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.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
Not applicable.
PART II
ITEM 5.
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, 2000, there were 803 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. 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)
(1) Per Unit amounts are based on the Unitholders' 96.04% share of net income and loss.
ITEM 7.
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, 1999. 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. Kelley Oil Corporation, managing general partner of the Partnership ("Kelley Oil") and a wholly-owned subsidiary of Contour Energy Co. (formerly Kelly Oil & Gas Corporation ) (Contour), owns 83.72% of the Units, together with its 3.94% managing general partnership 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. Contour has periodically used forward sales contracts, natural gas and crude oil price swap agreements, natural gas basis swap agreements and options to reduce exposure to downward price fluctuations on its natural
gas and crude oil production. Contour does not engage in speculative transactions. Contour's hedging activities also cover the oil and gas production attributable to the Partnership, including the interest in such production of the public unitholders of the Partnership. During 1999, Contour used price and basis swap agreements. Price swap agreements generally provide for the Partnership to receive or make counterparty payments on the differential between a fixed price and a variable indexed price for natural gas. Basis swap agreements generally provide for the Partnership to receive or make counterparty payments on the differential between a variable indexed price and the price it receives from the sale of natural gas production, and are used to hedge against unfavorable price movements in the relationship between such variable indexed price and the price received for such production. Additionally, Contour must provide cash collateral for any hedges (through swap or other agreements) to cover counter-party risk to the hedging party. 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.
Through natural gas price swap agreements, the Partnership hedged approximately 65%, 49% and 50%, respectively, of its natural gas production for 1997, 1998 and 1999, respectively, at average NYMEX quoted prices of $2.35, $2.31 and $2.17 per Mmbtu, respectively, before transaction and transportation costs. As of December 31, 1999, approximately 8% of the Partnership's anticipated natural gas production for 2000 has been hedged by natural gas price swap agreements at an average NYMEX quoted price of $2.41 per Mmbtu before transaction and transportation costs. Per additional hedging activities since December 31, 1999, approximately 47% of the Partnership's anticipated natural gas production for 2000 has been hedged at an average NYMEX quoted price of $2.56 per Mmbtu before transaction and transportation. 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 either 1997 or 1998. As of December 31, 1999, approximately 7% of the Partnership's crude oil production for 2000 had been hedged by crude oil price swap agreements at an average NYMEX quoted price of $25.05 per bbl before transaction and transportation costs. Per additional hedging activities since December 31, 1999, approximately 43% of the Partnership's anticipated crude oil production for 2000 has been hedged at an average NYMEX quoted price of $26.21 per bbl before transaction and transportation costs. Hedging activities decreased Partnership revenues by approximately $156,000 and $17,000 in 1997 and 1999, respectively, and increased such revenues by approximately $50,000 in 1998 as compared to estimated revenues had no hedging activities been conducted. At December 31, 1999, the unrealized gain/loss on the Partnership's existing hedging instruments for future production months in 2000 was not material.
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.
RESULTS OF OPERATIONS
Years Ended December 31, 1999 and 1998. Oil and gas revenues of $795,000 for 1999 decreased 43% compared to $1,398,000 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.
Lease operating expenses and severance taxes were $330,000 in 1999 versus $497,000 in 1998, a decrease of 37%, primarily related to the sale of properties to Phillips. On a unit of production basis, these expenses increased to $0.89 per Mcfe in 1999 from $0.75 per Mcfe in 1998.
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 reduction reflects the lower average note payable balance outstanding in 1999 as compared to 1998. See "Liquidity and Capital Resources" below.
Depreciation, depletion and amortization ("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, under Statement of Financial Accounting Standards No. 121 ("SFAS 121"), "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of," the Partnership recognized a non-cash impairment charge of $466 thousand against the carrying values of its proved oil and gas properties, for the year ended December 31, 1998 (see "Property Impairment under SFAS 121" in Note 2 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)er Unit. The reasons for the variance between 1999 and 1998 are described in the foregoing discussion.
Years Ended December 31, 1998 and 1997. Oil and gas revenues of $1,398,000 for 1998 decreased 40% compared to $2,322,000 in the corresponding period of 1997 primarily as a result of lower oil and gas production. Production of natural gas decreased 38% from 963,000 Mcf in 1997 to 601,000 Mcf in 1998. Production of crude oil in the current year totaled 10,172 barrels compared to 11,395 barrels last year, representing a decrease of 11%. Oil and gas production decreased due to natural depletion.
Lease operating expenses and severance taxes were $497,000 in 1998 versus $576,000 in 1997, a decrease of 14%, reflecting lower production levels. On a unit of production basis, these expenses increased to $0.75 per Mcfe in 1998 from $0.56 per Mcfe in 1997.
General and administrative expenses of $134,000 in 1998 decreased 72% from $476,000 in 1997. On a unit of production basis, these expenses decreased from $0.46 per Mcfe in 1997 to $0.20 per Mcfe in 1998.
In 1998 and 1997, the Partnership incurred interest expense of $287,000 and $376,000, 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 1998 as compared to 1997. See "Liquidity and Capital Resources" below.
Depreciation, depletion and amortization ("DD&A") expense decreased 27% from $587,000 in 1997 to $427,000 in 1998 due to lower production levels and lower depletion rates. On a unit of production basis, DD&A expense increased from $0.57 per Mcfe in 1997 to $0.64 per Mcfe in 1998.
In 1998, under Statement of Financial Accounting Standards No. 121 ("SFAS 121"), "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of," the Partnership recognized a non-cash impairment charge of $466 thousand against the carrying values of its proved oil and gas properties, for the year ended December 31, 1998 (see "Property Impairment under SFAS 121" in Note 2 to the Financial Statements).
The Partnership recognized a net loss in 1998 of $413,000 or $(0.02) per Unit compared to net income in 1997 of $307,000 or $0.02 per Unit. The reasons for the variance between 1998 and 1997 are described in the foregoing discussion.
LIQUIDITY AND CAPITAL RESOURCES
Liquidity. Net cash provided by the Partnership's operating activities during 1999, as reflected on its statement of cash flows, totaled $238,000. During the period, funds provided by investing activities included proceeds from the sale of properties to Phillips of $2,098,000, partially offset by capital expenditures of $14,000, and funds used in financing activities included a reduction in the Initial Loan principal of $2,322,000. As a result of these activities, the Partnership's cash and cash equivalents remained at zero at December 31, 1999 and December 31, 1998.
In 1999, Contour undertook several strategic actions in response to the severe downturn in the industry in 1998 caused by low commodity prices and the closing of the capital markets to smaller oil and gas companies. These actions, described below, were designed to increase the near-term liquidity of Contour, Kelley Oil and the Partnership, provide capital for ongoing capital expenditure programs and establish a stronger base for future growth.
In April 1999, Contour entered into an Exploration and Development Agreement with Phillips Petroleum Company ("Phillips") relating to certain of its interests in the Bryceland, West Bryceland and Sailes fields in north Louisiana ("Phillips Transaction"). Pursuant to the agreement, Contour: (1) received an $83 million cash payment, (2) retained a 42 Bcf, 8-year volumetric overriding royalty interest and a 1% override on the excess production above such royalty interest and (3) retained 25% of its working interest in the Cotton Valley formation. In addition, Phillips, will at its risk and expense, operate, develop, exploit and explore the properties thereby relieving Contour of significant operating, exploration and development costs in the future. The transaction closed on May 17, 1999.
As part of the Phillips Transaction described above, the Partnership conveyed its interest in the West Bryceland and Sailes fields to Phillips for $2.1 million. The Partnership's reserve quantities attributable to such fields represented approximately one-half of the Partnership's total reserve quantities at January 1, 1999 and one-half of its total 1998 production. In the third quarter of 1999, the sales proceeds were applied to reduce the Partnership's loan to Kelley Oil.
In April 1999, Contour negotiated a private offering of $135 million principal amount, 14% Senior Secured Notes (the "Notes"). The Notes are secured by a first lien on substantially all of Contour's proved oil and natural gas properties remaining after the sale to Phillips and guaranteed by three entities wholly-owned by Contour. In accordance with the Notes indenture, on June 30, 1999, Contour funded $37.5 million to repurchase $35 million principal amount of the Notes at a repurchase price equal to 104% of the principal amount, plus accrued and unpaid interest and commitment fees to the date of the repurchase.
On May 17, 1999, Contour funded $28.5 million to repurchase $46.1 million of the outstanding principal amounts of its 7 7/8% Convertible Subordinated Notes due December 15, 1999 and its 8 1/2% Convertible Subordinated Debentures due April 1, 2000 (collectively, the "Securities") at a price equal to $590 per $1,000 principal amount (not including accrued interest paid of $1.2 million).
In addition, on May 17, 1999, Contour repaid all borrowings outstanding under its credit facility of $115.5 million plus accrued interest and terminated the revolving credit facility and funded cash collateral for a $1.5 million letter of credit which was subsequently increased to $7.5 million. Contour used net proceeds remaining from the transactions for general corporate purposes.
Contour has received the benefits of a general increase in the level of commodity prices over the past several months. This increase, combined with the actions described above, have provided Contour with near-term liquidity and capital for its ongoing operations. However, the commodity markets are volatile and there is no certainty that current oil and natural gas prices can be sustained at these levels. In addition, Contour continues to have significant debt outstanding relative to its asset base and pays a high portion of its cash flow to service such debt. Furthermore, as Contour does not have a revolving credit facility, it also does not have ready access to incremental sources of capital to supplement its operational requirements. Contour believes that it has the ability for the foreseeable future based on its current condition, including economic conditions, to meet all obligations as they come due and fund its current capital expenditure program from cash on hand and operational cash flows. However, because of the combination of the factors described herein and the uncertainty of drilling successes required to sustain or increase operational cash flows, there can be no assurance that Contour will be able to fund future obligations.
Capital Resources. The partners' equity at December 31, 1999 increased to $887,000 as compared to $63,000 at December 31, 1998. 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, 1999, the Partnership was fully capitalized with contributions aggregating $50,082,285.
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 1997, 1998 and 1999. On December 31, 1996 the interest rate for the Initial Loan was reduced to 10 3/8% following the repayment of Contour's 13 1/2% Senior Notes, which were replaced by 10 3/8% Senior Subordinated Notes during the fourth quarter.
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. At December 31, 1999, $166,000 of the $6,000,000 Initial Loan remained outstanding. By continuing to service its debt from operating cash flow, the Partnership expects to further reduce the outstanding balance of the Initial Loan in 1999.
Year 2000. Contour, on behalf of the Partnership, conducted reviews and evaluations in response to Year 2000 issues. These issues involved the potential disruption to systems, processes, and business practices that may have occurred if system hardware and software utilized by Contour, its vendors, and customers are unable to process year 2000 data. Neither Contour nor the Partnership incurred any disruptions due to year 2000 issues.
The foregoing statements are intended to be and are hereby designated "Year 2000 Readiness Disclosures" within the meaning of the Year 2000 Information and Readiness Act.
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. In June 1998, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities" ("SFAS 133") which was amended in June 1999 by SFAS No. 137, "Accounting for Derivative Instruments and Hedging Activities - Deferral of the Effective Date of FASB Statement No. 133 - an amendment of FASB Statement No. 133." SFAS No. 133, as amended, is effective for fiscal years beginning after June 15, 2000, and establishes accounting and reporting standards for derivative instruments and hedging activities that require an entity to recognize all derivatives as an asset or liability measured at its fair value. Depending on the intended use of the derivative, changes in its fair value will be reported in the period of change as either a component of earnings or a component of other comprehensive income. Retroactive application to periods prior to adoption is not allowed. The Partnership has not quantified the impact of adoption on its financial statements.
ITEM 7A.
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
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
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, 1998 and 1999, 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, 1999. 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 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 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, 1998 and 1999, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1999, in conformity with generally accepted accounting principles.
DELOITTE & TOUCHE LLP
Houston, Texas March 23, 2000
KELLEY PARTNERS 1992 DEVELOPMENT DRILLING PROGRAM BALANCE SHEETS
(IN THOUSANDS)
See Notes to Financial Statements.
KELLEY PARTNERS 1992 DEVELOPMENT DRILLING PROGRAM STATEMENTS OF OPERATIONS
(IN THOUSANDS, EXCEPT PER UNIT DATA)
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 - INDUSTRY CONDITIONS AND LIQUIDITY
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. In 1999, KOGC's name was changed to Contour Energy Co. ("Contour")
The general partners own in the aggregate a 3.96% general partner interest in the Partnership. In addition, as of December 31, 1999, Kelley Oil owned 13,422,310 (83.72%) Units. 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.
In 1999, Contour undertook several strategic actions in response to the severe downturn in the industry in 1998 caused by low commodity prices and the closing of the capital markets to smaller oil and gas companies. These actions, described below, were designed to increase the near-term liquidity of Contour, Kelley Oil and the Partnership, provide capital for ongoing capital expenditure programs and establish a stronger base for future growth.
In April 1999, Contour entered into an Exploration and Development Agreement with Phillips Petroleum Company ("Phillips") relating to certain of its interests in the Bryceland, West Bryceland and Sailes fields in north Louisiana ("Phillips Transaction"). Pursuant to the agreement, Contour: (1) received an $83 million cash payment, (2) retained a 42 Bcf, 8-year volumetric overriding royalty interest and a 1% override on the excess production above such royalty interest and (3) retained 25% of its working interest in the Cotton Valley formation. In addition, Phillips, will at its risk and expense, operate, develop, exploit and explore the properties thereby relieving Contour of significant operating, exploration and development costs in the future. The transaction closed on May 17, 1999.
As part of the Phillips Transaction described above, the Partnership conveyed its interest in the West Bryceland and Sailes fields to Phillips for $2.1 million. The Partnership's reserve quantities attributable to such fields represented approximately one-half of the Partnership's total reserve quantities at January 1, 1999 and one-half of its total 1998 production. In the third quarter of 1999, the sales proceeds were applied to reduce the Partnership's loan to Kelley Oil.
In April 1999, Contour negotiated a private offering of $135 million principal amount, 14% Senior Secured Notes (the "Notes"). The Notes are secured by a first lien on substantially all of Contour's proved oil and natural gas properties remaining after the sale to Phillips and guaranteed by three entities wholly-owned by Contour. In accordance with the Notes indenture, on June 30, 1999, Contour funded $37.5 million to repurchase $35 million principal amount of the Notes at a repurchase price equal to 104% of the principal amount, plus accrued and unpaid interest and commitment fees to the date of the repurchase.
On May 17, 1999, Contour funded $28.5 million to repurchase $46.1 million of the outstanding principal amounts of its 7 7/8% Convertible Subordinated Notes due December 15, 1999 and its 8 1/2% Convertible Subordinated Debentures due April 1, 2000 (collectively, the "Securities") at a price equal to $590 per $1,000 principal amount (not including accrued interest paid of $1.2 million).
In addition, on May 17, 1999, Contour repaid all borrowings outstanding under its credit facility of $115.5 million plus accrued interest and terminated the revolving credit facility and funded cash collateral for a $1.5 million letter of credit which was subsequently increased to $7.5 million. Contour used net proceeds remaining from the transactions for general corporate purposes.
Contour has received the benefits of a general increase in the level of commodity prices over the past several months. This increase, combined with the actions described above, have provided Contour with near-term liquidity and capital for its ongoing operations. However, the commodity markets are volatile and there is no certainty that current oil and natural gas prices can be sustained at these levels. In addition, Contour continues to have significant debt outstanding relative to its asset base and pays a high portion of its cash flow to service such debt. Furthermore, as Contour does not have a revolving credit facility, it also does not have ready access to incremental sources of capital to supplement its operational requirements. Contour believes that it has the ability to meet all near-term obligations and fund its current capital expenditure program from cash on hand and operational cash flows. However, because of the combination of the factors described herein and the uncertainty of drilling successes required to sustain or increase operational cash flows, there can be no assurance that Contour will be able to fund future obligations.
NOTE 2 - 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. 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.
Property Impairment under FAS 121. Under 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" (SFAS 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, 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 as of year end. 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 thousand against the carrying value of its proved oil and gas properties under SFAS 121, at December 31, 1998.
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 6). As of December 31, 1999, the estimated fair value of the Partnership's debt approximated its carrying value. The estimated fair values at December 31, 1999 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. See Note 6 - "Hedging Activities" for a discussion of the Partnership's accounting policies related to hedging activities.
Comprehensive Income. In June 1997, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 130, "Reporting Comprehensive Income" ("SFAS 130"). SFAS 130 establishes standards for reporting and displaying comprehensive income and its components. SFAS 130 is effective for periods beginning after December 15, 1997. The purpose of reporting comprehensive income is to report a measure of all changes in equity of an enterprise that results from recognized transactions and other economic events of the period other than transactions with owners in their capacities as owners. As of December 31, 1999, there are no adjustments ("Other Comprehensive Income") to net income in deriving comprehensive income.
Concentration of Credit Risk and Significant Customers. Substantially all of the Partnership's receivables are due from the marketing subsidiary of 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.
Use of Estimates. The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Changes in Presentation. Certain financial statement items in 1997 and 1998 have been reclassified to conform to the 1999 presentation.
NOTE 3 - 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 1997, 1998 and 1999. On December 31, 1996, the interest rate for the Initial Loan was reduced to 10 3/8% following the repayment of Contour's 13 1/2% Senior Notes, which were replaced by 10 3/8% Senior Subordinated Notes during the fourth quarter.
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. The Partnership's operating cash flows in 1996 were applied to pay interest on the Initial Loan and to reduce unfunded payables for third party drilling overexpenditures. At December 31, 1999, $166,000 of the $6,000,000 Initial Loan remained
outstanding. By continuing to service its debt from operating cash flow, the Partnership expects to further reduce the outstanding balance of the Initial Loan in 2000.
NOTE 4 - CASH DISTRIBUTIONS
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 3 - Long-Term Debt.
NOTE 5 - 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, 1997, 1998 and 1999, these costs aggregated zero, zero and zero, respectively. The Partnership capitalized zero in 1997, 1998 and 1999, respectively, of allocated direct costs to oil and gas properties.
Overhead allocated to the Partnership by Kelley Oil for the years ended December 31, 1997, 1998 and 1999 related to general and administrative expenses aggregated $476,000, $134,000 and $92,000, respectively.
Substantially all gas sales of Contour 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. For 1997, 1998 and 1999, the fee was 2% of the resale price for marketed natural gas.
NOTE 6 - HEDGING ACTIVITIES
Contour has periodically used forward sales contracts, natural gas price swap agreements, natural gas basis swap agreements and options to reduce exposure to downward price fluctuations on its natural gas production. Contour does not engage in speculative transactions. Contour's hedging activities also cover the oil and gas production attributable to the Partnership, including the interest in such production of the public unitholders of the Partnership. During 1999, Contour used price and basis swap agreements. Price swap agreements generally provide for the Partnership to receive or make counterparty payments on the differential between a fixed price and a variable indexed price for natural gas. Basis swap agreements generally provide for the Partnership to receive or make counterparty payments on the differential between a variable indexed price and the price it receives from the sale of natural gas production, and are used to hedge against unfavorable price movements in the relationship between such variable indexed price and the price received for such production. Additionally, Contour must provide cash collateral for any hedges (through swap or other agreements) to cover counter-party risk to the hedging party. 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.
Through natural gas price swap agreements, the Partnership hedged approximately 65%, 49% and 50%, respectively, of its natural gas production for 1997, 1998 and 1999, respectively, at average NYMEX quoted prices of $2.35, $2.31 and $2.17 per Mmbtu, respectively, before transaction and transportation costs. As of December 31, 1999, approximately 8% of the Partnership's anticipated natural gas production for 2000 has been hedged by natural gas price swap agreements at an average NYMEX quoted price of $2.41 per Mmbtu before transaction and transportation costs. Per additional hedging activities since December 31, 1999, approximately 47% of the Partnership's anticipated natural gas production for 2000 has been hedged at an average NYMEX quoted price of $2.56 per Mmbtu before transaction and transportation. 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 either 1997 or 1998. As of December 31, 1999, approximately 7% of the Partnership's crude oil production for 2000 had been hedged by crude oil price swap agreements at an average NYMEX quoted price of $25.05 per
bbl before transaction and transportation costs. Per additional hedging activities since December 31, 1999, approximately 43% of the Partnership's anticipated crude oil production for 2000 has been hedged at an average NYMEX quoted price of $26.21 per bbl before transaction and transportation costs. Hedging activities decreased Partnership revenues by approximately $156,000 and $17,000 in 1997 and 1999, respectively, and increased such revenues by approximately $50,000 in 1998 as compared to estimated revenues had no hedging activities been conducted. At December 31, 1999, the unrealized gain/loss on the Partnership's existing hedging instruments for future production months in 2000 was not material.
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)
Costs Incurred. All costs were incurred in oil and gas property development activities (as defined in the Partnership Agreement) and aggregated $41,000, $52,000 and $14,000 in 1997, 1998 and 1999, 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, 1997, 1998 and 1999. See "Estimated Proved Reserves-Uncertainties in Estimated Reserves" under Items 1 and 2 of this Form 10K.
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.
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, 1997, 1998 and 1999 was calculated using prices in effect as of those dates, which averaged $17.01, $9.88 and $25.46, respectively, per barrel of oil and $2.49, $2.06 and $2.15, 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.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURES
None.
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 47 employees as of December 31, 1999, 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 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.
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, 1999 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, 1999 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.
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 5 of 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.
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:
(b) REPORTS ON FORM 8-K:
No reports on Form 8-K were filed by the Registrant during the fourth quarter of 1999.
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 3rd day of April 2000.
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 3rd day of April 2000 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
INDEX TO EXHIBITS