10-Q 1 h89710e10-q.txt KELLEY PARTNERS 1994 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 JUNE 30, 2001 COMMISSION FILE NO. 0-20998 KELLEY PARTNERS 1994 DEVELOPMENT DRILLING PROGRAM (EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER) TEXAS 76-0419001 (STATE OR OTHER JURISDICTION OF (I.R.S. EMPLOYER INCORPORATION OR ORGANIZATION) IDENTIFICATION NO.) 1001 MCKINNEY ST. SUITE 900 HOUSTON, TEXAS 77002 (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 1994 DEVELOPMENT DRILLING PROGRAM INDEX

1 3 PART I. FINANCIAL INFORMATION ITEM 1. FINANCIAL STATEMENTS KELLEY PARTNERS 1994 DEVELOPMENT DRILLING PROGRAM BALANCE SHEETS (IN THOUSANDS)

See Notes to Financial Statements. 2 4 KELLEY PARTNERS 1994 DEVELOPMENT DRILLING PROGRAM STATEMENTS OF INCOME (IN THOUSANDS, EXCEPT PER UNIT DATA) (UNAUDITED)

See Notes to Financial Statements. 3 5 KELLEY PARTNERS 1994 DEVELOPMENT DRILLING PROGRAM STATEMENTS OF CASH FLOWS (IN THOUSANDS) (UNAUDITED)

See Notes to Financial Statements. 4 6 KELLEY PARTNERS 1994 DEVELOPMENT DRILLING PROGRAM NOTES TO FINANCIAL STATEMENTS (UNAUDITED) NOTE 1 - BASIS OF PRESENTATION General. The accompanying unaudited interim financial statements of Kelley Partners 1994 Development Drilling Program (the "Partnership") have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission in accordance with accounting principles generally accepted in the United States of America for interim financial information. These financial statements reflect all adjustments (consisting solely of normal recurring adjustments) necessary for a fair presentation of the results for the interim periods presented. The results of operations for the three months and six months ended June 30, 2001 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 1 to the financial statements included in its Annual Report on Form 10-K for the year ended December 31, 2000. These unaudited interim financial statements should be read in conjunction with the audited financial statements and notes thereto included in the Partnership's 2000 Annual Report on Form 10-K. Derivative and Hedge Accounting. Historically, Contour Energy Co. has entered into hedge agreements on behalf of the Partnership to protect against commodity price declines, including production volumes for the second quarter and the first half of 2000. Beginning in 2001, due to small production volumes, the Partnership production will no longer be hedged. Through natural gas price swap agreements, approximately 56% and 52% of the Partnership's natural gas production for the second quarter of 2000 and the first half of 2000, respectively, was affected by hedging transactions at average NYMEX quoted prices of $2.60 per Mmbtu and $2.54 per Mmbtu, respectively, before transaction and transportation costs. Through crude oil price swap agreements, the Partnership hedged approximately 73% and 70% of its crude oil production for the three and six months ended June 30, 2000, respectively, at average NYMEX quoted prices of $27.65 per bbl and $26.38 per bbl, respectively, before transaction and transportation costs. No natural gas or crude oil was hedged in the three months and six months ended June 30, 2001. Hedging activities decreased Partnership revenues by $102,000 and $90,000 for the three months and six months ended June 30, 2000, as compared to estimated revenues had no hedging activities been conducted. The Partnership adopted Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities" ("SFAS 133") effective January 1, 2001. At of January 1, 2001, the Partnership was not party to any derivative instruments and as such there was no impact on its financial statements as a result of the adoption of SFAS 133. NOTE 2 - NEW ACCOUNTING PRONOUNCEMENTS In the fourth quarter of 2000, the Partnership adopted Emerging Issues Task Force Issue No. 00-10 ("EITF No. 00-10") accounting for Shipping and Handling Fees and Costs. EITF No. 00-10 addresses how shipping and handling fees should be classified in the income statement. As a result of EITF No. 00-10, the Partnership has reclassified its transportation and compression expenses from oil and gas revenues to lease operating expenses. As a result, $31,000 and $67,000 of expenses were reclassified from oil and gas revenues to lease operating expenses for the three months and six months ended June 30, 2000, respectively. In July 2001, the Financial Accounting Standards Board ("FASB") issued two new pronouncements: Statement of Financial Accounting Standards ("SFAS") No. 141, "Business Combinations", and SFAS No. 142, "Goodwill and Other Intangible Assets". SFAS 141 prohibits the use of the pooling-of-interest method for business combinations initiated after June 30, 2001 and also applies to all business combinations accounted for by the purchase method that are completed after June 30, 2001. SFAS 142, effective for fiscal years beginning after December 15, 2001, addresses financial accounting and reporting for acquired goodwill and other intangible assets and supersedes APB Opinion No. 17, Intangible Assets. It addresses how intangible assets that are acquired individually or with a group of other assets (but not those acquired in a business combination) should be accounted for in financial statements upon their acquisition. 5 7 This Statement also addresses how goodwill and other intangible assets should be accounted for after they have been initially recognized in the financial statements. The Partnership expects no impact on its financial statements from the adoption of these standards. 6 8 ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS GENERAL In 1994, Kelley Partners 1994 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. At June 30, 2001, Kelley Oil Corporation, managing general partner of the Partnership ("Kelley Oil") and a wholly owned subsidiary of Contour Energy Co. ("Contour") owns 95.61% of the Units and a 3.94% managing general partnership interest. RECENT DEVELOPMENTS Drilling Operations. Since inception, the Partnership participated in drilling 92 gross (29.31 net) wells, of which 88 gross (26.64 net) wells were found productive and 4 gross (2.67 net) wells were dry. Hedging and Derivative Activities. Historically, Contour has entered into hedge agreements on behalf of the Partnership to protect against commodity price declines, including production volumes for the second quarter and the first half of 2000. Beginning 2001, due to small production volumes, the Partnership production will no longer be hedged. Through natural gas price swap agreements, approximately 56% and 52% of the Partnership's natural gas production for the second quarter of 2000 and the first half of 2000, respectively, was affected by hedging transactions at average NYMEX quoted prices of $2.60 per Mmbtu and $2.54 per Mmbtu, respectively, before transaction and transportation costs. Through crude oil price swap agreements, the Partnership hedged approximately 73% and 70% of its crude oil production for the three and six months ended June 30, 2000, respectively, at average NYMEX quoted prices of $27.65 per bbl and $26.38 per bbl, respectively, before transaction and transportation costs. No natural gas or crude oil was hedged in the three months and six months ended June 30, 2001. Hedging activities decreased Partnership revenues by $102,000 and $90,000 for the three months and six months ended June 30, 2000, as compared to estimated revenues had no hedging activities been conducted. RESULTS OF OPERATIONS Three Months Ended June 30, 2001 and 2000. Oil and gas revenues of $538,000 for the second quarter of 2001 decreased 15% compared to $633,000 in the corresponding quarter of 2000 primarily as a result of lower natural gas and crude oil production, partially offset by higher natural gas prices. Production of natural gas decreased 46% from 206,681 Mcf in the second quarter of 2000 to 112,545 Mcf in the current quarter primarily due to normal production declines in the Partnership's producing areas. The average price of natural gas increased 54% from $3.05 per Mcf in the second quarter of 2000 to $4.71 per Mcf in the current quarter. Production of crude oil in the current quarter totaled 606 barrels, with an average sales price of $28.30 per barrel compared to 808 barrels at $25.26 per barrel in the same quarter last year, representing a volume decrease of 25% and a price increase of 12%. Production expenses and severance taxes were $95,000 in the current quarter versus $174,000 in the second quarter of 2000, a decrease of 45%. The decrease was due primarily to lower second quarter 2001 lifting costs, severance taxes and transportation and compression expenses due in part to the decline in production volumes. On a unit of production basis, these expenses decreased to $0.81 per Mcfe in the second quarter of 2001 from $0.83 per Mcfe in the same quarter of 2000. General and administrative ("G&A") expenses decreased 45% to $35,000 in the current quarter from $64,000 in the second quarter of 2000. Lower second quarter 2001 Partnership production activity caused the decline in G&A expenses charged by Kelley Oil to the Partnership. On a unit of production basis, these expenses were $0.30 per Mcfe for the second quarters of both 2000 and 2001. 7 9 Depreciation, depletion and amortization ("DD&A") expenses decreased 57% to $70,000 in the second quarter of 2001 from $164,000 in the second quarter of 2000 primarily the result of lower natural gas and crude oil production. On a unit of production basis, DD&A expense was $0.60 per Mcfe in the second quarter of 2001 compared to $0.78 per Mcfe in the same quarter last year, a decrease of 23%. The second quarter of 2001 includes an expense of $442,000 for the impairment of oil & gas properties resulting from unsuccessful development activities in south Louisiana. The Partnership recognized a net loss of $(104,000) or $0.00 per Unit for the second quarter of 2001. For the second quarter of 2000, the Partnership recognized net income of $231,000 or $0.01 per Unit. The reasons for the variance between the second quarter of 2001 and the second quarter of 2000 are described in the foregoing discussion. Six Months Ended June 30, 2001 and 2000. Oil and gas revenues increased 26% to $1,691,000 for the first six months of 2001 compared to $1,340,000 in the corresponding period of 2000 as a result of higher natural gas prices and crude oil production partially offset by lower natural gas production. Production of natural gas decreased 42% from 463,925 Mcf in the first six months of 2000 to 267,019 Mcf in the current period primarily due to normal production declines in the Partnership's producing areas. The average price of natural gas was $6.25 per Mcf in the first half of 2001 compared to $2.84 per Mcf in the prior year, an increase of 120%. Production of crude oil in the current period totaled 2,401 barrels, with an average sales price of $23.87 per barrel compared to 2,205 barrels at $26.75 per barrel in the same period last year, representing a volume increase of 9% and a price decrease of 11%. Production expenses and severance taxes were $205,000 in the current period versus $295,000 in the first half of 2000, a decrease of 31%. The decrease was due primarily to lower lifting costs, severance taxes and transportation and compression expenses due in part to the decline in production volumes. On a unit of production basis, these expenses increased to $0.73 per Mcfe in the first six months of 2001 from $0.62 per Mcfe in the year-earlier period. G&A expenses of $79,000 in the current period decreased 52% from $164,000 in the first half of 2000. Lower current period Partnership production activity caused the decline in G&A expenses charged by Kelley Oil to the Partnership. On a unit of production basis, these expenses decreased from $0.34 per Mcfe in the first six months of 2000 to $0.28 per Mcfe in the current period. DD&A expenses decreased 45% from $368,000 in the first six months of 2000 to $202,000 in the current period primarily the result of lower natural gas production. On a unit of production basis, DD&A expense decreased to $0.72 per Mcfe in the first half of 2001 from $0.77 per Mcfe in the same period last year. The first half of 2001 includes an expense of $442,000 for the impairment of oil & gas properties resulting from unsuccessful development activities in south Louisiana. The Partnership recognized net income of $763,000 or $0.04 per Unit for the first half of 2001. For the first half of 2000, the Partnership recognized net income of $513,000 or $0.02 per Unit. The reasons for the variance between the first six months of 2001 and the first six months of 2000 are described in the foregoing discussion. The results of operations for the quarter and six months ended June 30, 2001 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 six months of 2001, as reflected on its statement of cash flows, totaled $392,000. During the period, funds used in investing activities were comprised of capital expenditures of $29,000, and funds used in financing activities were for distributions to partners 8 10 of $363,000. As a result of these activities, the Partnership's cash and cash equivalents remained unchanged from December 31, 2000. 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 that is not required for the conduct of Partnership business to unitholders on a quarterly basis. In May 2001, the first quarter 2001 earnings distribution was paid to the managing and special general partners and unitholders in the amounts of $14,000 and $349,000, or $0.02 per Unit, respectively. However, future distributions are 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. Accounting Pronouncements. In the fourth quarter of 2000, the Partnership adopted Emerging Issues Task Force Issue No. 00-10 ("EITF No. 00-10") accounting for Shipping and Handling Fees and Costs. EITF No. 00-10 addresses how shipping and handling fees should be classified in the income statement. As a result of EITF No. 00-10, the Partnership has reclassified its transportation and compression expenses from oil and gas revenues to lease operating expenses. As a result, $31,000 and $67,000 of expenses were reclassified from oil and gas revenues to lease operating expenses for the three months and six months ended June 30, 2000, respectively. In July 2001, the Financial Accounting Standards Board ("FASB") issued two new pronouncements: Statement of Financial Accounting Standards ("SFAS") No. 141, "Business Combinations", and SFAS No. 142, "Goodwill and Other Intangible Assets". SFAS 141 prohibits the use of the pooling-of-interest method for business combinations initiated after June 30, 2001 and also applies to all business combinations accounted for by the purchase method that are completed after June 30, 2001. SFAS 142, effective for fiscal years beginning after December 15, 2001, addresses financial accounting and reporting for acquired goodwill and other intangible assets and supersedes APB Opinion No. 17, Intangible Assets. It addresses how intangible assets that are acquired individually or with a group of other assets (but not those acquired in a business combination) should be accounted for in financial statements upon their acquisition. This Statement also addresses how goodwill and other intangible assets should be accounted for after they have been initially recognized in the financial statements. The Partnership expects no impact on its financial statements from the adoption of these standards. 9 11 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 page 9 of the Partnership's Annual Report on Form 10-K for the fiscal year ended December 31, 2000. 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. PART II. OTHER INFORMATION ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K (a) Exhibits: EXHIBIT NUMBER: EXHIBIT ------- ------- None (b) Reports on Form 8-K: No reports on Form 8-K were filed by the Registrant during the second quarter of 2001. 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 1994 DEVELOPMENT DRILLING PROGRAM By: KELLEY OIL CORPORATION Managing General Partner Date: August 13, 2001 By: /s/ Rick G. Lester ------------------------------- Rick G. Lester Chief Financial Officer (Duly Authorized Officer) (Principal Accounting Officer) 11

KELLEY PARTNERS 1994 DEVELOPMENT DRILLING PROGRAM 10-Q