), independent petroleum engineers, for 1995 and 1996, and were prepared by the Company and reviewed by Gruy for 1994. See "Estimated Proved Reserves-Uncertainties in Estimating Reserves" under Items 1 and 2 of this Form 10-K.
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)
AS OF DECEMBER 31, ------------------------------------- 1994 1995 1996 -------- ------- ------- Future cash inflows ................. $ 28,819 25,546 29,709 Future production costs ............. (6,937) (5,502) (3,141) Future development costs ............ (465) (60) (77) -------- ------- ------- Future net cash flows .............. 21,417 19,984 26,491 10% annual discount for estimating timing of cash flows.... (5,980) (7,090) (10,771) -------- ------- ------- Standardized measure of discounted future net cash flows............................ 15,437 12,894 15,720
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.
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, 1994, 1995 and 1996 was calculated using prices in effect as of those dates, which averaged $15.65, $19.73 and $25.36, respectively, per barrel of oil and $1.64, $2.11 and $3.72, 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)
Sales of oil and gas, net of production costs, are based on historical results. Extensions and discoveries, the changes due to revisions in standardized variables and the accretion of discount are reported on a discounted basis.
ITEM 9.

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURES
In connection with the Contour Transaction, the Partnership dismissed Ernst & Young LLP ("E&Y") as its principal accountants, effective February 15, 1996. On the same date, the Partnership engaged Deloitte & Touche LLP ("D&T") as its principal accountants to audit its financial statements. The change in accountants was approved by the audit committee of the board of directors of Kelley Oil, contingent upon the closing under the Purchase Agreement. Neither of E&Y's reports on the Partnership's financial statements for the years ended December 31, 1993 and 1994 contained an adverse opinion or disclaimer of opinion, or was qualified or modified as to uncertainty, audit scope or accounting principles. During the last two years and the interim period prior to the date of the change in accountants, (i) the Partnership had no disagreements with E&Y on any matter of accounting principles or practices, financial statement disclosure or auditing scope or procedure, (ii) E&Y did not advise the Partnership of any "reportable event" as defined in Regulation S-K under the Securities Exchange Act of 1934 and (iii) the Partnership did not consult with D&T on any accounting, auditing, financial reporting or any other matters.
PART III
ITEM 10.

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 70 employees as of December 31, 1996, 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 a publicly held independent oil and gas 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 KOGC.
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.
OFFICER OR DIRECTOR OF THE COMPANY NAME AGE POSITION SINCE - ---- --- -------- ----------- John F. Bookout.......74 President, Chief Executive Officer 1996 and a director David C. Baggett......35 Senior Vice President and Chief 1997 Financial Officer and a director Dallas D. Laumbach....60 Senior Vice President-Exploration 1996 and Production and a director Thomas E. Baker.......66 General Counsel and Corporate Secretary 1996
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. From 1988 through 1993, he served as a member of the Supervisory Board of Royal Dutch Petroleum. He currently serves on the board of directors of McDermott International Inc., J. Ray McDermott, S.A. and The Investment Company of America as well as the board of trustees of the United States Counsel for International Business and various civic and educational bodies.
DAVID C. BAGGETT was elected Senior Vice President and Chief Financial Officer and a director of Kelley Oil in March 1997. Previously, he was a partner with Deloitte & Touche LLP for more than five years.
DALLAS D. LAUMBACH has served as Senior Vice President-Exploration and Production and a director of Kelley Oil since February 1996 and has served concurrently as President of Concorde Gas, Inc. since August 1996. He previously served as Senior Vice President of Contour commencing in December 1993. Before joining Contour, Mr. Laumbach served in positions of increasing responsibility for 24 years at Shell Oil Company, concluding as Manager-Business Development in Shell's Head Office.
THOMAS E. BAKER is an attorney and joined Kelley Oil in July 1996 as General Counsel and Corporate Secretary. From August 1991 through June 1996, Mr. Baker was engaged in a private consulting practice.
BENEFICIAL OWNERSHIP REPORTING
Not applicable.
ITEM 11.

ITEM 11. EXECUTIVE COMPENSATION
Not applicable. See "Certain Relationships and Related Transactions."
ITEM 12.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
BENEFICIAL OWNERS
The following table sets forth information as of December 31, 1996 with respect to the only Unitholder known by the Partnership to own beneficially more than five percent of the Partnership's Units.
AMOUNT & NATURE NAME AND ADDRESS OF OF BENEFICIAL PERCENT BENEFICIAL OWNER OWNERSHIP OF CLASS - ------------------- --------------- -------- Kelley Oil Corporation 13,422,310 83.72% 601 Jefferson, Suite 1100 Direct Houston, Texas 77002
MANAGEMENT
The following table sets forth information as of December 31, 1996 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.
AMOUNT & NATURE NAME AND ADDRESS OF OF BENEFICIAL PERCENT BENEFICIAL OWNER OWNERSHIP(1) OF CLASS - ------------------- --------------- -------- John F. Bookout -- -- Dallas D. Laumbach -- -- David C. Baggett -- -- All directors and officers as a group (9 persons) 2,000 .01%
(1) Represents direct beneficial ownership.
ITEM 13.

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. During 1994, 1995 and 1996, Kelley Oil was reimbursed by the Partnership for costs directly associated with the Partnership's development drilling activities in the amounts of $2,080,000, $220,000 and $1,000, respectively. Kelley Oil was reimbursed for its general and administrative expenses allocable to Partnership operations in the amount of $538,000, $391,000 and $227,000 in 1994, 1995 and 1996, respectively.
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.
PART IV
ITEM 14.

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).
(b)REPORTS ON FORM 8-K:
No reports on Form 8-K were filed by the Registrant during the fourth quarter of 1996.
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 27th day of March, 1997.
KELLEY PARTNERS 1992 DEVELOPMENT DRILLING PROGRAM
By: KELLEY OIL CORPORATION, Managing General Partner
By:/S/ JOHN F. BOOKOUT By:/S/ DAVID C. BAGGETT By:/S/ LAWRENCE G. MARBLE John F. Bookout David C. Baggett Lawrence G. Marble Chief Executive Officer Senior Vice President Controller and Chief Financial Officer (Chief Accounting Officer)
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed as of the 27th day of March, 1996 by the following persons in their capacity as directors of the Registrant's managing general partner.
/S/ JOHN F. BOOKOUT /S/ DALLAS D. LAUMBACH John F. Bookout Dallas D. Laumbach
/S/ DAVID C. BAGGETT Davd C. Baggett