DECEMBERTable 31,of SEPTEMBER 30, 2000 2001 ------------ ------------- (UNAUDITED) ASSETS: Cash and cash equivalents........................................ $ -- $ -- Accounts receivable - trade...................................... 9 2 Accounts receivable - affiliates................................. 363 673 --------- --------- Total current assets............................................. 372 675 --------- --------- Oil and gas properties, successful efforts method: Properties subject to amortization............................. 32,849 32,871 Less: Accumulated depreciation, depletion and amortization.... (27,825) (28,572) --------- --------- Total oil and gas properties..................................... 5,024 4,299 --------- --------- Total assets........................................................ $ 5,396 $ 4,974 ========= ========= LIABILITIES: Accounts payable and accrued expenses............................ $ 370 $ 68 --------- --------- Total current liabilities........................................... 370 68 --------- --------- Total liabilities................................................... 370 68 --------- --------- PARTNERS' EQUITY: LP Unitholders' equity .......................................... 284 276 GP Unitholders' equity........................................... 4,544 4,437 Managing and special general partners' equity.................... 198 193 --------- --------- Total partners' equity.............................................. 5,026 4,906 --------- --------- Total liabilities and partners'equity............................... $ 5,396 $ 4,974 ========= =========Contents

~~THREE~~UNITED ~~MONTHS~~STATES ENDED NINE MONTHS ENDED SEPT. 30, SEPT. 30, -------------------- -------------------- 2000 2001 2000 2001 ------- ------- ------- ------- REVENUES: Oil and gas sales ........................... $ 533 $ 429 $ 1,873 $ 2,120 ------- ------- ------- ------- Total revenues ........................... 533 429 1,873 2,120 ------- ------- ------- ------- EXPENSES: Production expenses ...................... 104 75 362 250 Severance taxes .......................... 16 26 53 56 General and administrative expenses ...... 56 23 220 102 Depreciation, depletion and amortization .... 147 103 515 305 Impairment of oil & gas properties ....... -- -- -- 442 ------- ------- ------- ------- Total expenses ........................... 323 227 1,150 1,155 ------- ------- ------- ------- Net income .................................. $ 210 $ 202 $ 723 $ 965 ======= ======= ======= ======= Net income allocable to LP and GP unitholders $ 201 $ 194 $ 694 $ 927 ======= ======= ======= ======= Net income allocable to managing and special general partners ................. $ 9 $ 8 $ 29 $ 38 ======= ======= ======= ======= Net income per LP and GP unit ............... $ .01 $ .01 $ .03 $ .04 ======= ======= ======= ======= Average LP and GP units outstanding ......... 20,864 20,864 20,864 20,864 ======= ======= ======= =======

~~NINE~~SECURITIES ~~MONTHS~~AND ~~ENDED~~EXCHANGE ~~SEPT.~~COMMISSION 30, --------------------- 2000 2001 ------- ------- OPERATING ACTIVITIES: Net income ................................................... $ 723 $ 965 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation, depletion and amortization ................... 515 305 Impairment of oil & gas properties ......................... -- 442 Changes in operating assets and liabilities: Decrease (increase) in accounts receivable ................. 47 (303) Decrease in accounts payable and accrued expenses .......... (62) (302) ------- ------- Net cash provided by operating activities .................... 1,223 1,107 ------- ------- INVESTING ACTIVITIES: Capital expenditures ......................................... 79 (22) ------- ------- Net cash provided by (used in) investing activities .......... 79 (22) ------- ------- FINANCING ACTIVITIES: Distributions to partners .................................... (1,302) (1,085) ------- ------- Net cash used in financing activities ........................ (1,302) (1,085) ------- ------- Increase (decrease) in cash and cash equivalents ................ -- -- Cash and cash equivalents, beginning of period .................. -- -- ------- ------- Cash and cash equivalents, end of period ........................ $ -- $ -- ======= =======

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, 2002 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 incorporation or organization)		(I.R.S. Employer 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 ¨

KELLEY PARTNERS 1994 DEVELOPMENT DRILLING PROGRAM

INDEX

		Page
Part I. Financial Information
Item 1. Financial Statements:
Balance Sheets as of December 31, 2001 and June 30, 2002 (unaudited)		2
Statements of Income for the three months and six months ended June 30, 2001 and 2002 (unaudited)		3
Statements of Cash Flows for the six months ended June 30, 2001 and 2002 (unaudited)		4
Notes to Financial Statements (unaudited)		5
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		6
Part II. Other Information		10

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

KELLEY PARTNERS 1994 DEVELOPMENT DRILLING PROGRAM

BALANCE SHEETS

(In thousands)

	December 31, 2001			June 30, 2002
				(Unaudited)
Assets:
Cash and cash equivalents	$	—		$	—
Accounts receivable—trade		1			—
Accounts receivable—affiliates		246			309

Total current assets		247			309

Oil and gas properties, successful efforts method:
Properties subject to amortization		32,873			32,873
Less: Accumulated depreciation, depletion and amortization		(28,616	)		(28,794	)

Total oil and gas properties		4,257			4,079

Total assets	$	4,504		$	4,388

Liabilities:
Accounts payable and accrued expenses	$	78		$	40

Total current liabilities		78			40

Total liabilities		78			40

Partners’ Equity:
LP Unitholders’ equity		249			244
GP Unitholders’ equity		4,003			3,934
Managing and special general partners’ equity		174			170

Total partners’ equity		4,426			4,348

Total liabilities and partners’ equity	$	4,504		$	4,388

See Notes to Financial Statements.

KELLEY PARTNERS 1994 DEVELOPMENT DRILLING PROGRAM

STATEMENTS OF INCOME

(In thousands, except per unit data)

(Unaudited)

	Three Months Ended June 30,					Six Months Ended June 30,
	2001			2002		2001		2002
Revenues:
Oil and gas sales	$	538		$	325	$	1,691	$	567

Total revenues		538			325		1,691		567

Expenses:
Production expenses		83			146		175		182
Severance taxes		12			19		30		39
General and administrative expenses		35			21		79		49
Depreciation, depletion and amortization		70			77		202		178
Impairment of oil & gas properties		442			—		442		—

Total expenses		642			263		928		448

Net (loss) income	$	(104	)	$	62	$	763	$	119

Net (loss) income allocable to LP and GP unitholders	$	(100	)	$	60	$	733	$	115

Net (loss) income allocable to managing and special general partners	$	(4	)	$	2	$	30	$	4

Net (loss) income per LP and GP unit	$	(.00	)	$	.00	$	.04	$	.01

Average LP and GP units outstanding		20,864			20,864		20,864		20,864

See Notes to Financial Statements.

KELLEY PARTNERS 1994 DEVELOPMENT DRILLING PROGRAM

STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)

	Six months Ended June 30,
	2001			2002
Operating Activities:
Net income	$	763		$	119
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, depletion and amortization		202			178
Impairment of oil & gas properties		442			—
Changes in operating assets and liabilities:
Increase in accounts receivable		(767	)		(62	)
Decrease in accounts payable and accrued expenses		(248	)		(38	)

Net cash provided by operating activities		392			197

Investing Activities:
Capital expenditures		(29	)		—

Net cash used in investing activities		(29	)		—

Financing Activities:
Distributions to partners		(363	)		(197	)

Net cash used in financing activities		(363	)		(197	)

Increase (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.

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 and six months ended June 30, 2002 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 3 to the financial statements included in its Annual Report on Form 10-K for the year ended December 31, 2001. These unaudited interim financial statements should be read in conjunction with the audited financial statements and notes thereto included in the Partnership’s 2001 Annual Report on Form 10-K.

NOTE 2—GENERAL PARTNER

Contour Energy E&P, LLC, managing general partner of the Partnership (“Contour E&P”), owns 95.62% of the Partnership units plus a 3.94% managing general partnership interest at June 30, 2002. Contour E&P is a subsidiary of Contour Energy Co. (collectively with its subsidiaries, “Contour” or the “Company”).

On July 15, 2002, Contour Energy Co. announced that it filed in the United States Bankruptcy Court for the Southern District of Texas, Houston Division (the “Bankruptcy Court”), a petition for reorganization under Chapter 11 of the United States Bankruptcy Code, Case No. 02-37740-H2-11. Contour E&P (Case No. 02-37741-H2-11) and Kelley Operating Company, Ltd. (Case No. 02-37744-H2-11), a joint venturer with the Partnership, (“Kelley Operating”), also filed Chapter 11 petitions with the Bankruptcy Court on that day. Following extensive negotiations with an informal committee of holders of more than 75% of their 10 3/8% subordinated notes (the “Ad Hoc Committee”), the Company and its subsidiaries filed a Joint Plan of Reorganization (the “Plan”) and a Disclosure Statement regarding the Plan with the Bankruptcy Court embodying the terms of a proposed restructuring of Contour and its affiliates. The Bankruptcy Court has not approved the Plan, and the Company cannot give any assurance that the Bankruptcy Court will approve the Plan in its current form.

As a result of the Contour E&P and Kelley Operating chapter 11 filings, a dissolution event has occurred under the limited partnership agreement governing the Partnership. The Partnership may be continued at the election of Unitholders holding a majority of the outstanding units. Contour E&P, as majority holder of the units, does not intend to take action to continue the Partnership.

With the Chapter 11 filing of Kelley Operating, a dissolution event has also occurred under the joint venture agreement pursuant to which properties of the Partnership are managed. Accordingly, the Partnership and the business of the Partnership’s joint venture with Kelley Operating shall be wound up and their respective assets distributed in accordance with the terms of the governing agreements. With the pendency of the Company’s Chapter 11 proceedings, the timing of winding up the affairs of the Partnership and the distribution of its assets is uncertain at this time. The accompanying unaudited interim financial statements of the Partnership have been prepared using the historical cost basis of accounting without further adjustments that maybe required if the Partnership is liquidated.

NOTE 3—NEW ACCOUNTING PRONOUNCEMENTS

In August and October 2001, the FASB issued SFAS No.143, “Accounting for Assets Retirement Obligations” and SFAS No. 144, “Accounting for Impairment or Disposal of Long-Lived Assets”. SFAS 143 requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset. Subsequently, the asset retirement costs should be allocated to expense using a systematic and rational method. SFAS 143 is

effective for fiscal years beginning after June 15, 2002. SFAS 144 addresses financial accounting and reporting for the impairment of long-lived and for long-lived assets to be disposed of. It supersedes, with exceptions, SFAS 121, “Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of”, and is effective for fiscal years beginning after December 15, 2001. The Partnership continues to assess the impact of SFAS No. 143 and cannot yet reasonably estimate the impact, if any, this statement will have on its financial statements upon adoption. The Partnership expects no impact to its financial statements upon the adoption of SFAS 144.

In April 2002, the Financial Accounting Standards Board (“FASB”) issued SFAS 145 “Rescission of FASB Statements No. 4, No. 44 and No. 64, Amendment to FASB Statement No. 13 and Technical Corrections”. SFAS No. 145 streamlines the reporting of debt extinguishments and requires that only gains and losses from extinguishments meeting the criteria in Accounting Policies Board Opinion 30 would be classified as extraordinary. Thus gains or losses arising from extinguishments that are part of a company’s recurring operations would not be reported as an extraordinary item. SFAS No. 145 is effective for fiscal years beginning after May 15, 2002. The Partnership does not expect the adoption of SFAS No. 145 to have an impact on its financial position, results of operations or cash flows.

SFAS No. 146, “Accounting for Costs Associated with Exit or Disposal Activities” was issued in June 2002 and addresses accounting and reporting for costs associated with exit or disposal activities and nullifies Emerging Issues Task Force (“ETIF”) issue No. 94-3, “Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit and Activity (including Certain Costs Incurred in a Restructuring), “SFAS No. 146 requires that a liability for a cost associated with an exit or disposal activity be recognized when the liability is incurred. Under Issue 94-3, a liability for an exit costs was recognized at the date of an entity’s commitment to an exit plan. Under SFAS No. 146, fair value is the objective for initial measurement of the liability. SFAS No. 146 is effective for exit disposal activities that are initiated after December 31, 2002. The Partnership does not expect the adoption of SFAS No. 146 to have an impact on its financial position, results of operations or cash flows.

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, 2002, Contour Energy E&P, LLC, managing general partner of the Partnership (“Contour E&P”) and a wholly owned subsidiary of Contour Energy Co. (collectively with its subsidiaries, “Contour” or the “Company”) owns 95.62% of the Units and a 3.94% managing general partnership interest.

Subsequent Events

On July 15, 2002, Contour Energy Co. and certain of its affiliates, including Contour E&P, the managing general partner of the Partnership, and Kelley Operating, a joint venturer with the Partnership, filed voluntary petitions under chapter 11 of the United States Bankruptcy Code. As a result of these filings, a dissolution event has occurred under the limited partnership agreement governing the Partnership. The Partnership may be continued at the election of Unitholders holding a majority of the outstanding units. Contour E&P, as majority holder of the units, does not intend to take action to continue the Partnership.

Chapter 11 proceedings, the timing of winding up the affairs of the Partnership and the distribution of its assets is uncertain at this time.

Results of Operations

Three Months Ended June 30, 2002 and 2001. Oil and gas revenues decreased 40% to $325,000 for the second quarter of 2002 compared to $538,000 in the corresponding quarter of 2001, primarily the result of lower natural gas and crude oil production and lower natural gas and crude oil prices. Production of natural gas decreased 21% from 112,545 Mcf in the second quarter of 2001 to 88,673 Mcf in the current quarter primarily due to normal production declines in the Partnership’s producing areas. The average price of natural gas decreased 23% from $4.71 per Mcf in the second quarter of 2001 to $3.61 per Mcf in the current quarter. Production of crude oil in the current quarter totaled 452 barrels, with an average sales price of $23.76 per barrel compared to 606 barrels, with an sales average price of $28.30 per barrel, in the same quarter last year, representing a volume decrease of 25% and a price decrease of 16%.

Production expenses and severance taxes were $165,000 in the current quarter versus $95,000 in the second quarter of 2001, an increase of 74%. The second quarter 2002 includes $45,000 for insurance costs due to increased policy premiums for the period May 2001 through May 2002. The Partnership also experienced higher severance taxes during the current quarter due to a higher tax rate on natural gas imposed by the state of Louisiana in July 2001. As a result of these factors and lower production volumes in the current quarter, production expenses and severance taxes on a per unit of production basis increased from $0.81 per Mcfe in the second quarter of 2001 to $1.81 per Mcfe in the current quarter. Excluding the increase in insurance cost, per unit of production cost would have been $1.31 per Mcfe for the current quarter.

General and administrative (“G&A”) expenses decreased 40% to $21,000 in the current quarter from $35,000 in the second quarter of 2001. Lower second quarter 2002 production volumes caused a decline in G&A expenses charged by Contour E&P to the Partnership. On a unit of production basis, these expenses were $0.23 per Mcfe for the second quarter of 2002 compared to $0.30 per Mcfe for the second quarter of 2001, a 23% decrease.

Depreciation, depletion and amortization (“DD&A”) expenses increased 10% to $77,000 in the second quarter of 2002 from $70,000 in the second quarter of 2001, primarily the result of a higher composite DD&A rate as proportionally higher volumes of production were produced from higher DD&A rate fields. On a unit of production basis, DD&A expense was $0.84 per Mcfe in the second quarter of 2002 compared to $0.60 per Mcfe in the same quarter last year, an increase of 40%.

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 net income of $62,000 or $0.00 per Unit for the second quarter of 2002. For the second quarter of 2001, the Partnership recognized a net loss of $(104,000) or $(0.00) per Unit. The reasons for the variance between the second quarter of 2002 and the second quarter of 2001 are described in the foregoing discussion.

Six Months Ended June 30, 2002 and 2001. Oil and gas revenues decreased 66% to $567,000 for the first six months of 2002 compared to $1,691,000 in the corresponding period of 2001 primarily the result of lower natural gas and crude oil production and lower natural gas and crude oil prices. Production of natural gas decreased 28% from 267,019 Mcf in the first six months of 2001 to 193,098 Mcf in the current period primarily due to normal production declines in the Partnership’s producing areas. The decrease in revenues and production for the first six months of 2002 were also in part the result of a well payout adjustment in the first quarter of 2002. The average price of natural gas was $6.25 per Mcf in the first half of 2001 compared to $2.89 per Mcf in first six months of 2002, a decrease of 54%. Production of crude oil in the current period totaled 884 barrels, with

an average sales price of $22.27 per barrel compared to 2,401 barrels priced at an average price of $23.87 per barrel in the same period last year, representing a volume decrease of 63% and a price decrease of 7%.

Production expenses and severance taxes were $221,000 in the current period versus $205,000 in the first half of 2001, an increase of 8%. The first six months of 2002 includes $45,000 for insurance costs due to increased policy premiums for the period May 2001 through May 2002. The Partnership also experienced higher severance taxes during the first half of 2002 due to a higher tax rate on natural gas imposed by the state of Louisiana in July 2001. These increases were partially offset by a reduction of production expenses due to a well payout adjustment in the first quarter 2002. On a unit of production basis, these expenses increased to $1.12 per Mcfe in the first six months of 2002 from $0.73 per Mcfe in the year-earlier period.

G&A expenses decreased 38% to $49,000 in the current period from $79,000 in the first half of 2001. Lower current period production activity caused the decline in G&A expenses charged by Contour E&P to the Partnership. On a unit of production basis, these expenses decreased from $0.28 per Mcfe in the first six months of 2001 to $0.25 per Mcfe in the current period.

DD&A expenses decreased 12% from $202,000 in the first six months of 2001 to $178,000 in the current period primarily the result of lower equivalent production partially offset by a higher composite DD&A rate as proportionally higher volumes of production were produced from higher DD&A rate fields. On a unit of production basis, DD&A expense increased to $0.90 per Mcfe in the first half of 2002 from $0.72 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 $119,000 or $0.01 per Unit for the first half of 2002. For the first half of 2001, the Partnership recognized net income of $763,000 or $0.04 per Unit. The reasons for the variance between the first six months of 2002 and the first six months of 2001 are described in the foregoing discussion.

The results of operations for the quarter and six months ended June 30, 2002 are not necessarily indicative of the Partnership’s operating results to be expected for the full year.

Liquidity and Capital Resources

Liquidity. The Partnership generated $197,000 of cash flows from its operating activities during the first six months of 2002, as reflected on its statement of cash flows. Additionally, no cash was provided by or used in its investing activities during the period. The Partnership made distributions of $197,000 to its partners in the first half of 2002 and as a result the Partnership’s cash and cash equivalents remained unchanged from December 31, 2001.

Commodity Prices. The Partnership experienced weak commodity prices during the first three months of 2002 with average realized prices for natural gas and crude oil of $2.28/Mcf and $20.70/Bbl, respectively. Commodity prices strengthened in the second quarter of 2002 with average realized prices for natural gas and crude oil of $3.61/Mcf and $23.76/Bbl, respectively. However, prices have weakened recently with the price for August natural gas falling again below $3.00/Mmbtu on the NYMEX. Storage levels for natural gas remain at historically high levels and the strength and timing of improvement in demand for natural gas is uncertain.

Capital Resources. The Partnership has completed its development stage. Accordingly, capital and general working capital needs should be minimal.

Although the capital needs of the Partnership are minimal and are funded by cash flows from operations, the administration of the Partnership and its assets are dependent on Contour E&P as Managing General Partner. The

financial difficulties that lead to Contour’s bankruptcy filing (see Note 2 to the Notes to the Financial Statements) could have a detrimental effect on Contour E&P’s abilities to administer the Partnership.

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. During the first half of 2002, $197,000 was distributed to the Partnership’s Unitholders and the managing and special general partners. Future distributions to the Unitholders and the managing and special general partners 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 August and October 2001, the FASB issued SFAS No. 143, “Accounting for Asset Retirement Obligations” and SFAS No. 144, “Accounting for Impairment or Disposal of Long-Lived Assets”. SFAS 143 requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset. Subsequently, the asset retirement costs should be allocated to expense using a systematic and rational method. SFAS 143 is effective for fiscal years beginning after June 15, 2002. SFAS 144 addresses financial accounting and reporting for the impairment of long-lived assets and for long-lived assets to be disposed of. It supersedes, with exceptions, SFAS 121, “Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of”, and is effective for fiscal years beginning after December 15, 2001. The Partnership is currently assessing the impact of SFAS No. 143 and cannot yet reasonably estimate the impact, if any, this statement will have on its financial statements upon adoption. The Partnership expects no impact to its financial statements upon the adoption of SFAS 144.

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 statement” 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, oil and natural gas prices, uncertainty of reserve estimates, rates and timing of future production of oil and natural 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 10 and 11 of the Partnership’s Annual Report on Form 10-K for the fiscal year ended December 31, 2001.

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
*99.1		Certification Pursuant to 18 U.S.C. 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
*99.2		Certification Pursuant to 18 U.S.C. 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

filed herewith.

(b) Reports on Form 8-K:

No reports on Form 8-K were filed by the Registrant during the second quarter of 2002.

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:		CONTOUR ENERGY E&P, LLC Managing General Partner

By:		/s/ RICK G. LESTER
		Rick G. Lester Manager

Date: August 22, 2002

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