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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D C 20549

Form 10-K

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D)
OF THE SECURITIES EXCHANGE ACT OF 1934

For the year ended December 31, 2001

Commission file number 001-11769

KEY PRODUCTION COMPANY, INC.

A Delaware Corporation

IRS Employer No. 84-1089744

707 Seventeenth Street, Suite 3300
Denver, Colorado 80202
Telephone Number (303) 295-3995

Securities Registered Pursuant to Section 12(b) of the Act:

Title of Each Class		Name of Each Exchange on Which Registered
Common Stock ($.25 par value)		New York Stock Exchange

Securities Registered Pursuant to Section 12(g) of the Act: None

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 ý NO o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of the registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.

Aggregate market value of the voting stock held by non-affiliates of Key Production Company, Inc. as of March 8, 2002 was approximately $241,992,230.

Number of shares of Key Production Company, Inc. common stock outstanding as of March 8, 2002 was 14,046,252.

Documents Incorporated by Reference: None

TABLE OF CONTENTS

DESCRIPTION

Item		Page
PART I
1.	Business	3
2.	Properties	7
3.	Legal Proceedings	10
4.	Submission of Matters to a Vote of Security Holders	10
PART II
5.	Market for the Registrant's Common Equity and Related Stockholders Matters	11
6.	Selected Financial Data	11
7.	Management's Discussion and Analysis of Financial Condition and Results of Operations	12
7A.	Quantitative and Qualitative Disclosures About Market Risk	20
8.	Financial Statements and Supplementary Data	22
9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	44
PART III
10.	Directors and Executive Officers of the Registrant	45
11.	Executive Compensation	47
12.	Security Ownership of Certain Beneficial Owners and Management	54
13.	Certain Relationships and Related Transactions	56
PART IV
14.	Exhibits, Financial Statement Schedules and Reports on Form 8-K	57

In this report, we use terms to discuss oil and gas producing activities as defined in Rule 4-10(a) of Regulation S-X. We express quantities of natural gas in terms of thousand cubic feet (Mcf), million cubic feet (MMcf) or billion cubic feet (Bcf). Oil is quantified in terms of barrels (Bbls), thousands of barrels (MBbls) and millions of barrels (MMBbls). Oil is compared to natural gas in terms of equivalent thousand cubic feet (Mcfe). One barrel of oil is the energy equivalent of six Mcf of natural gas. Information relating to our working interest in wells or acreage, "net" oil and gas wells or acreage is determined by multiplying gross wells or acreage by our working interest therein. Unless otherwise specified, all references to wells and acres are gross.

PART I

ITEM 1. BUSINESS

General

Key Production Company, Inc. is an independent energy company engaged in the exploration, development, acquisition, and production of oil and gas in the continental United States. We conduct exploration and development activities primarily in the Anadarko Basin of Oklahoma, the Mississippi Salt Basin, south Louisiana, and northern California. We also have production operations and exploration acreage in Wyoming and other Rocky Mountain states.

Key was incorporated in Delaware on June 22, 1988, and our corporate office is in Denver, Colorado. We have regional operations offices in: Tulsa, Oklahoma; New Orleans, Louisiana; and Sacramento, California and district operational offices in: Laredo, Texas; Houston, Texas; Elk City, Oklahoma; and Sidney, Montana. Key's common stock trades on the New York Stock Exchange under the symbol KP. We report all our operations as one business segment.

As of December 31, 2001, we had estimated proved reserves of approximately 92.0 Bcf of gas and 9.2 MMBbls of oil, or an aggregate of 147.3 Bcfe. Roughly 62 percent of our proved reserves are gas and 38 percent are oil. More than 99 percent of our proved reserves are classified as proved developed.

We own approximately 177,000 net acres of developed leases and 104,000 net acres of undeveloped leases, the bulk of which is in Wyoming, Mississippi, Texas, California and Oklahoma. We also own working interests in 2,267 (376 net) oil and gas wells located primarily in those same states.

Our primary business objective is to enhance shareholder value. To accomplish this objective we have implemented strategies designed to generate attractive economic returns on capital employed and profitable growth in per-share reserves, production, and cash flow. We maintain a balanced program of exploration and development, supplemented from time to time by acquisitions and other business development initiatives that lead to new drilling projects. Given the highly competitive nature of the domestic oil and gas business, decentralization is also a core component of our business strategy. We seek to have local experts in each of our regional offices equipped with the necessary authority to act decisively and motivated by economic incentives designed to benefit Key's common shareholders.

In our search for new oil and gas reserves, Key's technical staff uses sophisticated computer systems for processes encompassing geology, geophysics, petrophysics, engineering, and economic modeling. Modern field-tested drilling tools and production technologies also play an integral role in our pursuit of cost-effective oil and gas resources development. We routinely pool our collective expertise to ensure that we bring the necessary professional skills and exploration techniques to bear on every project. Equally important, we temper our use of technology with experience and sound professional judgment.

We believe that maintaining a strong balance sheet is integral to the successful execution of our business strategies because it provides the financial capability to capture attractive investment opportunities and the wherewithal to weather periods of low commodity prices.

Business During 2001

Fueled by increased gas production, total revenues rose nine percent over the previous year to $108.9 million. Net income decreased 119 percent from $28.0 million in 2000 to a net loss of $5.4 million, primarily due to a $45.1 million pre-tax full cost ceiling test write-down (See "Management's Discussion and Analysis of Financial Condition and Results of Operations"). Earnings per diluted share decreased to a loss per diluted share of $0.39 from earnings per diluted share of $2.23, and cash from operating activities of $83.5 million increased 18 percent from the $70.9 million reported in 2000.

Our combined oil and gas production volumes increased 13 percent to 26 Bcfe. Gas volumes increased 21 percent to 46.0 MMcf per day and oil volumes remained relatively the same at 4,212 Bbls per day in 2001 compared to 4,192 Bbls per day in 2000.

Our average realized oil price declined by 17 percent to $23.87 in 2001 compared to the 2000 average of $28.92. The oil price decrease reduced sales by approximately $7.8 million. Average gas prices rose to $4.22 per Mcf in 2001, up nine percent from the $3.87 per Mcf averaged in 2000. The positive change in gas prices added approximately $5.9 million to sales.

Cash production costs, including lease operating expense, general and administrative expense, and production-related taxes, equated to $1.08 per Mcfe in 2001, or 41 percent more than the prior year's corresponding figure of $0.77 per Mcfe. Lease operating expenses of $0.65 per Mcfe were up 39 percent compared to the $0.47 per Mcfe in 2000. Production taxes for 2001 amounted to $0.26 per Mcfe versus $0.16 in 2000, an increase of 63 percent. General and administrative expenses of $0.17 per Mcfe increased 22 percent from $0.14 per Mcfe in 2000.

Our year-end 2001 proved oil and gas reserves decreased four percent to 147.3 Bcfe primarily as a result of wells becoming non-economic earlier in their lives due to the oil and gas price decreases at December 31, 2001 compared to December 31, 2000. Net negative reserve revisions, mostly related to lower prices, totaled 4.7 Bcfe. Sixty-two percent of our proved reserves (92.0 Bcf) are gas and 38 percent are oil (9.2 MMBbls). Approximately 99 percent of year-end 2001 proved reserves were classified as developed.

During 2001, we made exploration and development expenditures of $73.7 million and participated in drilling 114 wells, with an overall success rate of 75 percent. We concentrated our drilling efforts in the Mid-Continent region, Mississippi, south Louisiana, and California. We drilled 61 wells in the Mid-Continent region, and completed 52 of them as producers. In our Gulf Coast region, 15 out of 25 wells drilled were successful. Our western region yielded 18 good wells out of 28 attempts. On a net basis, 24.7 of the 41.5 wells we drilled were successful. Overall, reserve additions from extensions and discoveries totaled 23.6 Bcfe.

At December 31, 2001, our total debt was $34.0 million, $10 million less than a year earlier; and our debt as compared to total book capitalization was 20 percent.

Merger with Helmerich & Payne, Inc.'s Oil and Gas Division

On February 23, 2002, Key, Helmerich & Payne, Inc., a Delaware corporation (H&P), Helmerich & Payne Exploration and Production Co., a Delaware corporation and a wholly owned subsidiary of H&P, which, after the Merger will be named Cimarex Energy Co. (Cimarex) and a wholly owned subsidiary of Cimarex (Merger Sub), entered into an Agreement and Plan of Merger (Merger Agreement). Under the Merger Agreement and other related transaction documents: (i) H&P will transfer to Cimarex certain assets primarily related to the oil and gas exploration, production, marketing and sales operations of H&P, (ii) Cimarex will assume certain liabilities of H&P and (iii) H&P will distribute to its shareholders approximately 0.53 shares of Cimarex common stock for each share of H&P common stock (Spin-off). Immediately thereafter, Merger Sub will be merged with and into Key, with Key as the surviving corporation (Merger).

In connection with the Merger, the stockholders of Key will receive one share of Cimarex common stock for each share of Key common stock they own immediately prior to the Merger, as set forth in the Merger Agreement. Upon completion of the transaction, holders of H&P common stock will own 65.25 percent and Key shareholders will own 34.75 percent of the common stock of Cimarex, in each case on a fully diluted basis.

The Merger Agreement has been approved by the respective Boards of Directors of Key and H&P. The Spin-off is subject to, among other things, receipt of a ruling from the Internal Revenue Service to

the effect that the Spin-off is tax-free. The Merger is subject to, among other things, the completion of the Spin-off, the approval of the stockholders of Key, and the receipt of opinions of counsel of each of Key and H&P to the effect that the Merger is tax-free. It is currently anticipated that the Merger will occur in the third calendar quarter of 2002.

Competition

The oil and gas industry is highly competitive. As a small independent oil and gas company, we find ourselves competing against companies with substantially larger financial, human, and technological resources for a variety of opportunities, including the purchase of proved reserves, exploratory lease acquisitions, and the marketing of our gas and oil.

Natural Gas and Oil Prices

Our 2001 gas price averaged $4.22 per Mcf, $0.35 higher than the prior year average of $3.87 per Mcf. Our 2001 average oil price was $23.87 per barrel, down $5.05 from the $28.92 per barrel reported in 2000. We did not use derivative instruments to mitigate the impact of changes in commodity prices. Our business will continue to be affected by changes in domestic and international oil and gas prices. We cannot predict, with any degree of accuracy, the trend in, or level of, future oil and gas prices and their impact on our reported results in future periods.

Reserve Value Ceiling Test

We review the carrying value of our oil and gas properties on a quarterly basis as prescribed by the accounting rules of the Securities and Exchange Commission (SEC). Under full cost accounting rules, capitalized costs of oil and gas properties, net of accumulated depreciation, depletion, and amortization, and deferred income taxes, may not exceed the present value of estimated future net revenues from proved reserves, discounted at 10 percent, plus the lower of cost or fair market value of unproved properties, as adjusted for related tax effects and deferred tax revenues. Applying this rule requires pricing of future revenues at the unescalated prices in effect at the end of each fiscal quarter and requires a write-down if the "ceiling" is exceeded, even if prices declined for only a short period of time. A reduction in the carrying value of oil and gas properties resulting from the ceiling test limitation is a non-cash charge to earnings.

Based on oil and gas prices in effect on December 31, 2001, the unamortized cost of our oil and gas properties exceeded the ceiling from our proved oil and gas reserves. We incurred a charge to earnings before income taxes of $45.1 million.

Regulation of Oil and Gas

Our exploration, production and marketing activities are regulated extensively by federal, state, and local governments. Oil and gas exploration, development and production activities are subject to various laws and regulations governing a wide variety of matters. For example, the states in which Key produces oil and gas have statutes or regulations addressing production practices that may affect our operations and limit the quantity of hydrocarbons we may produce and sell. Marketing and transportation of oil and gas and the valuation of royalty payments are also regulated.

The Federal Energy Regulatory Commission (FERC) regulates interstate transportation of natural gas under the Natural Gas Act among other regulated matters. Intrastate and interstate gas transportation regulations affect our gas sales. FERC has issued a series of orders that have significantly altered the marketing and transportation of natural gas. To date, Key has not experienced any material adverse effect on gas marketing as a result of these FERC orders. However, we cannot predict what effect subsequent regulations may have on future gas marketing.

Environmental

We are subject to various federal, state, and local laws and regulations relating to discharge of materials into, and protection of, the environment. These laws and regulations may, among other things, impose liability for the cost of pollution clean-up resulting from operations, subject us to liability for pollution damages, and restrict injection of liquids into subsurface aquifers that may contaminate groundwater.

Key has and will continue to incur costs complying with these requirements, which we believe are necessary business costs in the oil and gas industry. These costs are inextricably connected to normal operating expenses. We are unable to separate the expenses related to environmental matters. Although environmental regulations do have a substantial impact upon the energy industry, generally these requirements do not appear to affect Key any differently or to any greater or lesser extent than any other companies in the industry.

We are not aware of any environmental claims existing as of December 31, 2001, which would have a material impact upon our financial condition or results of operations. We do not believe that compliance with federal, state or local provisions regulating the discharge of materials into the environment, or otherwise relating to the protection of the environment, will have such an impact.

Employees

On December 31, 2001, Key had 97 employees.

Offices

Our principal executive office is located at 707 Seventeenth Street, Suite 3300, Denver, Colorado 80202-3404.

Glossary

Mcf—Thousand cubic feet (of natural gas)
MMcf—Million cubic feet
Bcf—Billion cubic feet
Mcfe—Thousand cubic feet equivalent
MMcfe—Million cubic feet equivalent
Bcfe—Billion cubic feet equivalent
Bbls—Barrels (of oil)
MBbls—Thousand barrels
MMBbls—Million barrels
Net Acres—Gross acreage multiplied by working interest percentage
Net Production—Gross production multiplied by net revenue interest

One barrel of oil is the energy equivalent of six Mcf of natural gas.

ITEM 2. PROPERTIES

We have implemented a decentralized approach to our exploration and development program, and to the management of our producing oil and gas properties. The following are the geographic areas that we are involved in:

Mid-Continent

Our Mid-Continent region consists of properties principally located in the Anadarko Basin of western Oklahoma, the Hardeman Basin of north Texas, and the Laredo field in south Texas. Managed out of Tulsa, Oklahoma, the Mid-Continent region is our largest source of proved reserves and production, as well as a significant part of our drilling program. Year-end 2001 proved reserves attributable to this region were 79.4 Bcfe, or 54 percent of the company's total proved reserves. Average daily volumes during 2001 approximated 29.3 MMcf of gas and 2,100 barrels of oil.

Gulf Coast

Our New Orleans-based Gulf Coast region encompasses the Mississippi Salt Basin, selected areas of south Louisiana, and coastal Texas. At year-end 2001, the Gulf Coast had proved reserves of 31.9 Bcfe, or 22 percent of our total proved reserves. Daily production during 2001 averaged 8.5 MMcf of gas and 1,100 barrels of oil.

Western

Our Western region directs production, exploration and development activities from our office in Denver, Colorado. Western's primary focus is on the Sacramento Basin in California and the Powder River, Wind River and Big Horn Basins of Wyoming. Year-end 2001 proved reserves in this region were 36.0 Bcfe and average daily production was approximately 8.2 MMcf of gas and 1,000 barrels of oil.

Proved Reserves

Region	Gas (MMcf)	Oil (MBbls)	Equivalent (MMcfe)
Mid-Continent	57,650	3,627	79,412
Gulf Coast	17,382	2,418	31,891
Western	16,946	3,170	35,967

Total	91,978	9,215	147,270

Proved developed	91,441	9,176	146,496

Our engineers estimate proved natural gas and oil reserve quantities in accordance with guidelines established by the SEC. Ryder Scott Company, L.P., who are independent petroleum engineers, reviewed approximately 80 percent of our reserve value estimates. All information in this Form 10-K relating to oil and gas reserves is net to Key's interest unless stated otherwise. See Supplemental Oil and Gas Disclosures in this Form 10-K for further information.

Acreage

The undeveloped and developed acreage held by Key as of December 31, 2001, is set forth below:

			Undeveloped Acreage		Developed Acreage
			Gross Acres	Net Acres	Gross Acres	Net Acres
Mid-Continent
	Kansas		160	6	10,417	9,182
	Oklahoma		31,318	17,378	155,160	33,472
	Texas		16,976	12,531	26,652	6,365

			48,454	29,915	192,229	49,019

Gulf Coast
	Arkansas		—	—	1,596	238
	Louisiana		5,282	316	37,522	3,033
	Mississippi		21,649	9,234	10,009	2,020
	Texas		2,424	373	116,758	22,412

			29,355	9,923	165,885	27,703

Western
	California		17,194	13,307	7,115	5,668
	Colorado		619	310	10,472	2,140
	Montana		8,738	4,923	35,590	16,540
	New Mexico		840	630	22,843	4,317
	North Dakota		1,659	277	36,828	3,516
	Utah		8,767	5,794	9,172	2,261
	Wyoming		73,957	39,315	212,081	64,868
	Other		—	—	14,274	1,132

			111,774	64,556	348,375	100,442

		Total Company	189,583	104,394	706,489	177,164

Productive Wells

We have working interests in the following productive gas and oil wells as of December 31, 2001:

	Gas		Oil
	Gross	Net	Gross	Net
Mid-Continent	851	147.9	194	74.0
Gulf Coast	174	26.9	200	33.3
Western	164	32.0	684	61.8

	1,189	206.8	1,078	169.1

In addition, we have royalty or overriding royalty interests in approximately 119 properties in the Mid-Continent region, 65 properties in the Gulf Coast region, and 1,884 properties in the Western region.

Gross Wells Drilled

Key participated in the following number of wells drilled during 2001, 2000, and 1999:

	Exploratory			Developmental
	Productive	Dry	Total	Productive	Dry	Total
2001
Mid-Continent	3	3	6	49	6	55
Gulf Coast	3	8	11	12	2	14
Western	5	10	15	13	—	13

	11	21	32	74	8	82

2000
Mid-Continent	3	5	8	38	5	43
Gulf Coast	8	2	10	13	—	13
Western	2	10	12	18	1	19

	13	17	30	69	6	75

1999
Mid-Continent	4	5	9	35	6	41
Gulf Coast	4	3	7	11	1	12
Western	8	9	17	15	3	18

	16	17	33	61	10	71

We were in the process of drilling 2 gross (2 net) wells at December 31, 2001.

Net Wells Drilled

The number of net wells Key drilled during each of the last three years is shown below:

	Exploratory			Developmental
	Productive	Dry	Total	Productive	Dry	Total
2001	5.3	12.1	17.4	19.4	4.7	24.1
2000	5.9	12.2	18.1	20.0	1.9	21.9
1999	10.2	12.1	22.3	13.6	2.4	16.0

Production and Pricing Information

The following table describes, for each of the last three fiscal years, our gas and oil production and pricing data.

			Average Sales Price
Year Ended December 31,	Gas MMcf	Oil MBbls	Average Sales Price				Average Production Cost Per Mcfe
Year Ended December 31,	Gas MMcf	Oil MBbls	Per Mcf		Per Bbl		Average Production Cost Per Mcfe
2001	16,775	1,537	$	4.22	$	23.87	$	0.91
2000	13,855	1,534	$	3.87	$	28.92	$	0.63
1999	14,070	1,375	$	2.19	$	17.58	$	0.52

Reserve Information

Key's estimated proved oil and gas reserves, as of December 31, 2001, 2000, and 1999, and the standardized measure of discounted future net cash flows attributable thereto at December 31, 2001, 2000, and 1999 are included in Supplemental Oil and Gas Disclosures to Financial Statements

appearing in this Form 10-K. Supplemental Oil and Gas Disclosures also include Key's net revenues from production (including royalty and working interest production) of oil and natural gas for each year in the three year period ended December 31, 2001.

	Total Proved Reserves			Proved Developed Reserves
December 31,	Gas (MMcf)	Oil (MBbls)	Equivalent MMcfe	Gas (MMcf)	Oil (MBbls)	Equivalent MMcfe
2001	91,978	9,215	147,270	91,441	9,176	146,496
2000	98,214	9,276	153,870	97,564	9,268	153,172
1999	79,351	9,220	134,671	77,048	8,916	130,544

Future reserve values are based on year-end prices except in those instances where the sale of gas is covered by contract terms providing for determinable escalations. Operating costs, production and ad valorem taxes, and future development costs are based on current costs with no escalations.

	Present Value of Estimated Future Net Cash Flows Before Income Tax (Discounted at 10 Percent)		Present Value of Estimated Future Net Cash Flows After Income Tax (Discounted at 10 Percent)
					Year-End Price Used in Calculation of Future Net Cash Flows
Year Ended December 31,					Year-End Price Used in Calculation of Future Net Cash Flows
Year Ended December 31,	Proved		Proved		Gas		Oil
	(In Thousands, Except Prices)
2001	$	182,881	$	147,065	$	2.59	$	17.30
2000	$	638,439	$	454,931	$	10.45	$	24.17
1999	$	185,204	$	146,975	$	2.16	$	23.68

No major discovery or other favorable or adverse event is believed to have occurred since December 31, 2001, which would cause significant change in the estimated proved reserves reported herein. The above estimates are based on year-end pricing in accordance with SEC guidelines and do not reflect current prices. Since December 31, 2001, no oil or gas reserve information has been filed with, or included in any report to, any federal authority or agency other than the SEC and/or the Energy Information Administration.

ITEM 3. LEGAL PROCEEDINGS

We are not subject to any pending litigation that, in the opinion of our management, will materially affect the financial position or results of operations of Key.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

No matters were submitted for a vote of security holders during the fourth quarter of 2001.

PART II

ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS

Key's common stock, par value $.25 per share, trades on the New York Stock Exchange under the symbol KP. No dividends were paid in 2001 or in 2000. The table below shows the market price of the common stock for 2001 and 2000:

	Market Price
	2001				2000
	High		Low		High		Low
First Quarter	$	33.000	$	18.600	$	13.938	$	6.938
Second Quarter	$	22.980	$	15.310	$	20.938	$	11.625
Third Quarter	$	16.750	$	10.950	$	24.813	$	13.250
Fourth Quarter	$	17.730	$	10.850	$	33.750	$	20.500

The closing price of Key's common stock as reported on the New York Stock Exchange for March 8, 2002, was $17.69. At December 31, 2001, the Company's 14,041,269 shares of common stock outstanding were held by approximately 4,800 stockholders of record and approximately 7,100 beneficial owners.

ITEM 6. SELECTED FINANCIAL DATA

The following table sets forth selected financial data of the Company for each of the years in the five-year period ended December 31, 2001, which information has been derived from the Company's audited financial statements. This information should be read in connection with and is qualified in its entirety by the more detailed information and consolidated financial statements under Item 8 below:

		For the Year Ended December 31,
		2001			2000		1999		1998		1997
		(In Thousands, Except Per Share Data)
Revenues		$	108,885		$	99,820	$	56,258	$	37,783	$	42,151
Income (loss) before cumulative effect of change in accounting method, net of income taxes (1)			(3,617	)		27,995		6,804		4,595		9,696
Net income (loss)			(5,442	)		27,995		6,804		4,595		9,696
Income (loss) per share before cumulative effect of change in accounting method:
	Basic		(0.26	)		2.32		0.59		0.40		0.84
	Diluted		(0.26	)		2.23		0.56		0.38		0.80
Net income (loss) per share:
	Basic		(0.39	)		2.32		0.59		0.40		0.84
	Diluted		(0.39	)		2.23		0.56		0.38		0.80
Oil and gas expenditures			73,658			88,118		34,456		55,429		44,625
Total assets			217,668			244,154		176,857		166,295		130,647
Bank debt			34,000			44,000		60,000		60,000		35,000
Stockholders' equity			134,227			138,087		76,873		69,681		64,911

(1): See "summary of significant accounting policies," in Item 8 below, for a discussion on the change in accounting method relating to depreciation of our oil and gas properties.

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Financial Results

In 2001, we incurred a net loss of $5.4 million, or $0.39 per diluted share. The net loss includes a cumulative effect of a change in accounting method after income taxes of $1.8 million and a full cost ceiling write-down of $45.1 million, $27.8 million net of income taxes. If we had adopted the change in accounting method sooner, our pro forma net income for 2000 would have been $31.7 million, or $2.52 per diluted share. For 1999, pro forma net income was $10.4 million, or $0.86 per diluted share.

Revenues had an upward trend as we recorded total revenues of $108.9, $99.8 and $56.3 million in 2001, 2000 and 1999, respectively. Although oil and gas prices declined through the year, we received a higher average price for our gas production and continued to see increased oil and gas production. The prices we receive for oil and gas sales are market driven. However, our production growth is the result of the Columbus acquisition and a successful drilling program.

Effective January 1, 2001, we changed our method of amortizing capitalized costs from the future gross revenue method to the units-of-production method. Key believes that the newly adopted accounting principle is preferable in the circumstances because the units-of-production method results in a better matching of the costs of oil and gas production against the related revenue received in periods of volatile prices for production, as have been experienced in recent periods. Additionally, the units-of-production method is the predominant method used by full cost companies in the oil and gas industry, accordingly, the change improves the comparability of the Company's financial statements with its peer group.

The cumulative effect of the change, calculated as of January 1, 2001, was to increase net loss by $1.8 million, net of income taxes of $1.1 million, or $0.13 per diluted share. The effect of the change was to increase net loss for the year ended December 31, 2001 by $7.8 million, $4.8 million net of income taxes, or $0.34 per diluted share.

The following selected financial data for the years ended December 31, 2000 and 1999 have been adjusted on a pro forma basis assuming the new method of computing depreciation, depletion and amortization expense (DD&A) is applied retroactively.

		Year Ended December 31,
		2000		1999
		(In Thousands, Except Per Share Data)
Depreciation, depletion and amortization		$	29,383	$	22,894
Provision for income taxes		$	18,595	$	6,309
Net income		$	31,662	$	10,444
Net income per common share:
	Basic	$	2.62	$	0.91
	Diluted	$	2.52	$	0.86

For purposes of our discussion and analysis of financial condition and results of operations for the years ended December 31, 2001 and 2000, we have used pro forma data for the year ended December 31, 2000.

Results of Operations

Our oil and gas sales rose nine percent to $108.7 million in 2001, from $99.4 million in 2000. The $9.3 million increase in sales included an increase in gas sales of $17.2 million, offset by a decrease in

oil sales of $7.7 million and a decrease in plant products of $0.2 million. We produced combined oil and gas volumes of 71.2 MMcfe per day in 2001 compared to 63.0 MMcfe in 2000, an increase of 13 percent. The nine percent overall increase in 2001 revenues was mostly fueled by increased gas production.

Between 2000 and 1999, our oil and gas sales climbed 78 percent to $99.4 million. Oil sales generated $20.2 million of the 2000 sales increase, $22.9 million is from gas sales and $0.5 million is from plant products. Combined oil and gas production increased to 63.0 Mmcfe per day in 2000, up three percent from the 61.2 MMcfe per day produced during the prior year.

Gas sales for 2001 increased to $70.8 million from $53.7 million, a 32 percent increase, due primarily to an increase in gas production and higher gas prices in the first half of 2001. During 2001, gas production increased to 45,959 Mcf per day from 37,855 Mcf per day in 2000. The 21 percent increase in gas volumes improved sales by $11.3 million. We had higher volumes than the prior year due primarily to production from new wells drilled in the Mid-Continent region of 7,601 Mcf per day and the December 2000 merger with Columbus, partially offset by natural declines in older wells. The Columbus merger contributed 5,777 Mcf per day in 2001 and none in 2000. Our average realized gas price was $4.22 per Mcf in 2001 compared to $3.87 per Mcf in 2000. The $0.35 per Mcf increment added approximately $5.8 million to sales.

Between 2000 and 1999, gas sales climbed to $53.7 million from $30.8 million. Significantly higher prices contributed to the 74 percent increase. The rise in gas prices was in response to a tighter balance between supply and demand in North America during 2000 and added approximately $23.3 million to sales. During 2000, average daily production declined to 37,855 Mcf per day from 38,549 Mcf per day in 1999. The two percent decrease in gas volumes reduced sales by $0.5 million. Through the first nine months of 2000, we had higher volumes than the prior year due to production from new wells in Oklahoma and Mississippi, partially offset by natural reservoir declines in the Sacramento Basin of California. However, in the fourth quarter of 2000, our volumes were also negatively impacted by inclement weather in the Mid-Continent region and continuing declines in California.

Driven by significantly lower prices, our oil sales decreased by 17 percent between 2001 and 2000. Sales declined to $36.7 million in 2001 from $44.4 million in 2000. We realized an average of $23.87 per barrel in 2001, compared to $28.92 per barrel in 2000. The price difference between the two years accounted for approximately $7.8 million of the decrease in oil sales. We produced an average of 4,212 barrels per day in 2001 compared to 4,192 barrels per day in 2000. The increase in production accounted for approximately $0.1 million of positive sales variance.

The decline in prices during the year is a direct result of many factors. Market analysts and economists point to many factors that influence energy prices, including weather, economics growth, geopolitical events, Organization of Petroleum Exporting Countries policies, electricity demand, and others. We have not entered into any derivative contracts or hedges with respect to our production. As a result, the prices we receive reflect the impact of market forces. Our analysis indicates that the prices we receive tend to follow changes in domestic natural gas prices and worldwide oil prices. A commonly used benchmark for natural gas prices is the price at the Henry Hub as reported by Natural Gas Week. There is a strong correlation between our gas prices and the prices at the Henry Hub, adjusted for basis differentials and gas quality. A similar relationship exists for our oil prices. One of the commonly used benchmark prices for oil is West Texas Intermediate (WTI) as reported in the Wall Street Journal. Our oil price tends to move in the same direction as the WTI price, adjusted for quality and transportation costs.

Oil sales jumped by 84 percent between 2000 and 1999 due to significantly higher oil prices. Sales were $44.4 million in 2000 compared to $24.2 million in 1999. We realized an average price of $28.92 per barrel in 2000 versus an average price of $17.58 per barrel in 1999. The price difference between the two years accounted for approximately $17.4 million of the increase in oil sales. At the same time

prices were climbing, our production increased by 12 percent. We produced an average of 4,192 barrels per day in 2000 compared to 3,767 barrels per day in 1999. The production increase accounted for approximately $2.8 million of the positive sales variance. A major factor in the 2000 production increase was new wells drilled in the Mid-continent region.

Product sales from gas processing plants declined 14 percent between 2001 and 2000, and increased 58 percent between 2000 and 1999. Price was the basis for our change in plant product sales.

Our oil and gas revenues are derived from the following product mix in 2001: 34 percent oil, 65 percent gas and 1 percent plant products. This compares to the following mix for 2000: 45 percent oil, 54 percent gas, and 1 percent plant products. If you look at our total production volumes for 2001, 35 percent of our output is oil and 65 percent is gas. Production for 2000 was 40 percent oil and 60 percent gas.

Other revenues were approximately $0.2, $0.4 and $0.5 million in 2001, 2000, and 1999, respectively. For all three years, the most significant component of other revenue is income from our two gathering systems in California. The remaining other revenue, for all periods presented, includes proceeds from gas contract settlements and other miscellaneous items.

Costs and Expenses

DD&A increased 35 percent to $39.6 million in 2001 from pro forma DD&A of $29.4 million in 2000, partially due to the 13 percent increase in oil and gas production. We changed our method of computing depletion on our oil and gas properties from the future gross revenue method to the units-of-production method effective January 1, 2001. This accounting change resulted in an increase in DD&A of $7.8 million for 2001. On a unit of production basis, DD&A was $1.52 per Mcfe in 2001 versus pro forma DD&A of $1.27 per Mcfe in 2000. The increase on a per Mcf basis is primarily due to the increase in our average cost of reserves added. Increased costs from suppliers and a success rate of 60 percent on net wells drilled in 2001 compared to 65 percent in 2000 contributed to the rise in the cost of finding new proved reserves. In calculating Mcf equivalents, we use a generally recognized standard in which one barrel of oil is equal to six Mcf of gas. Management believes the units-of-production method more closely reflects our financial results by better matching depletion expense with the depletion of our reserves by removing the effect of volatile oil and gas prices, and the units of-of-production method is the predominant method used in the industry. DD&A also includes depreciation of fixed assets and amortization of financing costs associated with our credit facility.

Using the future gross revenue method and rolling average prices in 2000 and 1999, DD&A increased nearly 23 percent between 2000 and 1999. Part of the increase can be attributed to the 78 percent increase in oil and gas sales. The increase resulting from higher sales was partially offset by a decrease in the depletion rate. Our depletion rate as a percentage of oil and gas sales decreased to 34.6 percent from 50.6 percent in 1999. Higher product prices in 2000, for both oil and gas, helped to lower the depletion rate.

Based on oil and gas prices in effect on December 31, 2001, the unamortized cost of our oil and gas properties exceeded the full cost ceiling limitation from our proved oil and gas reserves. We incurred a non-cash charge to earnings of $45.1 million. We did not incur a full cost ceiling write-down in 2000 or 1999 due to higher prices in effect at those year-ends.

Lease operating expense (LOE) increased 56 percent between 2001 and 2000. Compared on a unit of production basis, expenses increased to $0.65 per Mcfe in 2001 from $0.47 per Mcfe in 2000. Some of the items impacting LOE are:1) production from drilling is growing and we are paying expenses on more wells, 2) when commodity prices were high in the first half of 2001, it became economical to do more workovers to further enhance production, 3) higher prices at January 1, 2001 increased property values and, as a result, ad valorem taxes, 4) increase in the number of properties and field personnel

due to the December 2000 merger with Columbus, and 5) there are upward cost pressures resulting from heightened competition.

LOE increased 28 percent between 2000 and 1999. On a unit of production basis, LOE climbed to $0.47 per Mcfe in 2000 from $0.38 per Mcfe in 1999. During the last half of 2000 when commodity prices were high, we performed more workovers to increase production and vendors, due to heightened demand for services, raised their prices.

Production taxes increased to $6.9 million in 2001 from $3.7 million in 2000 and $3.2 million in 1999. The tax for 2001 is a little over 6.3 percent of oil and gas sales, or $0.26 per Mcfe. This compares to 3.8 percent and $0.16 per Mcfe, and 5.7 percent and $0.14 per Mcfe in 2000 and 1999, respectively. The rise in production taxes for the year was a result of the nine percent increase in oil and gas revenues and the 13 percent increase in production which can effect volume-based taxes. Also, as an outgrowth of the Columbus merger, a greater proportion of our gas sales are from properties in Texas, where the production/severance tax rate is higher than our previous blended average.

General and administrative expense (G&A) increased to $4.6 million in 2001 from $3.3 million in 2000. On a unit basis, G&A increased to $0.17 per Mcfe in 2001 from $0.14 per Mcfe in 2000. Most of the variance is due to higher employee compensation and benefit expense, various consulting fees, and expenses related to the proposed merger. Employee count increased from 70 at December 31, 2000 to 97 at December 31, 2001, primarily owing to the December 2000 acquisition of Columbus and replacing contract field labor with new employees in the Mid-Continent region.

G&A increased to $3.3 million in 2000 from $2.6 million in 1999. On a unit basis, G&A increased to $0.14 per Mcfe in 2000 from $0.11 per Mcfe in 1999. Most of the variance was due to higher employee compensation and benefit expense and miscellaneous costs related to our acquisition of Columbus. During the first quarter of 2001, we began to add staff and make preparations for integrating the Columbus properties. While these expenses were related to the acquisition, they were not direct costs and therefore were not capitalized.

As prescribed by full cost accounting rules, we capitalized direct overhead related to exploration and development activities of $6.4, $5.0, and $4.6 million in 2001, 2000 and 1999, respectively.

Interest expense before capitalization was $2.0, $4.3, and $4.1 million for the years 2001, 2000, and 1999, respectively. We capitalized interest of $1.1, $1.7, and $1.4 million for those same periods. These capitalized amounts are for borrowings associated with undeveloped leasehold. Our interest expense is lower in 2001 from 2000 due to a decrease in interest rates and $10 million less debt. At December 31, 2001 our average interest rate was 2.92 percent. A year ago, the average interest rate was 7.65 percent. Even though our debt balance decreased $16 million between December 31, 2000 and December 31, 1999, our interest expense was higher in 2000 due to an increase in interest rates and most of the debt was paid down in the second half of 2000.

Cash Flow and Liquidity

We primarily need cash to fund oil and gas exploration, development, and acquisition activities and to pay existing obligations and trade commitments related to oil and gas operations. Our primary sources of liquidity are cash flows from operating activities and proceeds from financing activities. The prices we receive for future oil and natural gas production and the level of production will significantly impact future cash flows from operating activities. No prediction can be made as to the prices we will receive for our future oil and gas production.

We generated cash from operating activities of $83.5 million in 2001. This is 18 percent greater than the $70.9 million reported for 2000, and more than double the $35.5 million reported in 1999. Most of the 2001 increase was a consequence of higher gas production and high gas prices in the first half of 2001, and the resulting increase in gas sales.

Cash expenditures for exploration and development (E&D) in 2001 totaled $75.1 million, or 90 percent of cash from operating activities. We participated in drilling 114 gross wells, with an overall success rate of 75 percent. On a net basis, 24.7 of the 41.5 wells drilled were successful. We concentrated our drilling efforts in the Mid-Continent region, principally the Anadarko Basin, California and the Mississippi Salt Basin.

Our 2001 E&D expenditures were $16.9 million more than the $58.2 million spent in 2000, and $42.3 million more than the $32.8 million spent in 1999. We drilled 105 gross wells (40.0 net) in 2000 and 104 gross wells (38.3 net) in1999. While we did not significantly increase the gross number of wells we drilled, we took a larger interest in the drilling projects we selected.

In 2001 and 1999, we acquired additional interests in producing properties we already operated in the Hardeman Basin and properties in the Gulf Coast region. The transactions were funded with cash from operating activities.

As discussed in Note 1, we completed a merger with Columbus Energy Corp. (Columbus) during December 2000. In this transaction, Columbus became a wholly-owned subsidiary of Key. Our consolidated balance sheet includes the assets and liabilities, as well as the adjustments required to record the acquisition in accordance with purchase accounting. At the closing date, Columbus had $1,058,000 in cash and cash equivalents. During the months leading up to the merger, we incurred approximately $250,000 of costs directly related to the transaction.

We received proceeds totaling $0.1 million, $0.3 million, and $2.1 million in 2001, 2000, and 1999, respectively, for the sale of miscellaneous producing properties and non-producing acreage.

Using cash from operating activities and proceeds from the issuance of common stock associated with the exercise of stock options, we paid down $10 million of our debt balance in 2001. Although not reflected in our statement of cash flows, in 2000, we assumed $2.2 million of long-term debt in our merger with Columbus. The $2.2 million of Columbus debt is included in the $18.2 million we paid in 2000. We started and finished 1999 with a long-term debt balance of $60.0 million. During 1999, proceeds from borrowings were used to finance exploration and drilling activities. These borrowings were subsequently repaid with cash from operating activities.

We received cash proceeds of $1.1 million and $5.5 million from the issuance of common stock in 2001 and 2000, respectively. Shares of Key common stock were issued in connection with the exercise of stock options granted to officers and directors between 1992 and 1999. The options exercised had exercise prices ranging from $2.50 to $12.00 per share.

In 2000, our chief executive officer (Mr. Merelli) exercised options to purchase 500,000 shares of common stock. The options were granted in 1992 in connection with his employment contract. These options had an exercise price of $3.00. We received proceeds valued at $1.5 million from Mr. Merelli for the exercise price of the options. The proceeds were a combination of cash and 70,000 shares of Key common stock valued at the then market price. We issued 370,000 shares of stock to him after withholding 130,000 shares to cover his tax withholding obligation.

We believe that cash on hand, net cash generated from operations and amounts available under our existing line of credit will be adequate to meet future liquidity needs, including satisfying our

financial obligations and funding our operations and exploration and development activities. At December 31, 2001, we had contractual obligations and material commitments as follows:

				Payment Due
		Total		2002		2003		2004		2005 and Thereafter
Bank debt		$	34,000	$	4,857	$	9,714	$	9,714	$	9,715
Operating leases			3,856		733		615		618		1,890
Drilling commitments			1,836		1,836		—		—		—

	Total obligations	$	39,692	$	7,426	$	10,329	$	10,332	$	11,605

We have a long-term credit agreement with a group of banks led by Banc of America Securities LLC. The agreement specifies a maximum loan amount of $150 million and had an aggregate borrowing base of $110 million at the end of 2001. The lenders may periodically re-determine the borrowing base depending upon the value of our oil and gas properties. If the re-determined borrowing base falls below the outstanding loan amount, the banks may request repayment of the excess amount. At December 31, 2001, we had $34 million outstanding and $76 million unused and available on the credit facility.

The agreement has a maturity date of January 1, 2006, including a revolving period that ends on July 1, 2002. If not amended before then, the outstanding loan amount converts to a term loan and we must commence quarterly principal payments. As such, we have classified a portion of the loan as current on our balance sheet. We are currently discussing a new credit facility with several banks but there is no guarantee a new credit facility will be completed prior to the current facility converting to a term loan.

The operating leases represent lease commitments for office space with varying expiration dates. The drilling commitment represent commitments on oil and gas wells approved for drilling or in the process of being drilled at December 31, 2001. All of these commitments were routine and were made in the normal course of our business.

Critical Accounting Policies

We rely on estimates and assumptions made by our management to prepare our financial statements in conformity with accounting principles generally accepted in the United States of America. Those estimates and assumptions affect the reported amounts of assets and liabilities and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Significant estimates with regard to our consolidated financial statements include the estimate of proved oil and gas reserve volumes and the related present value of estimated future net cash flows. Proved oil and gas reserve quantities are based on estimates prepared by Key's engineers in accordance with guidelines established by the SEC, and are audited by Ryder Scott Company, L.P., independent petroleum engineers. Reserve engineering is a subjective process of estimating underground accumulations of natural gas and crude oil. There are numerous uncertainties inherent in estimating quantities of proved reserves, projecting future rates of production and the timing of development expenditures. Also, reserve estimates are based on economic and operating conditions existing at December 31, including generally requiring pricing future oil and gas production at the unescalated oil and gas prices in effect at December 31. Future oil and gas prices may vary significantly from the prices received at December 31, 2001. The estimate of proved oil and gas reserve volumes and the related present value of estimated future net cash flows can effect the charge for DD&A and the reported value of our oil and gas properties, as discussed below.

We use the full cost method of accounting for our investment in oil and gas properties. As prescribed by full cost accounting rules, we capitalize all costs associated with property acquisition, exploration, and development activities. Our exploration and development costs include dry hole costs, geological and geophysical costs, direct overhead related to exploration and development activities and other costs incurred for the purpose of finding oil and gas reserves. We also capitalize salaries and benefits paid to employees directly involved in the exploration and development of oil and gas properties as well as other internal costs that can be specifically identified with acquisition, exploration and development activities.

Our rate of recording DD&A is dependent upon our estimate of proved reserves. If the estimates of proved reserves decline, the rate at which we record DD&A increases, reducing net income. Such a decline may result from lower market prices, which may make it non-economic to drill for and produce higher cost wells.

In accordance with full cost accounting rules, we are subject to a limitation on the capitalized costs of our oil and gas properties. Under these rules, capitalized costs of proved oil and gas properties, net of accumulated DD&A and deferred income taxes, may not exceed the present value of estimated future net cash flows from proved oil and gas reserves, discounted at 10 percent, plus the lower of cost or fair value of unproved properties, as adjusted for related tax effects and deferred tax revenues (the "full cost ceiling limitation"). These rules generally require pricing future oil and gas production at the unescalated oil and gas prices in effect at the end of each fiscal quarter and require a write-down if the "ceiling" is exceeded. A full cost ceiling write-down is a non-cash charge to earnings. Moreover, the expense may not be reversed in future periods, even if higher oil and gas prices subsequently increase the full cost ceiling limitation.

Based on oil and gas prices in effect on December 31, 2001, the unamortized cost of our oil and gas properties exceeded the full cost ceiling limitation from our proved oil and gas reserves. We incurred a charge to earnings of $45.1 million, $27.8 million net of income taxes.

Our results of operations are also highly dependent upon the prices we receive for natural gas and crude oil production, and those prices have been volatile and unpredictable in response to changing market forces. Nearly all of our revenue is from the sale of gas and oil, so these fluctuations, positive and negative, can have a significant impact. If we wanted to attempt to smooth out the effect of commodity price fluctuations, we could enter into various derivative or off-balance sheet arrangements, such as non-speculative hedge arrangements, commodity swap agreements, forward sale contracts, commodity futures, options, and other similar agreements relating to natural gas and crude oil. To date, we have not used any of these financial instruments or arrangements to mitigate commodity price changes. If we decided to use derivative arrangements in the future, it could have a significant impact, positive or negative, on our results of operations and cash flows.

Recent Accounting Pronouncements

In July 2001, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standard (SFAS) No. 141, Business Combinations. SFAS No. 141 requires that the purchase method of accounting be used for all business combinations initiated after June 30, 2001 and eliminates the pooling-of-interests method. The adoption of this standard does not impact our current consolidated financial statements.

In July 2001, the FASB issued SFAS No. 142, Goodwill and Other Intangible Assets, which is effective January 1, 2002. SFAS No. 142 requires that goodwill and other intangible assets with indefinite useful lives no longer be amortized, but instead tested for impairment at least annually. The adoption of this standard will not have an impact on our consolidated financial position and results of operations.

In August 2001, the FASB issued SFAS No. 143, Accounting for Asset Retirement Obligations, which is effective for fiscal years beginning after June 15, 2002. SFAS No. 143 requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. Management is currently assessing the impact of this statement on our consolidated financial position and results of operations.

In August 2001, the FASB issued SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, which is effective for fiscal years beginning after December 15, 2001. SFAS No. 144 establishes one accounting model to be used for long-lived assets to be disposed of by sale and broadens the presentation of discontinued operations to include more disposal transactions. We do not believe that adoptions of SFAS No. 144 will have an impact on our consolidated financial position or results of operations.

Future Trends

Our primary goals are to increase shareholder value and grow the company profitably. Just as we have done in the past, we will try to position ourselves to weather all market conditions. Our strategy is to increase our oil and gas reserves and production through our exploration and development efforts and to supplement this growth with acquisitions or mergers that meet our economic criteria.

In the current price environment, we anticipate exploration and development expenditures of $55 to $60 million in 2002 and that the risk profile of the wells drilled will be similar to our historical drilling program. The amount and allocation of our future capital expenditures will depend on a number of factors, including the impact of oil and gas prices on investment opportunities and available cash flow, the availability of debt and equity capital, the rate at which we can evaluate potential drilling projects, and the number and size of attractive opportunities. It is also expected that over 60 percent of planned 2002 expenditures will occur in the second half of the year and, as such, the level of budgeted expenditures may be modified. We plan to fund these expenditures with cash provided by operating activities, supplemented by borrowings under our bank line of credit.

The Merger Agreement has been approved by the respective Boards of Directors of Key and H&P. The Spin-off is subject to, among other things, receipt of a ruling from the Internal Revenue Service to the effect that the Spin-off is tax-free. The Merger is subject to, among other things, the completion of the Spin-off, the approval of the stockholders of Key, and the receipt of opinions of counsel of each of Key and H&P to the effect that the Merger is tax-free. It is currently anticipated that the Merger will occur in the third calendar quarter of 2002.

Because H&P shareholders will own a majority of the shares of Cimarex after the merger, it is anticipated that the surviving accounting entity for financial reporting purposes will be H&P's Oil and Gas Division and the merger will be accounted for as a purchase of Key by H&P's Oil and Gas Division. Although not a condition to the merger, it is also expected the combined entity will seek to change its method of accounting for oil and gas properties to "full cost" from the "successful efforts" method currently utilized by H&P. Cimarex also plans to change to a fiscal year that ends on December 31 versus the September 30 year-end presently used by H&P.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Price Fluctuations

Our results of operations are highly dependent upon the prices we receive for natural gas and crude oil production, and those prices are constantly changing in response to market forces. Nearly all of our revenue is from the sale of gas and oil, so these fluctuations, positive and negative, can have a significant impact.

Gas and oil price realizations for 2001 ranged from a monthly low of $1.65 per Mcf and $17.19 per Bbl, and a monthly high of $10.21 per Mcf and $28.03 per Bbl, respectively. It is impossible to predict future oil and gas prices with any degree of certainty.

Any sustained weakness in gas and oil prices may affect our financial condition and results of operations, and may also reduce the amount of net gas and oil reserves that we can produce economically. Any reduction in reserves, including reductions due to price fluctuations, can have an adverse effect on our ability to obtain capital for our exploration and development activities and could cause us to record a reduction in the carrying value of our oil and gas properties. If gas and oil prices were to drop 10 percent from the prices they were at December 31, 2001 and volumes remained the same as 2001, our gas and oil sales would decrease to approximately $63.0 million for the year ended December 31, 2002.

If we wanted to attempt to smooth out the effect of commodity price fluctuations, we could enter into non-speculative hedge arrangements, commodity swap agreements, forward sale contracts, commodity futures, options, and other similar agreements relating to natural gas and crude oil. To date, we have not used any of these financial instruments to mitigate commodity price changes.

Interest Rate Risk

Our reported earnings are impacted by changes in interest rates. Any fluctuation in the rate will directly affect the amount of interest expense we report. At December 31, 2001, we had $34 million of debt outstanding at an average interest rate of 2.92 percent. At our election, our interest charges are based on either the prime rate or the LIBOR rate plus a margin predetermined by our debt agreement. Assuming there is no change in the balance outstanding during 2002, a ten percent change

in the average interest rate would impact annual interest expense by approximately $99,000. As the interest rate is variable and is reflective of current market conditions, the carrying value of our long-term debt approximates its fair value.

CAUTIONARY STATEMENT PURSUANT TO SAFE HARBOR PROVISION OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995

This report contains "forward-looking statements" within the meaning of the federal securities law. These forward-looking statements include, among others, statements concerning the consummation of the proposed merger, its effect on future earnings, cash flow, or other operating results, the expected closing date of the merger, the tax treatment of the proposed merger, the Company's outlook with regard to production levels, price realizations, expenditures for exploration and development, plans for funding operations and capital expenditures, and other statements of expectations, beliefs, future plans and strategies, anticipated events or trends, and similar expressions concerning matters that are not historical facts. The forward-looking statements in this report are subject to risks and uncertainties that could cause actual results to differ materially from those expressed in or implied by the statements.

These risks and uncertainties include, but are not limited to, fluctuations in the price the Company receives for its oil and gas production, reductions in the quantity of oil and gas sold due to decreased industry-wide demand and/or curtailments in production from specific properties due to mechanical, marketing or other problems, operating and capital expenditures that are either significantly higher or lower than anticipated because the actual cost of identified projects varied from original estimates and/or from the number of exploration and development opportunities being greater or fewer than currently anticipated, and increased financing costs due to a significant increase in interest rates. These and other risks and uncertainties affecting the Company are discussed in greater detail in this report and in other filings by the Company with the Securities and Exchange Commission.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

KEY PRODUCTION COMPANY, INC.

INDEX TO FINANCIAL STATEMENTS AND SUPPLEMENTAL SCHEDULES

		Page
Independent Auditors' Report for the years ended December 31, 2001 and 2000		23
Report of Independent Auditors for the year ended December 31, 1999		24
Consolidated statements of operations for the years ended December 31, 2001, 2000, and 1999.		25
Consolidated statements of cash flows for the years ended December 31, 2001, 2000, and 1999.		26
Consolidated balance sheets as of December 31, 2001 and 2000.		27
Consolidated statements of stockholders' equity for the years ended December 31, 2001, 2000, and 1999		28
Summary of significant accounting policies		29
Notes to consolidated financial statements		32
Supplemental oil and gas disclosures		41
Supplemental quarterly financial data		44

All other supplemental information and schedules have been omitted because they are not applicable or the information required is shown in the consolidated financial statements or related notes thereto.

Independent Auditors' Report

The Board of Directors
Key Production Company, Inc.:

We have audited the accompanying consolidated balance sheets of Key Production Company Inc. and subsidiaries as of December 31, 2001 and 2000 and the related consolidated statements of operations, stockholders' equity, and cash flows for the years ended December 31, 2001 and 2000. These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audit in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Key Production Company, Inc. and subsidiaries as of December 31, 2001 and 2000, and the results of its operations and its cash flows for the years then ended, in conformity with accounting principles generally accepted in the United States of America.

As discussed in the summary of significant accounting policies to the financial statements, the Company changed its method of computing depletion in 2001 from the future gross revenue method to the units-of-production method.

We also audited the adjustments which were applied to present the pro forma earnings and earnings per share for 2000 and 1999 that give pro forma effect to the retroactive application of the units-of-production method of accounting for depletion. In our opinion, such adjustments are appropriate and have been properly applied.

KPMG LLP

Denver, Colorado
March 6, 2002

REPORT OF INDEPENDENT AUDITORS

To the Stockholders and Board of Directors of Key Production Company, Inc.:

We have audited the accompanying consolidated statements of operations, stockholders' equity and cash flows of Key Production Company, Inc. (a Delaware corporation) and subsidiaries for the year ended December 31, 1999, except for the pro forma amounts of net income and net income per basic and diluted share presented in the December 31, 1999 consolidated statement of operations that give pro forma effect to the retroactive application of the units-of-production method of accounting for depreciation, depletion and amortization. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audit in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the results of operations and cash flows of Key Production Company, Inc. and subsidiaries for the year ended December 31, 1999, in conformity with accounting principles generally accepted in the United States.

ARTHUR ANDERSEN LLP

Denver, Colorado,
February 24, 2000.

KEY PRODUCTION COMPANY, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

				For the Year Ended December 31,
				2001			2000			1999
				(In Thousands, Except Per Share Data)
Revenues:
	Natural gas sales			$	70,815		$	53,656		$	30,779
	Oil sales				36,699			44,379			24,177
	Plant product sales				1,143			1,333			842
	Other				228			452			460

					108,885			99,820			56,258

Expenses:
	Depreciation, depletion and amortization				39,612			35,204			28,672
	Reduction to carrying value of oil and gas properties				45,140			—			—
	Lease operating				16,823			10,756			8,391
	Production taxes				6,872			3,735			3,183
	General and administrative				4,579			3,324			2,550
	Financing costs:
		Interest expense			2,005			4,311			4,081
		Capitalized interest			(1,148	)		(1,712	)		(1,397	)
		Interest income			(168	)		(234	)		(197	)

					113,715			55,384			45,283

Income (loss) before income tax expense (benefit)					(4,830	)		44,436			10,975
Provision (benefit) for income tax expense (benefit)					(1,213	)		16,441			4,171

Income (loss) before cumulative effect of change in accounting method					(3,617	)		27,995			6,804
Cumulative effect of change in accounting method, net of income tax benefit of $1,143,000					(1,825	)		—			—

			Net income (loss)	$	(5,442	)	$	27,995		$	6,804

Earnings (loss) per share:
	Basic:
		Income (loss) before cumulative effect of change in accounting method		$	(0.26	)	$	2.32		$	0.59
		Cumulative effect of change in accounting method, net of income taxes			(0.13	)		—			—

			Net income (loss)	$	(0.39	)	$	2.32		$	0.59

	Diluted:
		Income (loss) before cumulative effect of change in accounting method		$	(0.26	)	$	2.23		$	0.56
		Cumulative effect of change in accounting method, net of income taxes			(0.13	)		—			—

			Net income (loss)	$	(0.39	)	$	2.23		$	0.56

Pro forma amounts assuming the new method of depletion is applied retroactively:
	Net income						$	31,662		$	10,444

	Net income per common share:
		Basic					$	2.62		$	0.91

		Diluted					$	2.52		$	0.86

Weighted average common shares outstanding					13,974			12,075			11,537

Weighted average diluted shares outstanding					13,974			12,537			12,111

The accompanying Summary of Significant Accounting Policies
and Notes to Consolidated Financial Statements
are an integral part of these statements.

KEY PRODUCTION COMPANY, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

				For the Year Ended December 31,
				2001			2000			1999
				(In Thousands)
Cash Flows from Operating Activities:
	Net income (loss)			$	(5,442	)	$	27,995		$	6,804
	Adjustments to reconcile net income (loss) to net cash provided by operating activities:
		Depreciation, depletion and amortization			39,612			35,204			28,672
		Reduction to carrying value of oil and gas properties			45,140			—			—
		Cumulative effect of change in accounting method			2,968			—			—
		Deferred income taxes			(2,849	)		9,881			3,732
		Common stock issued as compensation			137			181			236
		Amortization of unearned compensation			160			—			—
		Income tax benefit related to stock options exercised			429			4,783			—
	Changes in operating assets and liabilities:
		(Increase) decrease in receivables			11,671			(8,900	)		(4,228	)
		Increase in prepaid expenses and other			(591	)		(295	)		(654	)
		Increase (decrease) in accounts payable and accrued expenses			(7,817	)		2,166			1,443
		Increase (decrease) in other liabilities			39			(103	)		(545	)

			Net cash provided by operating activities		83,457			70,912			35,460

Cash Flows from Investing Activities:
	Oil and gas exploration and development expenditures				(75,109	)		(58,208	)		(32,800	)
	Acquisition of oil and gas properties				(745	)		(55	)		(2,877	)
	Cash received in connection with acquisition				—			1,058			—
	Cash costs of acquisition				—			(250	)		—
	Proceeds from sale of oil and gas properties				69			341			2,114
	Other capital expenditures				(522	)		(422	)		(685	)

			Net cash used by investing activities		(76,307	)		(57,536	)		(34,248	)

Cash Flows from Financing Activities:
	Long-term borrowings				5,000			—			7,000
	Payments on long-term debt				(15,000	)		(18,200	)		(7,000	)
	Payments to acquire treasury stock				(11	)		(36	)		(3	)
	Proceeds from issuance of common stock				1,118			5,519			158

			Net cash provided (used) by financing activities		(8,893	)		(12,717	)		155

Net Increase (Decrease) in Cash and Cash Equivalents					(1,743	)		659			1,367
Cash and Cash Equivalents at Beginning of Year					6,746			6,087			4,720

Cash and Cash Equivalents at End of Year				$	5,003		$	6,746		$	6,087

The accompanying Summary of Significant Accounting Policies
and Notes to Consolidated Financial Statements
are an integral part of these statements.

KEY PRODUCTION COMPANY, INC.

CONSOLIDATED BALANCE SHEETS

			December 31,
			2001			2000
			(In Thousands, Except Share Data)
ASSETS
Current Assets:
	Cash and cash equivalents		$	5,003		$	6,746
	Receivables			13,357			25,028
	Prepaid expenses and other			2,163			1,572

				20,523			33,346

	Oil and Gas Properties, on the basis of full cost accounting:
		Proved properties		390,794			307,882
		Unproved properties and properties under development, not being amortized		11,961			21,284

				402,755			329,166
		Less—accumulated depreciation, depletion and amortization		(207,139	)		(120,337	)

				195,616			208,829

Other Assets, net				1,529			1,979

			$	217,668		$	244,154

LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
	Accounts payable		$	13,210		$	16,963
	Accrued exploration and development			2,478			4,726
	Accrued lease operating expense and other			467			4,282
	Current portion of long-term debt			4,857			—

				21,012			25,971

Long-Term Debt				29,143			44,000

Deferred Income Taxes				32,699			35,548

Other Liabilities				587			548

Commitments and Contingencies (Notes 6 and 7)
Stockholders' Equity:
	Common stock, $.25 par value, 50,000,000 shares authorized; 14,041,269 and 14,223,775 shares issued, respectively			3,510			3,556
	Paid-in capital			69,924			71,122
	Unearned compensation			(278	)		—
	Retained earnings			61,071			66,513
	Treasury stock at cost, 303,138 shares in 2000			—			(3,104	)

				134,227			138,087

			$	217,668		$	244,154

The accompanying Summary of Significant Accounting Policies
and Notes to Consolidated Financial Statements
are an integral part of these statements.

KEY PRODUCTION COMPANY, INC.

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY

		Shares of Common Stock Outstanding		Common Stock			Paid-in Capital			Unearned Compensation			Retained Earnings			Treasury Stock			Total Stockholders' Equity
		(In Thousands)
Balance, December 31, 1998		11,518		$	2,945		$	37,406		$	—		$	31,737		$	(2,407	)	$	69,681
	Net income	—			—			—			—			6,804			—			6,804
	Common stock issued for option exercises	42			10			144			—			—			—			154
	Common stock issued as compensation	27			—			7			—			(23	)		252			236
	Common stock reacquired	—			—			—			—						(2	)		(2	)

Balance, December 31, 1999		11,587			2,955			37,557			—			38,518			(2,157	)		76,873
	Net income	—			—			—			—			27,995			—			27,995
	Common stock and stock options issued for Columbus acquisition	1,363			341			24,787			—			—			—			25,128
	Common stock issued for option exercises	1,210			302			6,190			—			—			—			6,492
	Income tax benefit from stock options exercised	—			—			4,783			—			—			—			4,783
	Common stock issued as compensation	12			—			64			—			—			117			181
	Common stock reacquired	(251	)		(42	)		(2,259	)		—			—			(1,064	)		(3,365	)

Balance, December 31, 2000		13,921			3,556			71,122			—			66,513			(3,104	)		138,087
	Net loss	—			—			—			—			(5,442	)		—			(5,442	)
	Common stock issued for option exercises	123			31			1,410			—			—			—			1,441
	Income tax benefit from stock options exercised	—			—			429			—			—			—			429
	Common stock issued as compensation	22			—			16			—			—			62			78
	Common stock reacquired	(25	)		(7	)		(508	)		—			—			(11	)		(526	)
	Retirement of treasury stock	—			(70	)		(2,819	)		—			—			2,889			—
	Unearned compensation related to restricted stock awards	—			—			274			(438	)		—			164			—
	Amortization of unearned compensation	—			—			—			160			—			—			160

Balance, December 31, 2001		14,041		$	3,510		$	69,924		$	(278	)	$	61,071		$	—		$	134,227

The accompanying Summary of Significant Accounting Policies
and Notes to Consolidated Financial Statements
are an integral part of these statements.

KEY PRODUCTION COMPANY, INC.

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Description of Our Business

We are an independent energy company engaged in the exploration, development, acquisition, and production of oil and gas in the continental United States. Our primary focus areas are the Anadarko Basin of Oklahoma, south Louisiana, the Mississippi Salt Basin, northern California, and the Rocky Mountain region.

Basis of Presentation

We are presenting the accounts of Key Production Company, Inc. (Key) and its subsidiaries in the accompanying consolidated financial statements. All intercompany accounts and transactions were eliminated in consolidation.

Use of Estimates

We rely on estimates and assumptions made by our management to prepare financial statements in conformity with accounting principles generally accepted in the United States of America. Those estimates and assumptions affect the reported amounts of assets and liabilities and the reported amounts of revenues and expenses during the reporting period and in the disclosures of commitments and contingencies. Actual results could differ from those estimates.

The more significant areas requiring the use of management's estimates and judgments relate to estimates of oil and gas reserves used in calculating depletion, depreciation and amortization, estimates of future net revenues used in computing the ceiling test limitations and estimates of abandonment obligations used in such calculations. Estimates and judgments are also required in determining the impairments of undeveloped properties and the valuation of deferred tax assets.

Property and Equipment

Our investment in oil and gas properties is accounted for using the full cost method. As prescribed by full cost accounting rules, all costs associated with property acquisition, exploration, and development activities are capitalized. Exploration and development costs include dry hole costs, geological and geophysical costs, direct overhead related to exploration and development activities and other costs incurred for the purpose of finding oil and gas reserves. Salaries and benefits paid to employees directly involved in the exploration and development of oil and gas properties as well as other internal costs that can be specifically identified with acquisition, exploration, and development activities are also capitalized.

In accordance with full cost accounting rules, we are subject to a limitation on capitalized costs. The capitalized cost of oil and gas properties, net of accumulated DD&A may not exceed the estimated future net cash flows from proved oil and gas reserves discounted at 10 percent, plus the lower of cost or fair market value of unproved properties as adjusted for related tax effects (the "full cost ceiling test limitation"). If capitalized costs exceed this limit, the excess must be charged to expense.

Based on oil and gas prices in effect on December 31, 2001, the unamortized cost of our oil and gas properties exceeded the ceiling from our proved oil and gas reserves and we incurred a charge to earnings of $45.1 million, or $27.8 million net of income taxes.

The costs of certain unevaluated leasehold acreage and wells being drilled are not being amortized. On a quarterly basis, we assess costs not being amortized for possible impairments or reductions in value. If a reduction in value has occurred, the portion of the carrying cost in excess of the current value is included in the costs subject to amortization.

Interest expense related to undeveloped properties is also capitalized. Interest capitalized was $1.1 million, $1.7 million, and $1.4 million in 2001, 2000, and 1999, respectively.

Office furniture and equipment are recorded at cost and depreciated on a straight line basis over the estimated useful lives of the assets, which range from three to 10 years.

Revenue Recognition

We use the sales method of accounting for natural gas revenues. Under this method, revenue recognition is based on actual volumes of gas sold to purchasers. The volumes of gas sold may differ from the volumes to which Key is entitled based on its interests in the properties. Differences between volumes sold and entitlement volumes create gas imbalances. These imbalances are reflected as adjustments to reported gas reserves and future cash flows in our supplemental oil and gas disclosures. Adjustments for gas imbalances reduced Key's proved gas reserves by approximately four percent as of December 31, 2001. Revenue is deferred and a liability recorded for those properties where the estimated remaining reserves will not be sufficient to enable the under-produced owners to recoup their entitled share through production. We recognize revenue from oil based on actual volumes sold to purchasers.

Net Income (Loss) Per Share

We compute basic net income (loss) per share by dividing income (loss) attributable to common stock by the weighted average number of common shares outstanding for the period. Diluted net income (loss) per common share reflects the potential dilution that could occur if potential common stock (stock options) are assumed to have been exercised. We use the treasury stock method to determine the number of shares converted. Calculations of net income (loss) per common share are disclosed in Note 9.

Cash and Cash Equivalents

We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents. These investments earned an average of 1.2 and 6.0 percent rates of interest at December 31, 2001 and 2000, respectively, with cost approximating market.

Financial Instruments

Our financial investments consist of cash, trade receivables, trade payables and current and long-term debt. The carrying value of cash and cash equivalents, trade receivables, and trade payables are considered to be representative of their fair market value, due to the short maturity of these

instruments. The carrying value of debt approximates fair value because the debt carries a variable interest rate which is reset periodically.

Income Taxes

We utilize the asset and liability method to account for income taxes. A deferred tax liability or asset is determined based on the temporary differences between the financial reporting basis and tax basis of assets and liabilities as measured by the enacted tax rates. A valuation allowance is established for any portion of a deferred tax asset for which it is more likely than not that a tax benefit will not be realized.

General and Administrative Expense

General and administrative expenses are reported net of amounts billed to the working interest owners of Key-operated oil and gas properties, and net of amounts capitalized pursuant to full cost accounting rules. We capitalized costs of $6.4, $5.0, and $4.6 million in 2001, 2000, and 1999, respectively.

Derivatives and Related Activities

We have never used derivative arrangements or other financial instruments to mitigate changes in market-based commodity prices or interest rates. As a result, adoption of Statement of Financial Accounting Standards (SFAS) No. 133, Accounting for Derivative Instruments and Hedging Activities, effective January 1, 2001, had no impact on our financial statements.

Comprehensive Income

There is no difference between our net income and comprehensive income. Therefore, we are not including a comprehensive income disclosure that would be required by SFAS No. 130, Reporting Comprehensive Income.

Reclassification

We reclassified some prior year amounts to conform to the current year presentation.

Recent Accounting Pronouncements

In July 2001, the Financial Accounting Standards Board (FASB) issued SFAS No. 141, Business Combinations. SFAS No. 141 requires that the purchase method of accounting be used for all business combinations initiated after June 30, 2001 and eliminates the pooling-of-interests method. The adoption of this standard did not impact our current consolidated financial statements.

In August 2001, the FASB issued SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, which is effective for fiscal years beginning after December 15, 2001. SFAS No. 144 establishes one accounting model to be used for long-lived assets to be disposed of by sale and broadens the presentation of discontinued operations to include more disposal transactions. We do not believe that adoption of SFAS No. 144 will have an impact on our financial position or results of operations.

KEY PRODUCTION COMPANY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. ACQUISITION OF COLUMBUS ENERGY CORP.

On December 29, 2000, we consummated a merger with Columbus Energy Corp. (Columbus). In this transaction we acquired all the outstanding common stock of Columbus in a tax-free reorganization pursuant to which Columbus became a wholly-owned subsidiary of Key. Each outstanding share of Columbus common stock was converted into 0.355 shares of Key common stock. The acquisition has been accounted for by the purchase method and, accordingly, Columbus' results of operations have been included in our consolidated statement of income from the closing date of the acquisition. Our consolidated balance sheets dated December 31, 2001 and 2000, include the assets and liabilities, as well as the adjustments required to record the acquisition in accordance with purchase accounting.

The following unaudited pro forma financial information presents the combined result of Key and Columbus, and was prepared as if the acquisition had occurred at the beginning of 1999. The pro forma data presented is based on numerous assumptions and is not necessarily indicative of future results of operations.

	For the Year Ended December 31,
	2000		1999
	(In Thousands, Except Per Share Amounts)
Revenues	$	115,028	$	66,272
Net income	$	30,300	$	6,206
Basic earnings per share	$	2.25	$	0.48
Diluted earnings per share	$	2.18	$	0.46

2. LONG-TERM DEBT

In November of 1999, we signed a long-term credit agreement with a group of banks led by Banc of America Securities LLC. The agreement provides for a maximum loan amount of $150 million, limited to a borrowing base. Our borrowing base was $110 million at the end of 2001. The lenders may periodically re-determine the borrowing base depending upon the value of our oil and gas properties. If the re-determined borrowing base falls below the outstanding loan amount, the banks may request repayment of the excess amount. We may voluntarily select a borrowing base, less than the maximum value our properties would allow, to reduce fees for unused borrowing base capacity. At December 31, 2001, we had $34 million outstanding and $76 million unused and available on the credit facility.

At our option, interest on amounts borrowed is calculated based on London Interbank Offered Rates (LIBOR) or the Base Rate. Base Rate means the higher of the Federal Funds rate plus 0.5 percent or the prime rate. The interest rate we pay is also based on the facility usage ratio (the quotient obtained by dividing the outstanding loan amount by the borrowing base). Pursuant to the terms of the loan agreement, the margin on the interest rate for LIBOR-based loans could range from 1.00-1.75 percent per annum. Similarly, the margin on Base Rate borrowings could range from 0.00-0.50 percent per annum.

The average interest rate on the outstanding debt at the end of 2001 was 2.92 percent. The loan agreement also provides for a 0.30-0.40 percent commitment fee (also based on the facility usage ratio)

on the average unused portion of the borrowing base in return for the banks' commitment to maintain the availability of those funds.

We secured this debt with oil and gas assets owned by Key and our subsidiaries. We are also subject to customary covenants and restrictions including limitations on additional borrowings, and minimum working capital, and net worth maintenance requirements. We were in compliance with the covenants of the agreement as of December 31, 2001.

Aggregate maturities of long-term debt outstanding at December 31, 2001 are as follows:

	(In Thousands)
2002	$	4,857
2003		9,714
2004		9,714
2005		9,715

	$	34,000

3. INCOME TAXES

Deferred tax assets and liabilities are comprised of the following components at December 31, 2001 and 2000:

		2001			2000
		(In Thousands)
Long-term deferred tax assets:
	Net operating loss carryforwards	$	298		$	1,095
	Percentage depletion carryforwards		971			1,991
	AMT credit carryforward		1,300			1,290
	Other		359			269

			2,928			4,645
Valuation allowance			—			(343	)

			2,928			4,302
Long-term deferred tax liabilities:
	Depreciation, depletion, and amortization		(35,627	)		(39,850	)

	Net deferred income tax liability	$	(32,699	)	$	(35,548	)

We had net tax operating loss carryforwards of approximately $851,000 at December 31, 2001, which expire in the years 2008 through 2019. These net operating losses (NOLs), acquired as part of the Columbus acquisition, are subject to annual limitations. We believe all NOLs will be utilized before they expire.

Income tax expense consisted of the following:

		For the Year Ended December 31
		2001			2000		1999
		(In Thousands)
Current taxes:
	Federal	$	199		$	971	$	—
	State		294			85		78

			493			1,056		78
Deferred federal and state taxes			(1,706	)		15,385		4,093

	Total tax provision (benefit) on income (loss)	$	(1,213	)	$	16,441	$	4,171

A reconciliation of the statutory income tax rate to the effective rate is as follows:

	2001		2000		1999
Statutory income tax rate	(35.0	)%	35.0	%	34.0	%
State income taxes, net of federal benefit	6.5		4.0		4.0
Adjustment to prior year tax return	10.4		—		—
Change in valuation allowance	(7.0	)	—		—
Other	—		(2.0	)	—

	(25.1	)%	37.0	%	38.0	%

4. NON-CASH INVESTING AND FINANCING ACTIVITIES

Supplemental Disclosure of Cash Flow Information

		For the Year Ended December 31,
		2001		2000		1999
		(In Thousands)
Cash paid during the year for:
	Interest (net of amounts capitalized)	$	907	$	2,547	$	2,703
	Income taxes (net of refunds received)	$	4,386	$	221	$	78

Noncash Transactions

Also in 2001 and 2000, officers and directors of Key and former Columbus employees exercised 123,073 and 1,210,166 non-qualified stock options, respectively. In connection with these transactions, we received total proceeds of $1.4 million and $6.5 million, respectively. Approximately $1.1 million and $5.5 million, respectively, of the proceeds was cash and the balance of the proceeds was noncash. The noncash portion was in the form of mature (held longer than six months) Key common stock, which was recorded as treasury stock at its market value of $0.3 and $1.0 million, respectively. In connection with the exercise of these stock options, we issued 108,768 and 1,040,966 shares of stock after withholding 14,305 and 169,200 shares valued at $0.3 and $2.3 million, respectively, to cover the tax withholding obligations. The shares withheld are reflected in common stock reacquired and do not have an impact on cash flows from financing activities.

5. STOCK OPTIONS

The Key Production Company, Inc. 2001 Equity Incentive Plan reserves 1,000,000 shares of common stock for issuance to employees of Key and consultants of Key. No options have been granted under this plan.

The Key Production Company, Inc. 1992 Stock Option Plan reserves 2,000,000 shares of common stock for issuance to the Company's officers and employees. A total of 689,667 options were outstanding at December 31, 2001. The options expire at various dates through 2010 and are at prices ranging from $9.69 to $13.31 per share.

The Key Production Company, Inc. Stock Option Plan for Non-Employee Directors reserves 360,000 shares of common stock for issuance to the Company's non-employee directors. There were 139,167 options outstanding at December 31, 2001. These options were granted at exercise prices ranging from $2.88 to $18.77 and expire at various dates through 2008.

Our chief executive officer exercised options to purchase 500,000 shares in May of 2000. These options were granted in 1992 in accordance with the terms of his employment agreement at an exercise price of $3.00.

In connection with the Columbus merger, we reserved 214,000 shares of common stock for issuance to former Columbus stock option holders. Each option that was outstanding immediately prior to the merger was converted into a fully vested option to purchase 0.355 shares of Key common stock for each Columbus share covered by the option. We issued 179,011 options to purchase Key common stock, of which 34,073 were exercised and the remainder expired at the end of 2001.

All options granted had an exercise price equal to or above the market price on the date of grant. Subject to accelerated vesting under certain circumstances such as death of the employee or change in control of the Company, one-third of the options vest in each of the three years following the date of grant.

The following table summarizes the changes in stock options for the year, the number of common shares available for grant and the number of outstanding options vested at year end.

	2001
	Number of Options		Weighted- Average Exercise Price
Outstanding at beginning of year	1,051,845		$	11.86
Granted	45,000		$	18.77
Exercised	(123,073	)	$	11.58
Forfeited	(144,938	)	$	19.01

Outstanding at end of year	828,834		$	10.99

Exercisable at end of year	537,167		$	10.37

Available for grant at end of year	1,891,438

	2000
	Number of Options		Weighted- Average Exercise Price
Outstanding at beginning of year	1,958,000		$	7.11
Granted	125,000		$	13.31
Exercised	(1,210,166	)	$	5.36
Issued in Columbus merger	179,011		$	18.69

Outstanding at end of year	1,051,845		$	11.86

Exercisable at end of year	586,845		$	12.75

Available for grant at end of year	791,500

	1999
	Number of Options		Weighted- Average Exercise Price
Outstanding at beginning of year	1,540,000		$	6.30
Granted	490,000		$	9.69
Exercised	(42,000	)	$	3.76
Forfeited	(30,000	)	$	11.38

Outstanding at end of year	1,958,000		$	7.11

Exercisable at end of year	1,269,666		$	5.45

Available for grant at end of year	702,500

The following table summarizes information about the stock options outstanding at December 31, 2001.

				Options Outstanding			Options Exercisable
Year Granted	Range of Exercise Prices		Number Outstanding	Weighted Average Remaining Contractual Life	Weighted Average Exercise Price		Number Exercisable	Weighted Average Exercise Price
1992	$	2.88	45,000	1.0 years	$	2.88	45,000	$	2.88
1997	$	11.38	272,500	5.8 years	$	11.38	272,500	$	11.38
1998	$	12.00	26,667	6.4 years	$	12.00	26,667	$	12.00
1999	$	9.69	314,667	7.7 years	$	9.69	151,333	$	9.69
2000	$	13.31	125,000	8.4 years	$	13.31	41,667	$	13.31
2001	$	18.77	45,000	9.3 years	$	18.77	—	$	—

			828,834	6.9 years	$	10.99	537,167	$	10.37

SFAS No. 123, Accounting for Stock-Based Compensation, establishes a fair value method of accounting for stock-based compensation plans either through recognition or disclosure. SFAS No. 123 allows the continued measurement of compensation cost for such plans using the intrinsic value based method prescribed by APB Opinion No. 25, Accounting for Stock Issued to Employees (APB No. 25), provided that pro forma results of operations are disclosed for those options granted. We account for our stock-based compensation plans under APB No. 25, and related interpretations, under which no compensation cost has been recognized for the Stock Option Plans. If compensation costs had been

determined in accordance with SFAS No. 123, our net income (loss) and net income (loss) per common share would approximate the following pro forma amounts.

			For the Year Ended December 31,
			2001			2000		1999
			(In Thousands, Except Per Share Amounts)
Net income (loss):
	As reported		$	(5,442	)	$	27,995	$	6,804

	Pro forma		$	(6,500	)	$	27,327	$	6,025

Net income (loss) per common share:
	Basic:
		As reported	$	(0.39	)	$	2.32	$	0.59

		Pro forma	$	(0.47	)	$	2.26	$	0.52

	Diluted:
		As reported	$	(0.39	)	$	2.23	$	0.56

		Pro forma	$	(0.47	)	$	2.18	$	0.50

Assumptions used:
	Risk-free interest rate	4.7	%	6.5	%	6.3	%
	Expected weighted average lives	5 years		5 years		5 years
	Expected volatility	56	%	47	%	47	%

For purposes of pro forma disclosures, the estimated fair value of options is amortized to expense over the options' vesting period. The weighted-average fair value of each option granted is estimated on the date of grant using the Black Scholes option pricing model with the above assumptions for risk-free interest rate, expected weighted-average lives, expected volatility, and no expected dividends.

6. EMPLOYEE BENEFIT PLANS

Retirement Plan—We provide a 401(k) retirement/savings plan for all employees. Participants may contribute up to 10 percent of their compensation, and we match contributions up to 4 percent of their compensation. Our contribution is made in the form of Key common stock. Employees vest in the Company's contribution at the rate of 25 percent per year. Total expenses for our matching contribution were $0.3, $0.2, and $0.2 million in 2001, 2000, and 1999, respectively.

Deferred Compensation Plan—Effective December 1, 1993, the Company established the Key Production Company, Inc. Deferred Compensation Plan. This plan is intended to provide a mechanism whereby certain management employees of the Company may defer compensation. The Company intends for this plan to provide the eligible employees with the opportunity to defer compensation in cases where deferrals under the 401(k) plan may be limited by applicable provisions of the Internal Revenue Code of 1986, as amended.

Income Continuance Plan—Effective June 1, 1994, the Company established the Key Production Company, Inc. Income Continuance Plan. The plan provides for the continuation of salary and benefits for certain employees in the event of a change in control of the Company. Participation in the plan is open to officers and other employees meeting age, years of service and special skills criteria. The benefit provides for up to twenty-four months of salary and benefits as determined by the employee's age and years of service.

The administrative, compliance and legal costs associated with administering these plans are paid by Key. Such expenses were not significant in 2001, 2000, or 1999.

7. COMMITMENTS AND CONTINGENCIES

Lease Commitments—We have lease commitments for office space with varying expiration dates through 2007. Rental expense was approximately $0.4 million in each of the years 2001, 2000, and 1999.

As of December 31, 2001, minimum rental commitments under these leases are payable in the following years (in thousands):

2002	$	733
2003		615
2004		618
2005		630
2006		630
Thereafter		630

	$	3,856

Drilling Commitments—We have drilling commitments of $1.8 million on oil and gas wells approved for drilling or in the process of being drilled at December 31, 2001.

Litigation—We are involved in litigation claims and are subject to governmental and regulatory controls arising in the ordinary course of business. It is the opinion of our management that all claims and litigation involving the Company are not likely to have a material adverse effect on our financial position, results of operations or cash flows.

Environmental—We are not aware of any environmental claims existing as of December 31, 2001, which would have a material impact upon the Company's financial condition, results of operations, or cash flows.

8. CONCENTRATION OF CREDIT RISK

Most of our accounts receivable balances are uncollateralized and result from transactions with other companies in the oil and gas industry. This concentration of customers may impact our overall credit risk because our customers may be similarly affected by changes in economic or other conditions within the industry.

Each of the following major customers made payments representing 10 percent or more of our net share of oil and gas sales receipts:

	For the Year Ended December 31,
Purchaser	For the Year Ended December 31,
Purchaser	2001		2000		1999
Enogex Services Corporation (formerly Transok, LLC)	25	%	17	%	18	%
Duke Energy Field Services	21	%	—		—
EOTT Energy Corp	15	%	14	%	—
Plains All American (formerly Scurlock Permian Corporation)	14	%	13	%	16	%
Tosco Refining & Marketing	—		—		10	%

9. EARNINGS PER SHARE

A reconciliation of the components of basic and diluted net income (loss) per common share for the years ended December 31, 2001, 2000, and 1999 is presented in the table below:

		2001
		Income			Shares	Per share
Basic:
	Loss available to common stockholders	$	(5,442	)	13,974	$	(0.39	)

Effect of dilutive securities—Stock options			—		—

Diluted:
	Loss available to common stockholders, including assumed conversions	$	(5,442	)	13,974	$	(0.39	)

		2000
		Income		Shares	Per share
Basic:
	Income available to common stockholders	$	27,995	12,075	$	2.32

Effect of dilutive securities—Stock options			—	462

Diluted:
	Income available to common stockholders, including assumed conversions	$	27,995	12,537	$	2.23

		1999
		Income		Shares	Per share
Basic:
	Income available to common stockholders	$	6,804	11,537	$	0.59

Effect of dilutive securities—Stock options			—	574

Diluted:
	Income available to common stockholders, including assumed conversions	$	6,804	12,111	$	0.56

In 2001, potential common stock of 336,000 shares related to outstanding options were not included in the calculation of diluted earnings per share because they were considered antidilutive.

10. SUBSEQUENT EVENT

KEY PRODUCTION COMPANY, INC.

SUPPLEMENTAL OIL AND GAS DISCLOSURES

Oil and Gas Operations—The following tables contain direct revenue and cost information relating to our oil and gas exploration and production activities for the periods indicated. We have no long-term supply or purchase agreements with governments or authorities in which we act as producer. Income taxes related to our oil and gas operations are computed using the statutory tax rate for the period.

		For the Year Ended December 31
		2001			2000			1999
		(In Thousands, Except Percentages)
Oil and gas revenues from production		$	108,657		$	99,368		$	55,798

Operating costs:
	Depletion		38,694			34,347			28,238
	Reduction to carrying value of oil and gas properties		45,140			—			—
	Lease operating		16,823			10,756			8,391
	Production taxes		6,872			3,735			3,183
	Income taxes		434			18,696			6,075

			107,963			67,534			45,887

Results of operations from oil and gas producing activities		$	694		$	31,834		$	9,911

Amortization rate as a percentage of revenues			35.6	%		34.6	%		50.6	%

Amortization rate per Mcf		$	1.49		$	1.49		$	1.27

Capitalized Costs Incurred—The following table sets forth the capitalized costs incurred in our oil and gas production, exploration, and development activities.

			For the Year Ended December 31
			2001			2000			1999
			(In Thousands)
Costs incurred during the year:
	Acquisition of properties
		Proved	$	796		$	27,571		$	1,986
		Unproved		7,331			1,488			891
	Exploration			19,204			20,636			15,977
	Development			46,327			38,423			15,602

		Oil and gas expenditures		73,658			88,118			34,456
	Property sales			(69	)		(341	)		(2,114	)

			$	73,589		$	87,777		$	32,342

Costs Not Being Amortized—The following table summarizes oil and gas property costs not being amortized at December 31, 2001, by year that the costs were incurred:

2001	$	6,674
2000		2,308
1999		700
1998 and prior		2,279

	$	11,961

We expect the majority of these costs to be evaluated, and to become subject to amortization within the next three years.

Oil and Gas Reserve Information (Unaudited)—Proved oil and gas reserve quantities are based on estimates prepared by Key's engineers, in accordance with guidelines established by the Securities and Exchange Commission (SEC), and were audited by Ryder Scott Company, L.P., independent petroleum engineers. Reserve estimates are based on economic and operating conditions existing at December 31 of each year presented.

There are numerous uncertainties inherent in estimating quantities of proved reserves, projecting future rates of production and the timing of development expenditures. The following reserve data represents estimates only and should not be construed as being exact. All of our reserves are located in the continental or offshore United States.

		Gas in Million Cubic Feet									Oil in Thousands of Barrels
		2001			2000			1999			2001			2000			1999
Total proved reserves—
	Developed and undeveloped Beginning of year		98,214			79,351			82,956			9,276			9,220			7,022
	Revisions of previous estimates		(6,397	)		3,822			(1,951	)		281			(205	)		1,740
	Extensions and discoveries		16,841			19,488			10,849			1,132			1,011			1,575
	Purchases of reserves		131			9,408			1,567			63			784			258
	Production		(16,775	)		(13,855	)		(14,070	)		(1,537	)		(1,534	)		(1,375	)
	Sales of properties		(36	)		—			—			—			—			—

	End of year		91,978			98,214			79,351			9,215			9,276			9,220

Proved developed reserves—
	Beginning of year		97,564			77,048			82,337			9,268			8,916			7,012
	End of year		91,441			97,564			77,048			9,176			9,268			8,916
	Year-end price used in calculation of future net cash flows	$	2.59		$	10.45		$	2.16		$	17.30		$	24.17		$	23.68

Standardized Measure Of Future Net Cash Flows (Unaudited)—Future cash flows are based on year-end prices except in those instances where the sale of gas is covered by contract terms providing for determinable escalations. Operating costs, production and ad valorem taxes, and future development costs are based on current costs with no escalation.

The following table presents information concerning future net cash flows from the production of oil and gas reserves, net of income tax expense. Income tax expense has been computed using expected future tax rates and giving effect to permanent differences and credits, which, under current laws, relate to oil and gas producing activities. This information does not purport to present the fair market value of Key's oil and gas assets, but does present a standardized disclosure about estimated future net cash flows that will result under the assumptions used.

Discounted Future Net Cash Flows and Changes Relating to Proved Reserves at December 31,

	2001			2000			1999
	(In Thousands)
Cash inflows	$	412,154		$	1,260,864		$	403,480
Production costs		(129,263	)		(231,130	)		(116,487	)
Development costs		(4,887	)		(5,755	)		(7,005	)
Income tax expense		(58,203	)		(310,432	)		(61,117	)

Net cash flows		219,801			713,547			218,871
10% annual discount rate		(72,736	)		(258,616	)		(71,896	)

Standardized measure of discounted future net cash flows	$	147,065		$	454,931		$	146,975

Discounted future net cash flows before income taxes	$	182,881		$	638,439		$	185,204

The following are the principal sources of change in the standardized measure of discounted future net cash flows:

	For the Year Ended December 31,
	2001			2000			1999
	(In Thousands)
Sales, net of production costs	$	(84,962	)	$	(84,877	)	$	(44,224	)
Net change in prices and production costs		(441,155	)		339,123			53,947
Extensions, discoveries, and improved recovery, net of related costs		37,706			151,512			38,721
Change in future development costs		2,346			4,563			1,187
Revision of quantities		(3,632	)		11,121			11,876
Accretion of discount		63,844			18,520			11,842
Change in income taxes		147,693			(145,279	)		(24,033	)
Purchases of reserves in place		468			57,618			5,547
Sales of properties		(139	)		—			—
Change in production rates and other		(30,035	)		(44,345	)		(12,110	)

	$	(307,866	)	$	307,956		$	42,753

Impact of Pricing (Unaudited)—The estimates of cash flows and reserve quantities shown above are based on year-end oil and gas prices, except in those cases where future gas sales are covered by contracts at specified prices. Fluctuations are largely due to the seasonal pricing nature of natural gas, supply perceptions for natural gas and significant worldwide volatility in oil prices.

Under SEC rules, companies that follow full cost accounting methods are required to make quarterly "ceiling test" calculations. Under this test, capitalized costs of oil and gas properties, net of accumulated DD&A, and deferred income taxes, may not exceed the present value of estimated future net revenues from proved reserves, discounted at 10 percent, plus the lower of cost or fair market value of unproved properties, as adjusted for related tax effects and deferred tax revenues. We calculate the projected income tax effect using the "year-by-year" method for purposes of the supplemental oil and gas disclosures and use the "short-cut" method for the "ceiling test" calculation. Application of these rules during periods of relatively low oil and gas prices, even if of short-term duration, may result in write-downs. A ceiling test write-down is a non-cash charge to earnings. A write-down may not be reversed in future periods, even if higher oil and gas prices subsequently increase the full cost ceiling limitation.

UNAUDITED SUPPLEMENTAL QUARTERLY FINANCIAL DATA

Quarterly financial data for 2001 has been restated to reflect the change in accounting principle from the future gross revenue method to the units-of-production method for DD&A as if the units-of-production method had been used during those periods.

				First			Second		Third		Fourth			Total
				(In Thousands, Except For Per Share Data)
*2001*
Revenues				$	39,771		$	29,886	$	21,331	$	17,897		$	108,885
Expenses, net					24,841			21,805		18,880		46,976			112,502

Income (loss) before cumulative effect of change in accounting principle					14,930			8,081		2,451		(29,079	)		(3,617	)
Cumulative effect of change in method of accounting for DD&A					(1,825	)		—		—		—			(1,825	)

			Net income (loss)	$	13,105		$	8,081	$	2,451	$	(29,079	)	$	(5,442	)

Earnings (loss) per common share*:
	Basic*:
		Income (loss) before cumulative effect of change in accounting principle		$	1.07		$	0.58	$	0.18	$	(2.08	)	$	(0.26	)
		Cumulative effect of change in method of accounting for DD&A			(0.13	)		—		—		—			(0.13	)

			Net income (loss)	$	0.94		$	0.58	$	0.18	$	(2.08	)	$	(0.39	)

	Diluted*:
		Net income (loss) before cumulative effect of change in accounting principle		$	1.03		$	0.56	$	0.17	$	(2.08	)	$	(0.26	)
		Cumulative effect of change in method of accounting for DD&A			(0.12	)		—		—		—			(0.13	)

			Net income (loss)	$	0.91		$	0.56	$	0.17	$	(2.08	)	$	(0.39	)

*2000*
Revenues				$	19,333		$	21,744	$	27,354	$	31,389		$	99,820
Expenses, net					15,144			16,476		18,843		21,362			71,825

			Net income	$	4,189		$	5,268	$	8,511	$	10,027		$	27,995

Basic earnings per common share*				$	0.36		$	0.44	$	0.69	$	0.80		$	2.32

Diluted earnings per common share*				$	0.34		$	0.43	$	0.67	$	0.77		$	2.23

*: The sum of the individual quarterly net income (loss) per common share amounts may not agree with year-to-date net income (loss) per common share because each period's computation is based on the weighted average number of shares outstanding during that period.

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

Not applicable.

PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

Directors of the Registrant

F.H. MERELLI, 65, has been with Key since September 9, 1992. He currently holds the offices of chairman of the board of directors, president and chief executive officer. He was chairman of the board of directors and chief executive officer from September 1999 to March 2002. From September 1992 to September 1999, he was chairman of the board, president and chief executive officer. From July 1991 to September 1992, Mr. Merelli was engaged as a private consultant in the oil and gas industry. Mr. Merelli was president and chief operating officer of Apache Corporation, and president, chief operating officer and a director of Key from June 1988 to July 1991, at which time he resigned from those positions in both companies. He was president of Terra Resources, Inc. from 1979 to 1988. Mr. Merelli has been a director of Apache Corporation since July 1997.

CORTLANDT S. DIETLER , 80, has been a member of the board of directors of Key since September 9, 1992. He has been the chairman of the board of TransMontaigne, Inc. since April 1995. The principal business of TransMontaigne, Inc. (through its various operating subsidiaries) is to provide refined petroleum product, terminaling and storage services, as well as the bulk purchase and sale and wholesale marketing of refined petroleum products. Mr. Dietler was the founder, chairman and chief executive officer of Associated Natural Gas Corporation prior to its 1994 merger with Panhandle Eastern Corporation (now Duke Energy Corporation). He also serves as a director of Hallador Petroleum Company, Forest Oil Corporation, and Carbon Energy Corporation. His industry affiliations include: member of the National Petroleum Council; director of the American Petroleum Institute; past director of the Independent Petroleum Association of America; and director, past president and life member of the Rocky Mountain Oil & Gas Association.

L. PAUL TEAGUE, 67, has been a member of the board of directors of Key since August 20, 1996. He retired in 1994 from his position as vice president, Western Region, Texaco Exploration & Producing Inc. in Denver. Other positions in his 35 years with Texaco included division manager of the New Orleans Division, Eastern Producing Department; vice president, New Orleans Producing Division of Texaco USA; and vice president, Producing Department, Texaco USA in Houston. His industry affiliations include: chairman of the API Executive Committee on Drilling and Production Practices; president of the Colorado Petroleum Association; director and executive committee member of the Rocky Mountain Oil & Gas Association; and executive committee member of the Louisiana Oil & Gas Association.

PAUL D. HOLLEMAN, 71, has been a member of the board of directors of Key since April 4, 2001. He retired in 2000 from his position as senior partner in Holme Roberts & Owen LLP, a Denver law firm. At Holme Roberts he had served as legal counsel to Key Production and other oil and gas companies. Other positions in his 40 years with Holme Roberts included chairman of the Natural Resources Department and member of the executive committee. He was president of Inter-American Petroleum Corporation in 1970 and 1971 and was a director of Janus Fund in those same years. He is past chairman of the Mineral Law Section of the Colorado Bar Association, past chairman of the Rocky Mountain Mineral Law Institute and past chairman of the American Bar Association Public Lands Committee of the Natural Resources Section.

All directors were elected on June 14, 2001, to serve for a one-year term or until their successors are duly elected and qualified.

Executive Officers of the Registrant

F.H. MERELLI, 65, has been with Key since September 9, 1992. He currently holds the offices of chairman of the board, president and chief executive officer. He was chairman of the board of directors

and chief executive officer from September 1999 to March 2002. From September 1992 to September 1999, he was chairman of the board, president and chief executive officer. From July 1991 to September 1992, Mr. Merelli was engaged as a private consultant in the oil and gas industry. Mr. Merelli was president and chief operating officer of Apache Corporation, and president, chief operating officer and a director of Key from June 1988 to July 1991, at which time he resigned from those positions in both companies. He was president of Terra Resources, Inc. from 1979 to 1988. Mr. Merelli has been a director of Apache Corporation since July 1997.

PAUL KORUS, 45, joined Key in September 1999, as its vice president and chief financial officer. He was an equity research analyst with Petrie Parkman & Co., an investment banking firm, from June 1995 to September 1999. Prior to that, Mr. Korus was director of investor relations for Apache Corporation.

THOMAS E. JORDEN, 44, has been with Key since November 1993. In September 1999, he was appointed vice president-exploration. He served as chief geophysicist for Key from November 1993 to September 1999. Prior to joining Key, Mr. Jorden was with Union Pacific Resources in Fort Worth, Texas.

JOSEPH R. ALBI, 43, has been with Key since June 1994. In September 1999, he was appointed vice president-engineering. He served as manager of engineering from June 1994 to September 1999. He was executive vice president of Black Dome Energy Corporation from 1991 to 1994. Prior to that, Mr. Albi held various engineering positions with Apache Corporation and Nicor Oil and Gas Corporation.

STEPHEN P. BELL, 47, has been with Key since February 1994. In September 1999, he was appointed senior vice president-business development and land. From February 1994 to September 1999, he served as vice president-land. From March 1991 to February 1994, he was president of Concord Reserve, Inc., a privately-held independent oil and gas company. He was employed by Pacific Enterprises Oil Company (formerly Terra Resources, Inc.) as mid-continent regional manager from February 1990 to February 1991 and as land manager from August 1985 to January 1990.

BARBARA L. SCHALLER, 46, joined Key in March 1993. She was appointed general counsel and corporate secretary in September 1999. From March 1993 to September 1999, she served as corporate counsel and assistant secretary. Ms. Schaller has been practicing law since 1982 and is a member of the Denver, Colorado and American Bar Associations.

Section 16(a) Beneficial Ownership Reporting Compliance

The federal securities laws require our directors and executive officers to file reports of changes in ownership of Key's stock. During 2001, one report filed by Monroe W. Robertson, who was Key's president and chief operating officer during 2001, was filed three days late. This report disclosed one transaction in Key stock.

ITEM 11. EXECUTIVE COMPENSATION

These tables show the compensation of Key Production's chairman and the five other most highly paid officers for the year ended December 31, 2001.

Summary Compensation Table

						Long-Term Compensation
		Annual Compensation				Long-Term Compensation
Name and Principal Position		Annual Compensation				Restricted Stock Awards			Securities Underlying Options	All Other Compensation
Name and Principal Position	Year	Salary(1)		Bonus		Restricted Stock Awards			Securities Underlying Options	All Other Compensation
F.H. Merelli, Chairman and Chief Executive Officer	2001 2000 1999	$ $ $	306,328 265,041 196,977	$ $ $	238,537 59,604 26,269		— — —		— 125,000 —	$ $ $	8,420 12,838 11,132	(2)
Monroe W. Robertson, President and Chief Operating Officer	2001 2000 1999	$ $ $	247,161 226,875 181,319	$ $ $	204,188 54,990 23,639		— — —		— — 120,000	$ $ $	18,123 11,325 8,259	(3)
Paul Korus Vice President and Chief Financial Officer	2001 2000 1999	$ $ $	178,776 157,750 42,801	$ $ $	141,975 12,840 —	$	— — 96,875	(7)	— — 120,000	$ $ $	6,800 6,277 1,496	(4)
Thomas E. Jorden, Vice President Exploration	2001 2000 1999	$ $ $	168,995 154,833 133,102	$ $ $	139,350 39,931 18,165		— — —		— — 80,000	$ $ $	12,440 7,758 6,032	(5)
Joseph R. Albi, Vice President Engineering	2001 2000 1999	$ $ $	157,728 144,541 120,601	$ $ $	130,087 36,181 15,850		— — —		— — 80,000	$ $ $	6,800 7,169 5,440	(4)
Stephen P. Bell Senior Vice President—Business Development and Land	2001 2000 1999	$ $ $	157,436 144,541 112,782	$ $ $	130,087 34,198 14,515		— — —		— — 80,000	$ $ $	11,535 7,169 5,127	(6)

(1): Includes amounts earned but deferred at the election of the officer, if any.
(2): Includes our matching contribution of $6,800 (made in the form of Key common stock) pursuant to our 401(k) plan and the one-year term cost of life insurance provided for Mr. Merelli of $1,620.
(3): Consists of our matching contribution of $6,800 (made in the form of Key common stock) pursuant to our 401(k) plan and a contribution of $11,323 pursuant to our deferred compensation plan.
(4): Consists of our matching contribution of $6,800 (made in the form of Key common stock) pursuant to our 401(k) plan.
(5): Consists of our matching contribution of $6,800 (made in the form of Key common stock) pursuant to our 401(k) plan and a contribution of $5,640 pursuant to our deferred compensation plan.
(6): Consists of our matching contribution of $6,800 (made in the form of Key common stock) pursuant to our 401(k) plan and a contribution of $4,735 pursuant to our deferred compensation plan.
(7): Consists of 10,000 restricted shares of Key stock valued at the closing price of $9.6875 per share on the date of grant and which will vest fully on September 20, 2002.

AGGREGATED OPTION EXERCISES IN FISCAL YEAR 2001
AND FISCAL YEAR 2001 YEAR-END OPTION VALUES

				Number of Securities Underlying Unexercised Options at 2001 Year End				Values of Unexercised In-the-Money Options at 2001 Year End
	Number of Shares Acquired on Exercise
Name		Value Realized
Name		Value Realized		Exercisable		Unexercisable		Exercisable(1)		Unexercisable(1)
F.H. Merelli	— —		— —	250,000 41,667	(2) (3)	— 83,333	(3)	$ $	1,406,250 153,647	$	— 307,290
Monroe W. Robertson	80,000 —	$	946,425 —	— —		— 40,000	(4)		— —	$	— 292,500
Paul Korus	5,000 —	$	65,587 —	— 45,000	(4)	— 40,000	(4)	$	— 329,063	$	— 292,500
Thomas E. Jorden	—		—	32,333	(4)	26,667	(4)	$	236,435	$	195,002
Joseph R. Albi	4,000 —	$	45,390 —	— 34,833	(4)	— 26,667	(4)	$	— 254,716	$	— 195,002
Stephen P. Bell	—		—	35,833	(4)	26,667	(4)	$	262,029	$	195,002

(1): Amount represents the $17.00 closing price of our common stock on December 31, 2001 (the last trading day of the year), on the New York Stock Exchange, less the exercise price multiplied by the number of exercisable/unexercisable stock options at December 31, 2001, that had an exercise price less than the market value at the date.
(2): Options were granted on January 26, 1997, and vest at a rate of one-third per year over three years. These options were granted under our 1992 Stock Option Plan.
(3): Options were granted on May 25, 2000, and vest at a rate of one-third per year over three years. These options were granted under our 1992 Stock Option Plan.
(4): Options were granted on September 7, 1999, and vest at a rate of one-third per year over three years. These options were granted under our 1992 Stock Option Plan.

Director Compensation

Of our current board members, Mr. Merelli is the only salaried employee of Key. Commencing in 2000, board members who are not employees received $1,000 for each board meeting attended and $300 for each committee meeting attended. Prior to that time, non-employee directors did not receive cash compensation for serving as directors. Board members are reimbursed for their actual expenses related to attending board meetings. Non-employee directors also receive director compensation in the form of stock options granted under the Stock Option Plan for Non-Employee Directors.

Upon his election to the board, Mr. Dietler was granted stock options for 45,000 shares on December 9, 1992, at an exercise price of $2.875 per share. These options vested at a rate of one-third per year over three years. In recognition of his continued service to Key, Mr. Dietler was also granted additional stock options for 22,500 shares on January 26, 1997, at an exercise price of $11.375 per share and stock options for 20,000 shares on May 7, 1998, at an exercise price of $12.00 per share. These options also vested at the rate of one-third per year over three years.

Upon his election to the board, Mr. Teague was granted stock options for 45,000 shares on August 19, 1996, at an exercise price of $8.125 per share. These options vested at a rate of one-third per year over three years. In recognition of his continued service to Key, Mr. Teague was also granted additional stock options for 20,000 shares on May 7, 1998, at an exercise price of $12.00 per share. These options also vested at a rate of one-third per year over three years.

Upon his election to the board, Mr. Holleman was granted stock options for 45,000 shares on April 4, 2001, at an exercise price of $18.765 per share. These option vest at a rate of one-third per year over three years on each anniversary date.

Employment Agreements and Change-in-Control Arrangements

F.H. Merelli. Mr. Merelli has an employment agreement with Key pursuant to which he agreed to serve for an indefinite term. The compensation committee of the board sets his base salary.

In addition to the base salary, the employment agreement provided for the grant to Mr. Merelli of stock options for 500,000 shares of the company's common stock. These options were exercised during fiscal year 2000. The agreement also provides that Mr. Merelli is eligible for incentive bonuses under any incentive program for executives of the company which is adopted by the board of directors. No formal incentive bonus program has been adopted as of the date of this report, although cash bonuses are granted based upon a subjective determination of an individual's performance as well as the overall financial results of Key.

It further provides that if he is terminated without cause or because of death or disability, Mr. Merelli or his estate will receive his then-current monthly salary for two years. The company must also purchase a $500,000 life insurance policy for him.

Mr. Merelli's stock option agreement provides that upon a change in control of Key, all of his outstanding options will immediately vest. He is a participant in the Key Production Company, Inc. Income Continuance Plan which provides for the continuation of salary and benefits for certain employees upon a change in control of Key Production. Any benefits paid to Mr. Merelli pursuant to this plan would be in lieu of, and not in addition to, any payments made pursuant to his employment agreement.

Monroe W. Robertson. Mr. Robertson recently retired from his most recent position with Key, President and Chief Operating Officer, effective March 1, 2002. In connection with his retirement, Mr. Robertson entered into two agreements with Key. The first agreement recognized his substantial contribution to the formation of Key and to its growth and significant increase in shareholder value. Pursuant to this agreement, dated February 23, 2002, he received a payment of $700,000, less applicable taxes and deductions required by law. He will continue to receive medical and dental coverage under Key's insurance plans through February 29, 2004, and will make payments for such coverage in an amount similar to other officers of the company. By action of the board of directors, options held by Mr. Robertson which were to vest on September 6, 2002, were fully vested on February 21, 2002.

This agreement superceded and replaced any benefits Mr. Robertson may have had pursuant to his employment agreement with Key (providing, among other things, if he is terminated under certain circumstances he will receive his then-current salary for two years), his stock option agreement with Key (providing that upon a change in control his options will immediately vest), the Key Production Company, Inc. Income Continuance Plan (providing for the continuation of salary and benefits in certain circumstances upon a change in control) or any other incentive program in which he may have participated.

The second agreement, a Noncompete Agreement dated as of February 23, 2002, recognizes that Mr. Robertson has acquired valuable and confidential and proprietary information through his employment with Key. In order to protect the trade secrets and confidential information of the company, Key made a $2,300,000 payment to Mr. Robertson for his agreement not to compete with the company. Pursuant to this agreement, for a two year period Mr. Robertson is prohibited from certain activities including affiliation with an entity engaged in substantially similar business operations and geographical areas as the company, recruiting employees of the company and other restrictions upon his ability to compete with Key.

Paul Korus. Mr. Korus has an employment agreement with Key pursuant to which he agreed to serve for a two-year term ending September 7, 2001. It provides that if Mr. Korus continues as an employee after the term of the agreement and is terminated without cause after a change in control, he will receive an immediate payment of two times his then-current annual salary.

A stock option agreement with Mr. Korus provides that upon a change in control of Key, all of his outstanding options will immediately vest.

A restricted stock agreement with Mr. Korus provides that the restricted stock will vest if his employment is terminated under certain circumstances within six months after a change in control of Key.

He is a participant in the Key Production Company, Inc. Income Continuance Plan which provides for the continuation of salary and benefits for certain employees upon a change in control of Key. Any benefits paid to Mr. Korus pursuant to this plan would be in lieu of, and not in addition to, any payments made pursuant to his employment agreement.

Thomas E. Jorden. Mr. Jorden has an employment agreement with Key pursuant to which he agreed to serve for a three-year term ending November 8, 1996. It provides that if Mr. Jorden continues as an employee after the term of the agreement and is terminated without cause after a change in control, he will receive an immediate payment of two times his then-current annual salary.

A stock option agreement with Mr. Jorden provides that upon a change in control of Key, all of his outstanding options will immediately vest.

He is a participant in the Key Production Company, Inc. Income Continuance Plan, which provides for the continuation of salary and benefits for certain employees upon a change in control of Key. Any benefits paid to Mr. Jorden pursuant to this plan would be in lieu of, and not in addition to, any payments made pursuant to his employment agreement.

Joseph R. Albi. Mr. Albi has an employment agreement with Key pursuant to which he agreed to serve for a three-year term ending March 11, 1997. It provides that if Mr. Albi continues as an employee after the term of the agreement and is terminated without cause after a change in control, he will receive an immediate payment of two times his then-current annual salary.

A stock option agreement with Mr. Albi provides that upon a change in control of Key, all of his outstanding options will immediately vest.

He is a participant in the Key Production Company, Inc. Income Continuance Plan, which provides for the continuation of salary and benefits for certain employees upon a change in control of Key. Any benefits paid to Mr. Albi pursuant to this plan would be in lieu of, and not in addition to, any payments made pursuant to his employment agreement.

Stephen P. Bell. Mr. Bell has an employment agreement with Key pursuant to which he agreed to serve for a three-year term ending February 2, 1997. It provides that if Mr. Bell continues as an employee after the term of the agreement and is terminated without cause after a change in control, he will receive an immediate payment of two times his then-current annual salary.

A stock option agreement with Mr. Bell provides that upon a change in control of Key, all of his outstanding options will immediately vest.

He is a participant in the Key Production Company, Inc. Income Continuance Plan which provides for the continuation of salary and benefits for certain employees upon a change in control of Key. Any benefits paid to Mr. Bell pursuant to this plan would be in lieu of, and not in addition to, any payment made pursuant to his employment agreement.

Compensation Committee Interlocks and Insider Participation

No member of Key's compensation committee of the board of directors was at any time during fiscal year 2001 or any preceding fiscal year an officer or employee of Key or any of its subsidiaries. During fiscal year 2001, no executive officer of Key served as a director or member of a compensation (or similarly empowered) committee for any entity whose executive officer or officers served on Key's compensation committee.

Board Compensation Committee Report on Executive Compensation

General Compensation Philosophy

The compensation committee of the board of directors is responsible for providing oversight of Key's executive compensation. The compensation committee is currently composed of Key's three independent directors, Mr. Cortlandt S. Dietler, Mr. L. Paul Teague and Mr. Paul D. Holleman.

Key has designed its compensation program to be competitive in the oil and gas industry and to motivate, retain and reward executives who are capable of successfully leading the company. Our program consists primarily of base salary and stock options, although executives also receive benefits typically offered to corporate executives. We also consider granting cash bonuses based upon a subjective determination of an individual's performance and accomplishments as well as the overall financial results of the company.

In keeping with this overall policy, we aim to link management goals with the interests of stockholders by emphasizing the grant of stock options. We believe that when Key's stockholders win—through consistent growth in earnings, revenue, production, reserves and stock price appreciation—Key's executives win. If stockholders do not realize these gains, neither do our executives.

Base Salaries

In making decisions regarding base salaries, the chairman of the board, president and chief executive officer, by authority of the compensation committee, makes recommendations about the base salary of the executive officers (other than himself). For several years he has relied primarily upon the information contained in an industry compensation survey. In 2001, he reviewed the information contained in the William Mercer 2001 Energy Compensation Survey. He reviewed the compensation and benefits of executives in positions of similar overall responsibility for those companies included in the report, which most closely approximated the size of Key. Based on this report and an assessment of the skills, experience and achievements of individual executives, the 2001 executive compensation was decided. Salary increases were made to these individuals in accordance with the salary ranges shown in the report.

The 2001 base salaries of our executives remain near to the mid-range for companies of comparable size engaged in similar business, which were included in the report. This result is in keeping with our current philosophy that in order to retain our executives, the non-variable portion of any executive officer's pay should be within the parameters offered by our competitors.

Bonuses

Short-term incentives consist of cash bonuses to executives to reward their contributions during the past business years and to provide incentives for further improvement in the future. The bonus any executive receives depends on the executive's individual performance and level of responsibility as well as the overall financial performance of Key. We assess relative performance based on factors including initiative, business judgment, technical expertise and management skills, but no particular formula is used. In early 2001, each of Key's executive officers received cash bonuses equal to 90 percent of their 2000 base salary. Although paid in 2001, these bonuses were based upon 2000 financial results and

recognized that these individuals contributed substantially to the successful acquisition by merger of Columbus Energy Corp. and the strong performance of Key's stock during 2000.

Stock Options

Stock options are the central focus of our long-term incentive program. The executives who are granted stock options gain only when you gain—when the common stock value goes up. Although the stockholders approved the 2001 Equity Incentive Plan at the annual meeting of stockholders held June 14, 2001, no option grants were made to executives of Key during fiscal year 2001.

Benefit Plans

The benefit package offered to executive officers is substantially the same as that for all Key employees for group health and hospitalization, dental, life and disability insurance, although we provide a $500,000 life insurance policy to Mr. Merelli pursuant to his employment agreement.

The executive officers participate in our 401(k) retirement savings plan, which consists of employee contributions and the company's matching contribution of up to four percent of the employee's compensation. The company's matching contribution is made in the form of Key common stock. The Key Production Company, Inc. Income Continuance Plan provides for the continuation of salary and benefits for certain employees if there is a change in control of Key Production. Any payments made pursuant to this plan are in lieu of, and not in addition to, any payments made pursuant to employment agreements.

Under the company's non-qualified Deferred Compensation Plan, executive officers and certain other management and highly compensated employees are entitled to defer an amount of income equal to the amount they would have been able to contribute to the company's 401(k) plan, but are prohibited from doing so under Section 402(g) of the Internal Revenue Code of 1986. Participants may also elect to have up to 25 percent of their annual compensation and 75 percent of any bonus withheld and credited to the plan.

CEO Compensation

Mr. Merelli was hired in late 1992 and is currently the chairman, president and chief executive officer of Key. During his tenure at Key, he has continuously held the office of chairman and chief executive officer. Since March 2002 and prior to September 1999, he also held the office of president. The compensation committee increased Mr. Merelli's base salary to $321,000, effective September 16, 2001. The compensation committee believes that Mr. Merelli's base salary remains very conservative for the chairman of the board and chief executive officer for a corporation of Key's size.

We have tied Mr. Merelli's compensation to the performance of Key because of the emphasis on stock options although no options were granted to him during fiscal year 2001.

Mr. Merelli received a cash bonus in 2001, reflecting fiscal 2000 operational and fiscal results, as well as his overall level of responsibility and experience. Since Mr. Merelli assumed management of Key, he has significantly contributed to the company's consistent and profitable growth and its consistently strong balance sheet. The committee focused on the importance of Mr. Merelli to the successful acquisition by merger of Columbus Energy Corp. during fiscal 2000 and to the continued growth and development of Key, his expertise in the industry and demonstrated management skills, as well as the fact that his base salary is relatively modest.

In 2001, Mr. Merelli received matching contributions pursuant to Key's 401(k) plan and Key paid the premium for a term life insurance policy it provides for him. These two components of Mr. Merelli's compensation are not based upon performance.

U.S. Income Tax Limits on Deductibility

U.S. income tax law limits the amount Key can deduct for compensation paid to the CEO and the other four most highly paid executives. We do not currently have a policy regarding qualifying compensation paid to executive officers for deductibility under Section 162(m) of the Internal Revenue Code (the "Code"). If such limits have a material effect on the company's tax position in the future, we will consider adopting criterion to qualify for the tax deduction at that time. However, Key has structured the 2001 Equity Incentive Plan with the intention that compensation resulting from options and awards granted under that plan would be deductible without regard to the limitations otherwise imposed by Section 162(m) of the Code.

Summary

The compensation committee is made up of non-employee directors who do not participate in the compensation plans we administer. We approve or endorse compensation paid or awarded to senior executives and we administer several of Key's benefit plans including the 2001 Equity Incentive Plan and the 1992 Stock Option Plan. We also specifically set salary and benefit levels for the chief executive officer, subject to the terms of his existing employment agreement. In the opinion of the committee, Key has an appropriate and competitive compensation program. The combination of sound base salary, short-term bonuses and the emphasis on long-term incentives provides a foundation for effective leadership into the future.

		THE COMPENSATION COMMITTEE
				L. Paul Teague, Chairman Cortlandt S. Dietler Paul D. Holleman

STOCK PERFORMANCE GRAPH

The following graph compares the cumulative total stockholder return on Key Production common stock with Standard & Poor's 500 Stock Index and the Dow Jones Secondary Oil Stock Index. The graph assumes that $100 each was invested on December 31, 1996, and that all dividends were reinvested.

Comparison of Five Year Cumulative Total Return
Among Key Production Company, Inc., the S & P 500 Index
and the Dow Jones Secondary Oil Index

	1996	1997	1998	1999	2000	2001
KP	100	82	41	59	263	133
S&P 500	100	133	171	208	189	166
DJ OIL 2D	100	100	68	79	126	116

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

Beneficial Stock Ownership

FIVE PERCENT HOLDERS
OF KEY PRODUCTION STOCK
(As of March 8, 2002)*

	Voting Authority		Dispositive Authority
Name and Address	Voting Authority		Dispositive Authority		Total Amount of Beneficial Ownership	Percent of Class
Name and Address	Sole	Shared	Sole	Shared	Total Amount of Beneficial Ownership	Percent of Class
Dimensional Fund Advisors Inc.(1) 1299 Ocean Avenue, 11^th Floor Santa Monica, California 90401	835,186	—	835,186	—	835,186	5.95	%

*: Calculations based upon 14,046,252 shares outstanding as of March 8, 2002.
(1): Information from Schedule 13G filed by Dimensional Fund Advisors with the SEC on February 12, 2002.

OFFICER AND DIRECTOR STOCK OWNERSHIP
(As of March 8, 2002)*

Name	Shares Beneficially Owned*		Percent of Class*
F.H. Merelli	711,534	(1)(5)	4.93	%
Cortlandt S. Dietler	146,000	(2)	1.03	%
L. Paul Teague	50,837	(3)	0.36	%
Paul D. Holleman	47,000	(4)	0.33	%
Stephen P. Bell	66,904	(6)	0.47	%
Joseph R. Albi	66,660	(7)	0.47	%
Thomas E. Jorden	65,986	(8)	0.47	%
Paul Korus	200,898	(9)(5)	1.42	%
Barbara L. Schaller	9,489	(10)	0.07	%
All directors and executive officers as group (including the above named persons)	1,260,394	(11)	8.50	%

*: Calculated pursuant to Rule 13d-3(d)(1) of the Securities Exchange Act of 1934.
(1): Includes 152,300 shares held in Mr. Merelli's IRA account; options for 375,000 shares (consisting of options for 250,000 shares which are fully vested, and options for 125,000 shares, one-third of which vested on May 25, 2001, with an additional one-third vesting on each subsequent anniversary date); and 9,220 shares held in his 401(k) account.
(2): Includes options for 87,500 shares which are fully vested.
(3): Includes options for 6,667 shares which are fully vested.
(4): Includes options for 45,000 shares, one-third of which will vest on April 4, 2002, with an additional one-third vesting on each subsequent anniversary date.
(5): Includes 104,914 shares held by Messrs. Merelli and Korus as Trustees of Key's 401(k) retirement plan.
(6): Includes options for 62,500 shares (consisting of options for 35,833 shares which are fully vested and 26,667 shares which will vest on September 7, 2002); and 4,404 shares held in his 401(k) account.
(7): Includes 800 shares held in Mr. Albi's IRA account; options for 61,500 shares (consisting of options for 34,833 shares which are fully vested and 26,667 shares which will vest on September 7, 2002); and 4,360 shares held in his 401(k) account.
(8): Includes options for 59,000 shares (consisting of options for 32,333 shares which are fully vested and 26,667 shares which will vest on September 7, 2002); and 5,226 shares held in his 401(k) account.
(9): Includes options for 85,000 shares (consisting of options for 45,000 shares which are fully vested and 40,000 shares which will vest on September 7, 2002); 10,000 shares of restricted stock; and 984 shares held in his 401(k) account.
(10): Includes options for 6,667 shares (consisting of 3,334 shares which are fully vested and 3,333 shares which will vest on September 7, 2002) and 1,822 shares held in her 401(k) account.
(11): Includes options for 788,834 shares of common stock, vesting at various dates beginning September 1, 1993. The 104,914 shares held by the trustees of Key's 401(k) retirement plan were only counted once in this calculation.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

Mr. Robertson recently retired from his most recent position with Key, President and Chief Operating Officer, effective March 1, 2002. In connection with his retirement, Mr. Robertson entered into two agreements with Key. The first agreement recognized his substantial contribution to the formation of Key and to its growth and significant increase in shareholder value. Pursuant to this agreement, dated February 23, 2002, he received a payment of $700,000, less applicable taxes and deductions required by law. He will continue to receive medical and dental coverage under Key's insurance plans through February 29, 2004, and will make payments for such coverage in an amount similar to other officers of the company. By action of the board of directors, options held by Mr. Robertson which were to vest on September 6, 2002, were fully vested on February 21, 2002.

PART IV

ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K

(a)	1.	The following financial statements are included in Item 8 to this 10-K.
		Independent Auditors' Report for the years ended December 31, 2001 and 2000.
		Report of Independent Auditors for the year ended December 31, 1999.
		Consolidated statements of operations for the years ended December 31, 2001, 2000, and 1999.
		Consolidated statements of cash flows for the years ended December 31, 2001, 2000, and 1999.
		Consolidated balance sheets as of December 31, 2001 and 2000.
		Consolidated statements of changes in stockholders' equity for the years ended December 31, 2001, 2000, and 1999.
		Summary of significant accounting policies.
		Notes to consolidated financial statements.
		Supplemental oil and gas disclosures.
		Supplemental quarterly financial data.
	2.	Schedules: None
	3.	Exhibits:
		Exhibits not incorporated by reference to a prior filing are designated by an asterisk (*) and are filed herewith; all exhibits not so designated are incorporated by reference to a prior SEC filing as indicated.
		Exhibits designated by a plus sign (+) are management contracts or compensatory plans or arrangements required to be filed herewith pursuant to Item 14.

Exhibit No.		Description

3.1	—	Certificate of Incorporation of the Registrant (incorporated by reference to Exhibit 3.1 to the Registrant's Registration Statement on Form S-4, registration no. 33-23533 filed with the SEC on August 5, 1988).
3.2	—	Amendment to Certificate of Incorporation of the Registrant (incorporated by reference to Exhibit 3.2 to the Registrant's Registration Statement on Form S-4, registration no. 33-23533 filed with the SEC on August 5, 1988).
3.3	—	Second amendment to Certificate of Incorporation of the Registrant, dated June 13, 2000 (incorporated by reference to Exhibit 3.3 to the Registrant's Form 10-K for the fiscal year ended December 31, 2000, file no. 001-11769).
3.4	—	Bylaws of the Registrant, as amended and restated on June 8, 1995 (incorporated by reference to Exhibit 3.3 to the Registrant's Form 10-Q for the quarter ended June 30, 1995, file no. 0-17162).

4.1	—	Form of Common Stock Certificate (incorporated by reference to Exhibit 4.12 to the Registrant's Amendment No. 1 to Registration Statement on Form S-4, registration no. 33-23533 filed with the SEC on August 15, 1988).
4.2	—	Rights Agreement, dated February 25, 2002, between the Company and A.G. Edwards & Sons, Inc., as Rights Agent, which includes as Exhibit A thereto the form of Rights Certificate (incorporated by reference to Exhibit 1 to the Registrants' Form 8-A, file no. 001-11769).
+10.1	—	Key Production Company, Inc. 1992 Stock Option Plan (incorporated by reference to Exhibit 10.7 to the Registrant's Form 10-K for the fiscal year ended December 31, 1992, file no. 0-17162).
+10.2	—	Key Production Company, Inc. Stock Option Plan for Non-Employee Directors, (incorporated by reference to Exhibit 10.8 to the Registrant's Form 10-K for the fiscal year ended December 31, 1992, file no. 0-17162).
+10.3	—	Key Production Company, Inc. 401(k) Plan (incorporated by reference to Exhibit 10.10 to the Registrant's Form 10-K for the fiscal year ended December 31, 1992, file no. 0-17162).
+10.4	—	Key Production Company, Inc. Income Continuance Plan, dated effective June 1, 1994 (incorporated by reference to Exhibit 10.18 to the Registrant's Form 10-K for the fiscal year ended December 31, 1992, file no. 0-17162).
+10.5.1	—	Amendment No. 1 to the Key Production Company, Inc. 1992 Stock Option Plan, dated March 14, 1997 (incorporated by reference to Exhibit 10.21.1 to the Registrant's Form 10-Q for the period ended June 30, 1998, file no. 001-11769).
+10.5.2	—	Amendment No. 1 to the Key Production Company, Inc. Stock Option Plan for Non-Employee Directors, dated January 27, 1997 (incorporated by reference to Exhibit 10.21.2 to the Registrant's Form 10-Q for the period ended June 30, 1998, file no. 001-11769).
+10.5.3	—	Amendment No. 2 to the Key Production Company Inc. Stock Option Plan for Non-Employee Directors, dated March 14, 1997 (incorporated by reference to Exhibit 10.21.3 to the Registrant's Form 10-Q for the period ended June 30, 1998, file no. 001-11769).
+10.5.4	—	Amendment No. 3 to the Key Production Company, Inc. Stock Option Plan for Non-Employee Directors, dated May 6, 1998 (incorporated by reference to Exhibit 10.21.4 to the Registrant's Form 10-Q for the period ended June 30, 1998, file no. 001-11769).
10.6	—	Credit Agreement, dated as of November 12, 1999, among Key Production Company, Inc., the Lenders party thereto, Bank of America N.A., as Administrative Agent, Bank One NA, as Documentation Agent, Banc of America Securities LLC, as Lead Arranger and Book Manager (incorporated by reference to Exhibit 10.6 to the Registrant's Form 10-K for the fiscal year ended December 31, 2000, file no. 001-11769).
10.7	—	First Amendment to Credit Agreement, dated as of November 15, 2000, among Key Production Company, Inc., Bank of America N.A., as Agent, and the Lenders under the Credit Agreement (incorporated by reference to Exhibit 10.7 to the Registrant's Form 10-K for the fiscal year ended December 31, 2000, file no. 001-11769).

*+10.8.1	—	Noncompete Agreement, dated as of February 23, 2002, between Key Production Company, Inc. and Monroe Robertson.
*+10.8.2	—	Agreement, dated as of February 23, 2002, between Key Production Company, Inc. and Monroe W. Robertson.
+10.9	—	Key Production Company, Inc. 2001 Equity Incentive Plan (incorporated by reference to Appendix A of the Registrant's Proxy Statement for its 2001 Annual Meeting of Stockholders, file no. 001-11769).
*18.1	—	Letter from KPMG LLP regarding the preferability of change in accounting principle dated March 20, 2002.
*23.1	—	Consent of KPMG LLP, dated March 20, 2002.
*23.2	—	Consent of Arthur Andersen LLP, dated March 20, 2002.

(b): Reports on Form 8-K:

On November 9, 2001, we filed a report dated November 8, 2001, on Form 8-K. The Form 8-K announced our third quarter earnings.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized:

		KEY PRODUCTION COMPANY, INC.
Date: March 21, 2002		By:	/s/ F.H. MERELLI F.H. Merelli Chairman, President and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Signature	Title	Date

/s/ F.H. MERELLI F.H. Merelli	Director, Chairman, President and Chief Executive Officer (Principal Executive Officer)	March 21, 2002
/s/ PAUL KORUS Paul Korus	Vice President and Chief Financial Officer (Principal Financial Officer)	March 21, 2002
/s/ SHERRI M. NITTA Sherri M. Nitta	Director of Financial Reporting (Principal Accounting Officer)	March 21, 2002
/s/ CORTLANDT S. DIETLER Cortlandt S. Dietler	Director	March 21, 2002
/s/ PAUL D. HOLLEMAN Paul D. Holleman	Director	March 21, 2002
/s/ L. PAUL TEAGUE L. Paul Teague	Director	March 21, 2002

KEY PRODUCTION CO INC 10-K