10-Q 1 h81779e10-q.txt KELLEY PARTNERS 1992 DEVELOPMENT DRILLING PROGRAM 1 ================================================================================ UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-Q Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 For the Quarter Ended September 30, 2000 Commission File No. 0-20998 KELLEY PARTNERS 1992 DEVELOPMENT DRILLING PROGRAM (Exact name of registrant as specified in its charter) TEXAS 76-0373428 (STATE OR OTHER JURISDICTION OF (I.R.S. EMPLOYER INCORPORATION OR ORGANIZATION) IDENTIFICATION NO.) 601 JEFFERSON ST. 77002 SUITE 1100 HOUSTON, TEXAS (ADDRESS OF PRINCIPAL EXECUTIVE OFFICES) (ZIP CODE) REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE: (713) 652-5200 Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X No ================================================================================ 2 KELLEY PARTNERS 1992 DEVELOPMENT DRILLING PROGRAM INDEX

1 3 PART I. FINANCIAL INFORMATION ITEM 1. FINANCIAL STATEMENTS KELLEY PARTNERS 1992 DEVELOPMENT DRILLING PROGRAM BALANCE SHEETS (In thousands)

See Notes to Financial Statements. 2 4 KELLEY PARTNERS 1992 DEVELOPMENT DRILLING PROGRAM STATEMENTS OF INCOME (LOSS) (In thousands, except per unit data) (Unaudited)

See Notes to Financial Statements. 3 5 KELLEY PARTNERS 1992 DEVELOPMENT DRILLING PROGRAM STATEMENTS OF CASH FLOWS (In thousands) (Unaudited)

See Notes to Financial Statements. 4 6 KELLEY PARTNERS 1992 DEVELOPMENT DRILLING PROGRAM NOTES TO FINANCIAL STATEMENTS (UNAUDITED) NOTE 1 - BASIS OF PRESENTATION General. The accompanying unaudited interim financial statements of Kelley Partners 1992 Development Drilling Program (the "Partnership") have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission in accordance with generally accepted accounting principles for interim financial information. These financial statements reflect all adjustments (consisting solely of normal recurring adjustments) necessary for a fair statement in all material respects of the results for the interim periods presented. The results of operations for the three and nine months ended September 30, 2000 are not necessarily indicative of results to be expected for the full year. The accounting policies followed by the Partnership are set forth in Note 2 to the financial statements included in its Annual Report on Form 10-K for the year ended December 31, 1999. These unaudited interim financial statements should be read in conjunction with the audited financial statements and notes thereto included in the Partnership's 1999 Annual Report on Form 10-K. NOTE 2 - NEW ACCOUNTING PRONOUNCEMENTS The Partnership plans to adopt Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities" ("SFAS 133") effective January 1, 2001. The statement, as amended, requires that all derivatives be recognized as either assets or liabilities and measured at fair value, and changes in the fair value of derivatives be reported in current earnings, unless the derivative is designated and effective as a hedge. If the intended use of the derivative is to hedge the exposure to changes in the fair value of an asset, a liability or firm commitment, then the changes in the fair value of the derivative instrument will generally be offset in the income statement by the change in the item's fair value. However, if the intended use of the derivative is to hedge the exposure to variability in expected future cash flows then the changes in fair value of the derivative instrument will generally be reported in Other Comprehensive Income (OCI). The gains and losses on the derivative instrument that are reported in OCI will be reclassified to earnings in the period in which earnings are impacted by the hedged item. Contour Energy Co. ("Contour") periodically uses forward sales contracts, swap agreements, natural gas basis swap agreements, collars and options to reduce exposure to downward price fluctuations on its natural gas and crude oil production. Contour's hedging activities also cover the production attributable to the interest of the public unitholders in this partnership. Contour has received a mark-to-market valuation report from its counterparty dated November 7, 2000. Based on this report, when SFAS 133 is adopted on January 1, 2001, a liability of approximately $7,000 would be recorded by the partnership to reflect the fair market value of hedges currently in place for the periods subsequent to January 1, 2001. Because the derivatives currently in place qualify for hedge accounting, an offsetting entry would be made to OCI. Due to commodity price volatility, the fair value of Contour's derivative instruments has changed dramatically since September 30, 2000 (See "Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations - Hedging Activities"). Volatility in the commodity price markets prevents management of the partnership from determining the actual transitional valuation effect on future results of operations or financial position once SFAS 133 is implemented on January 1, 2001. 5 7 ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS General In 1992, Kelley Partners 1992 Development Drilling Program (the "Partnership") issued units of limited and general partner interests ("Units"). The Units represent 96.04% of the total interests in the Partnership. In addition, the Partnership issued managing and special general partner interests 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. ("Contour"), owns 83.72% of the Units, together with its 3.94% managing general partnership interest. Recent Developments 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 periodically uses forward sales contracts, natural gas and crude oil price swap agreements, collars and options to reduce exposure to downward price fluctuations on its natural gas and crude oil production. Contour's hedging activities also cover the oil and gas production attributable to the interest of the public unitholders in its subsidiary partnerships. Contour does not engage in speculative transactions. During 2000, Contour has used price swap agreements and collars. Price swap agreements generally provide for Contour to receive or make counterparty payments on the differential between a fixed price and a variable indexed price for natural gas and crude oil. Collars combine put and call options to establish a ceiling and a floor. Contour normally employs the average NYMEX price for the last three days of the contract for natural gas and the monthly average of closing NYMEX prices for crude oil as the underlying index ("Index Price"). To the extent the Index Price closes above the established ceiling Contour must make payments to the counterparty on the differential between the Index Price and the ceiling. Conversely, if the Index price closes below the established floor, the counterparty must make payments to Contour on the differential between the Index Price and the floor. If the Index Price closes between the ceiling and the floor, no settlement is due. Gains and losses realized by the Partnership from hedging activities are included in oil and gas revenues and average sales prices in the period that the related production is sold. However, see Note 2 - New Accounting Pronouncements Through natural gas price swap agreements and collars, approximately 54%, 94%, 44% and 65% of the Partnership's natural gas production was hedged for the third quarter of 1999, the third quarter of 2000, the first nine months of 1999 and the first nine months of 2000, respectively. As of September 30, 2000, approximately 10,000 Mmbtus of the Partnership's natural gas production for October 2000 has been hedged by natural gas price swap agreements at an average Index Price of $2.60 per Mmbtu before transaction and transportation costs. As of September 30, 2000, approximately 30,000 Mmbtus of the Partnership's natural gas production for October through December 2000 has been hedged by collars at a floor of $4.00 per Mmbtu and a ceiling of $4.98 per Mmbtu. As of the date of this report, Contour has three collars in place for 15,000 Mmbtus per day each totaling 45,000 Mmbtus per day of expected natural gas production for the calendar year 2001. Approximately 400 Mmbtus per day of these volumes relate to the Partnership's production. The terms of the first collar include a ceiling of $5.00/Mmbtu and a floor of $3.55/Mmbtu at a closing Index Price above $3.00/Mmbtu. However, at prices below $3.00/Mmbtu, the floor moves to an Index Price plus $0.55 /Mmbtu. The terms of the second collar include a ceiling of $5.00/Mmbtu and a floor of $3.75/Mmbtu at a closing Index Price above $3.09/Mmbtu. However, at prices below $3.09/Mmbtu, the floor moves to an Index Price plus $0.66/Mmbtu. The terms of the third collar include a ceiling of $5.33/Mmbtu and a floor of $4.00/Mmbtu at the closing Index Price. Through crude oil price swap agreements and collars, approximately 46%, 48%, 17% and 62% of the Partnership's crude oil production was hedged for the third quarter of 1999, the third quarter of 2000, the first nine months of 1999 and the first nine months of 2000, respectively. As of September 30, 2000, Contour has two collars in place covering an average of 900 barrels per day of expected crude oil production for the remainder of 2000 and an average of 598 barrels per day of expected crude oil production for calendar year 2001. Approximately, 20 and 14 barrels per day of these volumes related to the Partnership's production for the remainder of 2000 and 2001, respectively. 6 8 The terms of the first collar include a ceiling of $32.00/bbl and a floor of $25.24/bbl at a closing Index Price above $22.00/bbl. However, at prices below $22.00/bbl, the floor moves to an Index Price plus $3.24 /bbl. The terms of the second collar include a ceiling of $32.48/bbl and a floor of $27.20/bbl at a closing Index Price above $23.00/bbl. However, at prices below $23.00/bbl, the floor moves to an Index Price plus $4.20/bbl. Included within oil and gas revenues for the three months and nine months ended September 30, 1999 and 2000 was approximately $(25,000), $(36,000), $40,000 and $(56,000), respectively, representing net (losses) and net gains from hedging activities. At September 30, 2000, the mark-to-market unrealized loss on Contour's existing hedging instruments for future production months approximated $6.7 million, of which $2.7 million related to October 2000. As to the aforementioned losses, approximately $10,000 and $4,000, respectively, related to the Partnership's production. Contour, under the terms of its existing hedge instruments, is required, from time to time, to provide collateral to the counterparty(s). The amount of collateral required is a function of the mark to market value of the hedge instruments at a point in time as determined by the counterparty(s). 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. Contour has not experienced counterparty nonperformance on these agreements and does not anticipate any in future periods. Results of Operations Three Months Ended September 30, 2000 and 1999. Oil and gas revenues of $200,000 for the third quarter of 2000 increased 46% compared to $137,000 in the corresponding quarter of 1999 primarily as a result of higher oil and gas prices, partially offset by lower gas production. Production of natural gas decreased 19% from 64,000 Mcf in the third quarter of 1999 to 52,000 Mcf in the current quarter primarily due to normal production decline. The average price of natural gas increased 76% from $1.88 per Mcf in the third quarter of 1999 to $3.31 per Mcf in the current quarter. Production of crude oil in the current quarter totaled 2,754 barrels, with an average sales price of $30.64 per barrel compared to 2,737 barrels at $19.10 per barrel in the same quarter last year. Lease operating expenses and severance taxes were $60,000 in the current quarter versus $64,000 in the third quarter of 1999, a decrease of 7%, primarily the result of lower natural gas production in the third quarter of 2000. On a unit of production basis, these expenses increased to $1.16 per Mcfe in the third quarter of 2000 from $1.01 per Mcfe in the same quarter of 1999, the result of a decline in production. General and administrative ("G&A") expenses of $21,000 in the current quarter decreased 19% from $26,000 in the third quarter of 1999, reflecting the Partnership's share of administration costs associated with operations of Contour. On a unit of production basis, these expenses were $0.41 per Mcfe in both the third quarters of 1999 and 2000. Depreciation, depletion and amortization ("DD&A") expenses decreased 31% from $39,000 in the third quarter of 1999 to $27,000 in the current quarter due to lower production levels in the third quarter of 2000 On a unit of production basis, DD&A expenses decreased to $0.52 per Mcfe in the third quarter of 2000 from $0.61 per Mcfe in the same quarter last year. The Partnership recognized net income of $92,000, or $0.01 per Unit, for the third quarter of 2000. For the third quarter of 1999, the Partnership recognized a net loss of $53,000, or $0.00 per Unit. The reasons for the variance between the third quarter of 2000 and the third quarter of 1999 are described in the foregoing discussion. Nine Months Ended September 30, 2000 and 1999. Oil and gas revenues of $569,000 for the first nine months of 2000 decreased 16% compared to $679,000 in the corresponding period of 1999 as a result of lower gas production, partially offset by higher gas and oil prices and higher oil production. Production of natural gas decreased 62% from 285,000 Mcf in the first nine months of 1999 to 109,000 Mcf in the current period primarily due to the sale of properties to Phillips Petroleum Company ("Phillips") in the second quarter of 1999. The average price of natural gas was $3.13 per Mcf in the first nine months of 2000 compared to $2.02 per Mcf in the prior year. Production of crude oil in the current period totaled 8,018 barrels, with an average sales price of $28.83 per barrel compared to 7,689 barrels at $15.63 per barrel in the same period last year, representing a volume increase of 4% and a price increase of 84%. In the second 7 9 quarter of 1999, the Partnership conveyed its interests in the West Bryceland and Sailes fields to Phillips. This transaction resulted in a second quarter 1999 gain on sale of properties of $855,000. Lease operating expenses and severance taxes were $190,000 in the current period versus $288,000 in the first nine months of 1999, a decrease of 34%. The decrease was due primarily to lower lifting costs and severance taxes in the first nine months of 2000 resulting from lower gas production related to the sale of properties to Phillips in the first half of 1999. On a unit of production basis, these expenses increased to $1.21 per Mcfe in the first nine months of 2000 from $0.87 per Mcfe in the year-earlier period, resulting from lower production volumes. G&A expenses of $54,000 in the current period decreased 33% from $80,000 in the first nine months of 1999. Lower current period Partnership production levels caused the decline in G&A expenses charged by Contour to the Partnership. On a unit of production basis, these expenses increased from $0.24 per Mcfe in the first nine months of 1999 to $0.34 per Mcfe in the current period. In the first nine months of 2000 and 1999, the Partnership incurred interest expenses of $6,000 and $187,000, respectively, on a loan advanced to it by Kelley Oil in August 1994 ("Initial Loan") to fund part of its drilling expenditures in excess of contributed capital. The reduction reflects the lower average note payable balance outstanding in the first nine months of 2000. See Liquidity and Capital Resources below. DD&A expenses decreased 53% from $198,000 in the first nine months of 1999 to $93,000 in the current period due to lower production levels primarily from the properties sold to Phillips. On a unit of production basis, DD&A expenses decreased to $0.59 per Mcfe in the first nine months of 2000 from $0.60 per Mcfe in the same period last year. The Partnership recognized net income of $226,000, or $0.01 per Unit, for the first nine months of 2000. For the first nine months of 1999, the Partnership recognized net income of $781,000, or $0.05 per Unit. The reasons for the variance between the first nine months of 2000 and the first nine months of 1999 are described in the foregoing discussion. The results of operations for the three and nine months ended September 30, 2000 are not necessarily indicative of the Partnership's operating results to be expected for the full year. Liquidity and Capital Resources Liquidity. Net cash provided by the Partnership's operating activities during the first nine months of 2000, as reflected on its statement of cash flows, totaled $104,000. During the period, funds provided by investing activities were comprised of net reductions to capital expenditures of $62,000, and funds used in financing activities included a reduction in the Initial Loan principal of $166,000. As a result of these activities, the Partnership's cash and cash equivalents remained unchanged from December 31, 1999. Capital Resources. 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. 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. The Partnership's operating cash flows have been applied to pay interest and principal on the Initial Loan. At September 30, 2000, the $6,000,000 Initial Loan from Kelly Oil has been paid in full. Future distributions to the unitholders is contingent on future operating results. 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. 8 10 Accounting Pronouncements. The Partnership plans to adopt Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities" ("SFAS 133") effective January 1, 2001. The statement, as amended, requires that all derivatives be recognized as either assets or liabilities and measured at fair value, and changes in the fair value of derivatives be reported in current earnings, unless the derivative is designated and effective as a hedge. If the intended use of the derivative is to hedge the exposure to changes in the fair value of an asset, a liability or firm commitment, then the changes in the fair value of the derivative instrument will generally be offset in the income statement by the change in the item's fair value. However, if the intended use of the derivative is to hedge the exposure to variability in expected future cash flows then the changes in fair value of the derivative instrument will generally be reported in Other Comprehensive Income (OCI). The gains and losses on the derivative instrument that are reported in OCI will be reclassified to earnings in the period in which earnings are impacted by the hedged item. Contour periodically uses forward sales contracts, swap agreements, natural gas basis swap agreements, collars and options to reduce exposure to downward price fluctuations on its natural gas and crude oil production. Contour's hedging activities also cover the production attributable to the interest of the public unitholders in this partnership. Contour has received a mark-to-market valuation report from its counterparty dated November 7, 2000. Based on this report, when SFAS 133 is adopted on January 1, 2001, a liability of approximately $7,000 would be recorded by the partnership to reflect the fair market value of hedges currently in place for the periods subsequent to January 1, 2001. Because the derivatives currently in place qualify for hedge accounting, an offsetting entry would be made to OCI. Due to commodity price volatility, the fair value of Contour's derivative instruments has changed dramatically since September 30, 2000 (See "Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations - Hedging Activities"). Volatility in the commodity price markets prevents management of the partnership from determining the actual transitional valuation effect on future results of operations or financial position once SFAS 133 is implemented on January 1, 2001. ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK See discussion in Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations - Hedging Activities. Forward-looking Statements Statements contained in this Report and other materials filed or to be filed by the Partnership with the Securities and Exchange Commission (as well as information included in oral or other written statements made or to be made by the Partnership or its representatives) that are forward-looking in nature are intended to be "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended, relating to matters such as anticipated operating and financial performance, business prospects, developments and results of the Partnership. Actual performance, prospects, developments and results may differ materially from any or all anticipated results due to economic conditions and other risks, uncertainties and circumstances partly or totally outside the control of the Partnership, including rates of inflation, natural gas prices, uncertainty of reserve estimates, rates and timing of future production of oil and gas, exploratory and development activities, acquisition risks, changes in the level and timing of future costs and expenses related to drilling and operating activities and those risk factors described on pages 9 and 10 of the Partnership's Annual Report on Form 10-K for the fiscal year ended December 31, 1999. Words such as "anticipated". "expect", "estimate", "project" and similar expressions are intended to identify forward-looking statements. Forward-looking statements include the risk factors described in the Partnership's Form 10-K mentioned above. 9 11 PART II. OTHER INFORMATION ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K (a) Exhibits: Exhibit Number: Exhibit ------- ------- 27 Financial Data Schedule (included only in the electronic filing of this document). (b) Reports on Form 8-K: No reports on Form 8-K were filed by the Registrant during the third quarter of 2000. 10 12 SIGNATURES Pursuant to the requirements 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. KELLEY PARTNERS 1992 DEVELOPMENT DRILLING PROGRAM By: KELLEY OIL CORPORATION Managing General Partner Date: November 14, 2000 By: /s/Rick G. Lester ---------------------------------------- Rick G. Lester Chief Financial Officer (Duly Authorized Officer) (Principal Accounting Officer) 11 13 EXHIBIT INDEX Exhibit Number: Exhibit ------- ------- 27 Financial Data Schedule (included only in the electronic filing of this document).

KELLEY PARTNERS 1992 DEVELOPMENT DRILLING PROGRAM 10-Q