10-Q 1 h81783e10-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 SEPTEMBER 30, 2000 COMMISSION FILE NO. 0-23784 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.) 601 JEFFERSON ST. SUITE 1100 HOUSTON, TEXAS 77002 (ADDRESS OF PRINCIPAL EXECUTIVE OFFICES) (ZIP CODE) REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE: (713) 652-5200 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

PART I. FINANCIAL INFORMATION PAGE ---- Item 1I. Financial Statements: Balance Sheets as of December 31, 1999 and ~~June~~September 30, 2000 (unaudited) .........................~~.....~~ 2 Statements of Income for the three months and ~~six~~nine months ended ~~June~~September 30, 1999 and 2000 (unaudited).........................................................~~.....~~ 3 Statements of Cash Flows for the ~~six~~nine months ended ~~June~~September 30, 1999 and 2000 (unaudited).........~~......~~ 4 Notes to Financial Statements (unaudited).......................................................... 5 Item 2II. Management"'s Discussion and Analysis of Financial Condition and Results of Operations...... 6 Item 3III. Quantitative and Qualitative Disclosure About Market Risk.................................. 89 PART II. OTHER INFORMATION.............................................................................. ~~9 Item 6. Exhibits and Reports on Form 8-K........................................................... 9~~10

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

DECEMBER 31, ~~JUNE~~SEPT. 30, 1999 2000 ------------- --------- (UNAUDITED) ASSETS: Cash and cash equivalents ...................................~~..........................~~ $ -- $ -- Accounts receivable - trade .................................~~.........................~~ 16 122 Accounts receivable - affiliates ............................~~.........................~~ 905 ~~922~~979 --------- -------- Total current assets ........................................~~.........................~~ 921 ~~934~~981 --------- -------- Oil and gas properties, successful efforts method: Properties subject to amortization ........................~~.........................~~ 32,619 32,~~564~~540 Less: Accumulated depreciation, depletion and amortization ........................................... (27,132) (27,~~499~~667) --------- -------- Total oil and gas properties ................................~~.........................~~ 5,487 54,~~065~~873 --------- -------- Total assets ...................................................~~..........................~~ $ 6,408 $ 5,~~999~~854 ========= ======== LIABILITIES: Accounts payable and accrued expenses .......................~~..........................~~ $ 121 $ 6778 --------- -------- Total current liabilities ...................................~~.........................~~ 121 6778 --------- -------- Total liabilities ..............................................~~.........................~~ 121 6778 --------- -------- PARTNERS' EQUITY: LP Unitholders' equity ......................................~~.........................~~ 346 327 GP Unitholders' equity ......................................~~.........................~~ 5,693 5,~~371~~221 Managing and Special General Partners' equity ...............~~.........................~~ 248 ~~234~~228 --------- -------- Total partners' equity .........................................~~.........................~~ 6,287 5,~~932~~776 --------- -------- Total liabilities and partners' equity .........................~~.........................~~ $ 6,408 $ 5,~~999~~854 ========= ========

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

THREE MONTHS ~~SIX MONTHS~~ ENDED ~~JUNE~~SEPT. 30, NINE MONTHS ENDED ~~JUNE~~SEPT. 30, ---------------------------- --------------------------- 1999 2000 1999 2000 ------- ------- ------- ------- REVENUES: Oil and gas sales .........................~~.................~~ $ ~~874~~727 $ ~~602~~630 $ 2,~~101~~828 $ 1,~~273~~903 Gain on sale of properties ................~~.................~~ ~~2,012~~-- -- 2,012 -- ------- ------- ------- ------- Total revenues ............................~~.................~~ ~~2,886~~727 ~~602~~630 4,~~113~~840 1,~~273~~903 ------- ------- ------- ------- EXPENSES: Lease operating expenses ..................~~.................~~ ~~160~~110 ~~128~~93 ~~333~~443 ~~191~~284 Severance taxes ...........................~~.................~~ 4558 1521 ~~108~~166 3758 Exploration expenses ......................~~.................~~ -- -- -- -- General and administrative expenses .......~~.................~~ ~~120~~129 6471 ~~211~~340 ~~164~~235 Depreciation, depletion and amortization ..~~.................~~ ~~252~~289 ~~164~~167 ~~625~~914 ~~368~~535 ------- ------- ------- ------- Total expenses ............................~~.................~~ ~~577~~586 ~~371~~352 1,~~277~~863 ~~760~~1,112 ------- ------- ------- ------- Net income ...................................~~.................~~ $ ~~2,309~~141 $ ~~231~~278 $ 2,~~836~~977 $ ~~513~~791 ======= ======= ======= ======= Net income allocable to LP and GP unitholders~~.................~~ $ ~~2,218~~135 $ ~~222~~267 $ 2,~~724~~859 $ ~~493~~760 ======= ======= ======= ======= Net income allocable to Managing and Special General Partners ..................~~.................~~ $ 916 $ 911 $ ~~112~~118 $ 2031 ======= ======= ======= ======= Net income per LP and GP unit ................~~.................~~ $ .1101 $ .01 $ .1314 $ .0204 ======= ======= ======= ======= Average LP and GP units outstanding ..........~~.................~~ 20,864 20,864 20,864 20,864 ======= ======= ======= =======

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

~~SIX~~NINE MONTHS ENDED ~~JUNE~~SEPT. 30, --------------------------- 1999 2000 -------- -------- OPERATING ACTIVITIES: Net income ...................................................~~........................~~ $ 2,~~836~~977 $ ~~513~~791 Adjustments to reconcile net income to net cash provided by operating activities: Gain on sale of properties ................................. (2,012) -- Depreciation, depletion and amortization ...................~~.....~~ ~~(2,012)~~914 --535 ~~Depreciation,~~Exploration ~~depletion~~expenses ~~and amortization~~.......................................~~....~~ ~~625~~-- ~~368~~-- Changes in operating assets and liabilities: Decrease (increase) in accounts receivable .................~~........................~~ 12,~~695~~180 (1360) ~~Decrease~~Increase (decrease) in accounts payable and accrued expenses ................................................. ~~(32)~~3 (5443) -------- -------- Net cash provided by operating activities ....................~~........................~~ 34,~~112~~062 ~~814~~1,223 -------- -------- INVESTING ACTIVITIES: Capital expenditures ......................................... (169) 79 Proceeds from sale of properties ............................. ~~(70)~~8,326 54-- -------- -------- Net cash ~~(used in)~~ provided by investing activities ....................~~..............~~ ~~(70)~~8,157 5479 -------- -------- FINANCING ACTIVITIES: ~~Capital contributed by partners...................................................... -- --~~ Distributions to partners ....................................~~........................~~ (312,~~042~~219) (~~868~~1,302) -------- -------- Net cash used in financing activities ........................~~........................~~ (312,~~042~~219) (~~868~~1,302) -------- -------- Decrease in cash and cash equivalents ...........................~~........................~~ -- -- Cash and cash equivalents, beginning of period ..................~~........................~~ -- -- -------- -------- Cash and cash equivalents, end of period ........................~~........................~~ $ -- $ -- ======== ========

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 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. Changes in Presentation. Certain 1999 financial statement items have been reclassified to conform to the 2000 presentation. 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 $190,000 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 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. Kelley Oil Corporation, managing general partner of the Partnership ("Kelley Oil") and a wholly owned subsidiary of Contour Energy Co. ("Contour"), owns 91.85% of the Units, together with its 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 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 50,000 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 150,000 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 1,400 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, 2 and 1 barrel(s) 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 $(136,000), $(223,000), $142,000 and $(313,000), 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 $300,000 and $120,000, 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 $630,000 for the third quarter of 2000 decreased 13% compared to $727,000 in the corresponding quarter of 1999 primarily as a result of lower gas production, partially offset by higher oil and natural gas prices. Production of natural gas decreased 47% from 387,000 Mcf in the third quarter of 1999 to 206,000 Mcf in the same period of 2000, primarily due to normal production decline. Lease operating expenses and severance taxes were $114,000 in the current quarter versus $168,000 in the third quarter of 1999. This 32% decrease was primarily from lower severance taxes due to lower production volumes. On a unit of production basis, these expenses increased from $0.42 per Mcfe in the third quarter of 1999 to $0.55 per Mcfe in the same quarter of 2000, primarily as a result of lower production levels in the third quarter 2000. General and administrative ("G&A") expenses of $71,000 in the current quarter decreased 45% from $129,000 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, G&A expenses increased from $0.32 per Mcfe in the third quarter of 1999 to $0.34 per Mcfe in the current quarter. Depreciation, depletion and amortization ("DD&A") expenses decreased 42% from $289,000 in the third quarter of 1999 to $167,000 in the current quarter, primarily as a result of decreased production levels. The units-of-production DD&A rate for oil & gas activities was $0.71 per Mcfe in the third quarter of 1999 compared to $0.80 per Mcfe in the third quarter of 2000. The Partnership recognized net income of $278,000, or $0.01 per Unit, for the third quarter of 2000 compared to third quarter 1999 net income of $141,000, or $0.01 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 $1,903,000 for the first nine months of 2000 decreased 33% compared to $2,828,000 in the corresponding period of 1999 primarily as a result of lower natural gas production, partially offset by higher prices. Production of natural gas decreased 54% from 1,500,000 Mcf in the first nine months of 1999 to 685,000 Mcf in the current period primarily due to the May 1999 sale of properties to Phillips Petroleum Company ("Phillips"). Natural gas prices increased 49% to $2.82 per Mcf in the current period from $1.89 per Mcf in the first nine months of 1999. In the second quarter of 1999, the Partnership conveyed its interest in the West Bryceland and Sailes fields to Phillips. This transaction resulted in a second quarter 1999 gain on sale of properties of $2,012,000. 7 9 Lease operating expenses and severance taxes were $342,000 in the first nine months of 2000 versus $609,000 in the first nine months of 1999. This 44% decrease was primarily due to the sale of properties to Phillips in the first half of 1999. On a unit of production basis, these expenses increased to $0.50 per Mcfe in the current period from $0.39 per Mcfe in the same period of 1999, primarily as a result of lower production levels in the first nine months of 2000. G&A expenses of $235,000 in the current period decreased 31% from $340,000 in the first nine months of 1999, reflecting the Partnership's share of administration costs associated with operations of Contour. On a unit of production basis, these expenses increased from $0.22 per Mcfe in the first nine months of 1999 to $0.34 per Mcfe in the current period. DD&A expense decreased 41% from $914,000 in the first nine months of 1999 to $535,000 in the current period, primarily as a result of decreased current period production related to the sale of properties in the first half of 1999 to Phillips. The units-of-production DD&A rate for oil & gas activities was $0.59 per Mcfe in the first nine months of 1999 compared to $0.78 per Mcfe in the same period in of 2000. The Partnership recognized net income of $791,000, or $.04 per Unit, for the first nine months of 2000 compared to net income of $2,977,000, or $0.14 per Unit, for the first nine months of 1999. 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 $1,223,000. During the period, funds provided by investing activities were comprised of net reductions to capital expenditures of $79,000. For the first nine months of 2000, funds used in financing activities consisted of cash distributions to partners of $1,302,000. As a result of these activities, the Partnership's cash and cash equivalents remained unchanged from December 31, 1999. Capital Resources. The capitalization of the Partnership was completed in 1997. Cash flows from operations are expected to be adequate to meet the Partnership's capital expenditures and 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. In March, May and August 2000, the Partnership made quarterly distributions of $0.02 per Unit (aggregating $1,302,000), compared to distributions of $0.05, $0.09 and $0.42 (including $0.38 per unit related to the proceeds from the sale of properties to Phillips) per Unit in March, May and August 1999, respectively (aggregating $12,219,000). The Partnership intends to continue making quarterly distributions consistent with its cash distribution policy. 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. 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. 8 10 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 $190,000 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 1994 DEVELOPMENT DRILLING PROGRAM By: KELLY 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) 13 INDEX TO EXHIBITS

EXHIBIT NUMBER DESCRIPTION ------- ----------- 27 Financial Data Schedule (included only in the electronic filing of this document).

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