Key Production 10-Q 2002 Q1 Quarterly report

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KEY PRODUCTION COMPANY, INC. Table of Contents

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-Q

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934

For the Quarterly Period ended March 31, 2002
Commission file No. 001-11769

KEY PRODUCTION COMPANY, INC.
707 Seventeenth Street, Suite 3300
Denver, Colorado 80202-3404
(303) 295-3995

Incorporated in the
State of Delaware Employer Identification
No. 84-1089744

        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

        The number of shares outstanding of the Company's common stock as of March 31, 2002 is shown below:

Title of Class	Number of Shares Outstanding
Common Stock, par value $0.25 per share	14,080,468

KEY PRODUCTION COMPANY, INC.
Table of Contents

PART I
Item 1—	Financial Statements
	Consolidated statements of operations (unaudited) for the three months ended March 31, 2002 and March 31, 2001
	Consolidated statements of cash flows (unaudited) for the three months ended March 31, 2002 and March 31, 2001
	Consolidated balance sheets (unaudited) as of March 31, 2002 and December 31, 2001
	Consolidated statement of stockholders' equity (unaudited) for the three months ended March 31, 2002
	Notes to consolidated financial statements
Item 2—	Management's Discussion and Analysis of Financial Condition and Results of Operations
Item 3—	Quantitative and Qualitative Disclosures About Market Risk
PART II
Item 6—	Exhibits and Reports on Form 8-K

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.

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KEY PRODUCTION COMPANY, INC.

Consolidated Statements of Operations

(Unaudited)

				For the Three Months Ended March 31,
				2002			2001
				(In thousands, except per share data)
Revenues:
	Gas sales			$	8,727		$	28,771
	Oil sales				7,320			10,703
	Plant product sales				211			249
	Other				107			48
					16,365			39,771
Operating expenses:
	Depreciation, depletion and amortization				7,913			8,604
	Lease operating				4,308			3,852
	Production taxes				1,004			2,486
	General and administrative				5,642			851
	Financing costs:
		Interest expense			298			693
		Capitalized interest			(81	)		(351	)
		Interest income			(10	)		(73	)
					19,074			16,062
Income (loss) before income taxes					(2,709	)		23,709
Income tax expense (benefit)					(600	)		8,779
Income (loss) before cumulative effect of change in accounting method					(2,109	)		14,930
Cumulative effect of change in accounting method, net of income taxes of $1,143,000					—			(1,825	)
			Net income (loss)	$	(2,109	)	$	13,105
Earnings (loss) per share:
	Basic:
		Income (loss) before cumulative effect of change in accounting method		$	(0.15	)	$	1.07
		Cumulative effect of change in accounting method, net of income taxes			—			(0.13	)
			Net income (loss)		(0.15	)		0.94
	Diluted:
		Income (loss) before cumulative effect of change in accounting method		$	(0.15	)		1.03
		Cumulative effect of change in accounting method, net of income taxes			—			(0.12	)
			Net income (loss)	$	(0.15	)		0.91
Weighted average common shares outstanding					14,057			13,961
Weighted average diluted shares outstanding					14,057			14,433

See accompanying notes to consolidated financial statements.

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KEY PRODUCTION COMPANY, INC.

Consolidated Statements of Cash Flows

(Unaudited)

				For the Three Months Ended March 31,
				2002			2001
				(In thousands)
Cash flows from operating activities:
	Net income (loss)			$	(2,109	)	$	13,105
	Adjustment to reconcile net income (loss) to net cash provided by operating activities:
		Depreciation, depletion and amortization			7,913			8,604
		Cumulative effect of change in accounting method			—			2,968
		Deferred income taxes			(742	)		3,511
		Common stock issued as compensation			—			112
		Amortization of unearned compensation			46			40
		Income tax benefit related to stock options exercised			108			217
	Changes in operating assets and liabilities:
		Increase in receivables			(1,597	)		(5,024	)
		Decrease in prepaid expenses and other			347			153
		Increase in accounts payable and accrued expenses			739			8,168
		Increase (decrease) in other liabilities			(138	)		9
			Net cash provided by operating activities		4,567			31,863
Cash flows from investing activities:
	Oil and gas exploration and development expenditures				(9,434	)		(26,114	)
	Acquisition of oil and gas properties				—			(36	)
	Purchase adjustments to acquisitions				—			703
	Proceeds from sale of oil and gas properties				—			1
	Other capital expenditures				(129	)		(121	)
			Net cash used by investing activities		(9,563	)		(25,567	)
Cash flows from financing activities:
	Payments on long-term debt, net				—			(12,000	)
	Payments to reacquire common stock				—			(6	)
	Proceeds from issuance of common stock				387			380
			Net cash provided (used) by financing activities		387			(11,626	)
Net decrease in cash and cash equivalents					(4,609	)		(5,330	)
Cash and cash equivalents at beginning of year					5,003			6,746
Cash and cash equivalents at end of period				$	394		$	1,416

See accompanying notes to consolidated financial statements.

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KEY PRODUCTION COMPANY, INC.

Consolidated Balance Sheets

(Unaudited)

		March 31, 2002			December 31, 2001
		(In thousands, except share data)
Assets
Current assets:
	Cash and cash equivalents	$	394		$	5,003
	Receivables		14,954			13,357
	Prepaid expenses and other		1,816			2,163
			17,164			20,523
Oil and gas properties, on the basis of full cost accounting:
	Proved properties		398,707			390,794
	Unproved properties and properties under development, not being amortized		11,224			11,961
			409,931			402,755
	Less—accumulated depreciation, depletion and amortization		(214,861	)		(207,139	)
			195,070			195,616
Other assets, net			1,467			1,529
		$	213,701		$	217,668
Liabilities and Stockholders' Equity
Current liabilities:
	Accounts payable	$	13,442		$	13,210
	Accrued exploration and development		1,068			2,478
	Accrued lease operating expense and other		222			467
	Current portion of long-term debt		7,286			4,857
			22,018			21,012
Long-term debt			26,714			29,143
Deferred income taxes			31,957			32,699
Other liabilities			449			587
Stockholders' equity:
	Common stock, $0.25 par value, 50,000,000 shares authorized, 14,080,468 and 14,041,269 shares issued, respectively		3,520			3,510
	Paid-in capital		70,394			69,924
	Unearned compensation		(313	)		(278	)
	Retained earnings		58,962			61,071
			132,563			134,227
		$	213,701		$	217,668

See accompanying notes to consolidated financial statements.

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KEY PRODUCTION COMPANY, INC.

Consolidated Statement of Stockholders' Equity

For the Three Months Ended March 31, 2002

(Unaudited)

	Common Stock
						Paid-in Capital			Unearned Compensation			Retained Earnings			Total Stockholders' Equity
	Shares		Amount
	(In thousands)
Balance, December 31, 2001	14,041		$	3,510		$	69,924		$	(278	)	$	61,071		$	134,227
Net loss	—			—			—			—			(2,109	)		(2,109	)
Common stock issued for options exercised	40			10			377			—			—			387
Income tax benefit from stock options exercised	—			—			108			—			—			108
Common stock reacquired	(6	)		(1	)		(95	)		—			—			(96	)
Unearned compensation related to restricted stock awards	5			1			80			(81	)		—			—
Amortization of unearned compensation	—			—			—			46			—			46
Balance, March 31, 2002	14,080		$	3,520		$	70,394		$	(313	)	$	58,962		$	132,563

See accompanying notes to consolidated financial statements.

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KEY PRODUCTION COMPANY, INC.

Notes to Consolidated Financial Statements

March 31, 2002

(Unaudited)

1. Basis of Presentation

        The accompanying financial statements are unaudited and were prepared from the Company's records. Management believes these financial statements include all adjustments necessary for a fair presentation of our financial position and results of operations. Key Production Company, Inc. (Key) prepared these statements on a basis consistent with the annual audited statements and Regulation S-X. Regulation S-X allows us to omit some of the footnote and policy disclosures required by accounting principles generally accepted in the United States of America and normally included in annual reports on Form 10-K. These interim financial statements should be read in conjunction with the financial statements, summary of significant accounting policies and notes in our most recent annual report on Form 10-K.

        The accounts of Key and its subsidiaries are presented in the accompanying consolidated financial statements. All intercompany accounts and transactions were eliminated in consolidation.

        We rely on management estimates and assumptions 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 and in 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.

        The financial statements for the three months ended March 31, 2001 have been restated to reflect the change in accounting method from the future gross revenue method to the units-of-production method for depletion of our oil and gas properties. The change in accounting method occurred in the fourth quarter of 2001 and was effective January 1, 2001.

        The cumulative effect of the change, calculated as of January 1, 2001, was to decrease net income by $1.8 million, net of income taxes of $1.1 million, or $0.12 per diluted share. The effect of the change was to increase net income for the three months ended March 31, 2001 by $2.6 million, $1.6 million net of income taxes, or $0.11 per diluted share.

        Certain amounts in the accompanying consolidated financial statements for prior periods have been reclassified to conform to the current year presentation.

2. 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

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(iii) H&P stockholders will receive 26,571,321 shares of Cimarex common stock upon distribution in the pro rata spin-off of Cimarex (Spin-off). Immediately thereafter, each share of common stock of Key will be exchanged for one share of Cimarex common stock and Merger Sub will be merged with and into Key, with Key as the surviving subsidiary of Cimarex (Merger).

        Upon completion of the transaction, holders of H&P common stock will own approximately 65 percent and Key stockholders will own approximately 35 percent of the common stock of Cimarex, in each case on a 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.

3. Long-Term Debt

        We have 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 March 31, 2002. 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 March 31, 2002, we had $34 million outstanding and $76 million unused and available on the credit facility.

        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 March 31, 2002.

        The credit 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 at March 31, 2002.

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4. Income Taxes

        Income tax expense (benefit) consisted of the following:

		Three Months Ended March 31,
		2002			2001
		(In thousands)
Current taxes:
	Federal	$	126		$	3,691
	State		16			434
			142			4,125
Deferred taxes			(742	)		4,654
		$	(600	)	$	8,779

5. Supplemental Disclosure of Cash Flow Information

		For the Three Months Ended March 31,
		2002		2001
		(In thousands)
Cash paid during the period for:
	Interest (net of amounts capitalized)	$	211	$	349
	Income taxes (net of refunds received)	$	298	$	1,114

6. Earnings Per Share

        The calculations of basic and diluted net income (loss) per common share for the three months ended March 31, 2002 and 2001 are presented in the table below:

		2002			2001
		(In thousands, except per share data)
Basic earnings (loss) per share:
	Income (loss) attributable to common stockholders	$	(2,109	)	$	13,105
	Weighted average basic shares outstanding		14,057			13,961
	Basic earnings (loss) per share	$	(0.15	)	$	0.94
Diluted earnings (loss) per share:
	Income (loss) attributable to common stockholders	$	(2,109	)	$	13,105
	Incremental shares assuming the exercise of stock options		—			472
	Weighted average diluted shares outstanding		14,057			14,433
	Diluted earnings (loss) per share	$	(0.15	)	$	0.91

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        For the three months ended March 31, 2002, potential common stock of 271,000 shares related to outstanding options were not included in the calculation of diluted loss per share because they were considered antidilutive.

        The weighted average common shares of diluted earnings (loss) per share calculation at March 31, 2002 excludes the incremental effect related to 45,000 outstanding stock options whose exercise price is in excess of the average price of Key's stock of $16.66 for the quarter. These options are excluded due to their antidilutive effect at March 31, 2002.

7. Stockholder Rights Plan

        On February 23, 2002, the Board of Directors adopted a shareholder rights plan. The plan is designed to improve the ability of the board to protect the interests of the stockholders in the event of an unsolicited takeover attempt.

        In adopting the plan, the board declared a dividend distribution of one common share purchase right for each outstanding share of common stock of Key, payable to stockholders of record at the close of business on March 7, 2002. The rights will become exercisable only in the event a person or group acquires beneficial ownership of 15% or more of our common stock, or a person or group commences a tender offer or exchange offer that, if successfully consummated, would result in such person or group beneficially owning 15% or more of our common stock.

        Upon a person or group acquiring beneficial ownership of 15% or more of our common stock, holders of the rights (other than rights owned by the acquiring person or group) would be entitled to purchase Key common stock (or in certain circumstances, shares of the acquiring entity) at approximately half the then current market price of such stock. Further, at any time after a person or group acquires 15% or more (but less than 50%) of our outstanding common stock, the board may, at its option, exchange all or part of the rights for Key common stock at an exchange ratio of one share of common stock per right.

        Key generally will be entitled to redeem the rights at $0.01 per right at any time prior to the close of business on the tenth business day after there has been a public announcement of the beneficial ownership by any person or group of 15% or more of our common stock. The rights may not be exercised until the board's right to redeem the stock has expired.

        The plan is not intended to prevent a takeover of Key on terms that are in the best interests of its stockholders. Because the rights may be redeemed by the board, the plan will not interfere with any transaction which the board has approved, including the merger with H&P's oil and gas division.

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ITEM 2—MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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.

Financial Results

		For the Three Months Ended March 31,
		2002			2001
		(In thousands, except per share amounts)
Revenues		$	16,365		$	39,771
Net income (loss)			(2,109	)		13,105
	Per share—basic		(0.15	)		0.94
	Per share—diluted		(0.15	)		0.91

Net Income (Loss)

        We incurred a net loss of $2.1 million, or $0.15 per diluted share, for the first quarter of 2002 compared with net income of $13.1 million, or $0.91 per diluted share, for the first quarter of 2001. The net loss includes $4.4 million of charges related to our planned merger with Helmerich & Payne, Inc.'s oil and gas division of $1.2 million, separation pay of $3.0 million and other unusual items of $0.2 million. The decline in income is also attributable to a decrease in revenues to $16.4 million for the first quarter of 2002 compared to $39.8 million for the same period of 2001. Lower oil and gas prices and decreased oil production contributed to the decline in revenues.

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Results of Operations

        Information about oil and gas sales, production volumes and prices are presented in the following table:

		For the Three Months Ended March 31,
		2002		2001
		(In thousands)
Gas sales		$	8,727	$	28,771
Oil sales			7,320		10,703
Plant product sales			211		249
	Total oil and gas sales	$	16,258	$	39,723
Gas volume—Mcf per day			43,591		42,326
Gas price—per Mcf		$	2.22	$	7.55
Oil volume—barrels per day			4,168		4,427
Oil price—per barrel		$	19.51	$	26.86

        Oil and gas sales revenues declined 59 percent, or $23.5 million between the first quarter of 2002 and 2001 to $16.3 million. Compared to a year earlier, gas sales decreased $20.1 million, oil sales decreased $3.4 million and plant product sales were essentially unchanged. The decline was due primarily to lower oil and gas prices during the first quarter of 2002. We produced combined oil and gas volumes of 68.6 MMcfe per day in the first quarter of 2002, a slight decrease from the 68.9 MMcfe per day produced in the first quarter of 2001.

        Driven by significantly lower prices, gas sales decreased $20.1 million, or 70 percent, to $8.7 million. Lower gas prices caused a $20.9 million decrease, partially offset by higher production volume. The average realized gas price for the first quarter of 2002 was $2.22 per Mcf, compared to $7.55 per Mcf during the same three months of 2001. Daily gas production rose three percent to 43.6 MMcf versus 42.3 MMcf in the first quarter of 2001 as a result of production from wells that were completed during 2001.

        Oil sales decreased $3.4 million, or 32 percent, to $7.3 million in the first quarter of 2002 compared to the comparable period in 2001. Approximately $2.8 million of the decrease is related to lower oil prices and the remaining decrease was because of decreased production. We produced an average of 4,168 barrels per day in 2002 compared to 4,427 barrels per day in 2001. We realized an average price of $19.51 per barrel in 2002, compared to $26.86 per barrel in 2001.

        The decline in gas and oil prices is a direct result of many factors, including, geopolitical events, economic growth, Organization of Petroleum Exporting Countries policies, weather, 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.

        As the prices for oil and gas change, the components of our oil and gas sales fluctuate. In the first three months of 2002, our revenues came from the following product mix: 54 percent gas, 45 percent oil, and one percent plant products. This compares to the following mix for the first three months of 2001: 72 percent gas, 27 percent oil, and one percent plant products. On a volumetric basis, we produced 64 percent gas and 36 percent oil in 2002. Production for the same period of 2001 was 61 percent gas and 39 percent oil.

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Costs and Expenses

        Depreciation, depletion and amortization expense (DD&A) decreased eight percent between the first quarter of 2002 and 2001. On a unit of production basis, DD&A was $1.28 per Mcfe in the first quarter of 2002 compared to $1.39 per Mcfe for the same period in 2001. The decline is a result of a lower basis in our net oil and gas properties as a result of a full cost ceiling write-down recorded in 2001. Effective January 1, 2001, 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. DD&A for 2001 has been restated to reflect this change. We also include a small amount of fixed asset depreciation and amortization of financing costs associated with our credit facility in this income statement line.

        The risk that we will be required to write-down the carrying value of our oil and gas properties increases when oil and gas prices are depressed or if we have substantial downward revisions in our estimated proved reserves. Based on oil and gas prices in effect on March 31, 2002 and 2001, we were not required to record a full cost ceiling write-down in the first three months of 2002 or 2001. Because of the volatility of oil and gas prices, no assurance can be given that we will not experience a ceiling test write-down in future quarterly periods.

        Our lease operating expense (LOE) increased 12 percent between the first quarter of 2002 and the same period of 2001. On a unit of production basis, first quarter LOE increased to $0.70 per Mcfe in 2002 from $0.62 per Mcfe in 2001. First quarter 2002 LOE included $0.5 million of workover expense, or $0.08 per Mcfe, compared to first quarter 2001 workover expense of $0.3 million, or $0.05 per Mcfe. Excluding workover expenses, our routine operating expenses on a unit of production basis would be $0.62 and $0.57 per Mcfe for the first quarter of 2002 and 2001, respectively. LOE also increased because: 1) we paid expenses on more wells (19 net wells) as a result of our 2001 drilling program, 2) we did more workovers, repairs and maintenance to boost production, and 3) we experienced rising costs from our suppliers.

        Production taxes for the first three months of 2002 decreased 60 percent to $1.0 million from $2.5 million last year. The tax for 2002 equates to 6.2 percent of oil and gas sales, or $0.16 per Mcfe. This compares to 6.3 percent of oil and gas sales, or $0.40 per Mcfe in 2001. The decline in production taxes for the quarter was a result of the 59 percent decrease in oil and gas sales due to lower oil and gas prices.

        General and administrative (G&A) expense increased 563 percent between the first quarter of 2002 and 2001. On a unit basis, first quarter G&A increased to $0.91 per Mcfe compared to $0.14 per Mcfe for the comparable period in 2001 primarily due to noncompete and separation pay of $3.0 million, charges related to our proposed merger with the oil and gas division of Helmerich & Payne, Inc. of $1.2 million, and other unusual items of $0.2 million. Excluding these charges, G&A on a unit of production basis would be $0.20 per Mcfe for the first quarter of 2002. The additional increase in G&A is a consequence of increased rent at our Denver headquarters of $0.02 per Mcfe and higher employee compensation and benefit expense. We have added five employees since March 2001 owing to increased activity and the Columbus acquisition in December 2000. As prescribed by the full cost accounting rules, we capitalize direct overhead related to exploration and development activities.

        Interest expense before capitalization was $0.3 million and $0.7 million for the first three months of 2002 and 2001, respectively. We capitalized interest of $0.1 million and $0.4 million in 2002 and 2001, respectively. The capitalized amounts were for borrowings associated with undeveloped leases. We paid less interest in the first three months of 2002 because of average lower interest rates. Our average interest rate at March 31, 2002 was 2.9 percent compared to 6.2 percent at March 31, 2001.

        Income tax benefit totaled $0.6 million for the first three months of 2002 versus income tax expense of $8.8 million a year earlier. Tax (benefit) expense was calculated using a combined federal

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and state effective income tax rate of 38.5 percent in 2002 and 2001, adjusted for items that are non-deductible for income tax purposes.

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 our 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 $4.6 million in the first three months of 2002, a decrease of 86 percent compared to the same period of 2001. Most of the decrease was the result of lower oil and gas prices in 2002 compared to 2001.

        Cash expenditures for exploration and development (E&D) in the first quarter of 2002 totaled $9.4 million. In the quarter ended March 31, 2002, we participated in drilling 4 gross wells, with an overall success rate of 50 percent, or 79 percent on a net well basis. In the first three months of 2001, we made cash expenditures for E&D of $26.1 million, or 82 percent of cash from operating activities.

        During the first quarter of 2002, we borrowed $3.5 million and then later paid down $3.5 million to maintain our debt balance at the December 31, 2001 level. At March 31, 2002, we had outstanding debt of $34 million and $76 million of unused borrowing capacity under our existing bank credit facility.

        The credit facility 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 $7.3 million 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.

        At March 31, 2002, we had commitments on oil and gas wells approved for drilling or in the process of being drilled at March 31, 2002 of approximately $2.0 million. We also had lease commitments for office space totaling $0.5 million for the remainder of 2002. All of the commitments were routine and were made in the normal course of our business. 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.

Critical Accounting Policies

        We rely on management estimates and assumptions 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. Each quarter end, proved oil and gas reserve quantities are based on estimates prepared by Key's engineers, in accordance with guidelines established by the SEC. Ryder Scott Company, L.P., independent petroleum engineers, audits our oil and gas reserve estimates each year end. Reserve engineering is a subjective process of estimating underground accumulations of natural gas and crude

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oil. There are numerous uncertainties inherent in estimating quantities of proved reserves, projecting future rates of production and the timing of development expenditures. Future oil and gas prices may vary significantly from the prices in effect as of March 31, 2002. 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 net carrying 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. Such a decline in reserves may result from lower market prices, which may make it non-economic to drill for and produce higher cost wells.

        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 current accounting method 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 decrease net income by $1.8 million, net of income taxes of $1.1 million, or $0.12 per diluted share. The financial results for the three months ended March 31, 2001 have been restated to reflect this change and as a result, all periods are presented on a comparable basis.

        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 March 31, 2002, we were not required to record a full cost ceiling limitation.

        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

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changes. If we decide to use derivative arrangements in the future, they could have a significant impact, positive or negative, on our results of operations and cash flows.

Recent Accounting Pronouncements

        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. Key will adopt SFAS No. 143 on January 1, 2003. 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 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 adopted SFAS No. 144 on January 1, 2002. There was no impact on our financial statements on the adoption of this statement.

Future Trends and Significant Events

        We currently anticipate exploration and development expenditures of $55 to $60 million in 2002 and that the risk profile of the wells drilled will be more heavily weighted towards exploration than the recent past. The amount and allocation of our future capital expenditures depends 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 to the extent necessary.

        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 shareholders will receive 26,571,321 shares of Cimarex common stock upon distribution in the pro rata spin-off of Cimarex (Spin-off). Immediately thereafter, each share of common stock of Key will be exchanged for one share of Cimarex common stock and Merger Sub will be merged with and into Key, with Key as the surviving subsidiary (Merger) of Cimarex.

        Upon completion of the transaction, holders of H&P common stock will own approximately 65 percent and Key shareholders will own approximately 35 percent of the common stock of Cimarex, in each case on a 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.

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        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.

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ITEM 3—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.

        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 March 31, 2002, we had $34 million of debt outstanding at an average interest rate of 2.85 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 for the remainder of 2002, a ten percent change in the average interest rate would impact annual interest expense by approximately $73,000. As the interest rate is variable and is reflective of current market conditions, the carrying value of our debt approximates its fair value.

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PART II—OTHER INFORMATION

ITEM 6—EXHIBITS AND REPORTS ON FORM 8-K

(a)

Exhibits:

None.

(b)

Reports on Form 8-K:

On February 19, 2002, the Company filed a report on Form 8-K. The Form 8-K announced a ceiling test writedown and production and reserve information for the quarter ended December 31, 2001.

On February 25, 2002, the Company filed a report on Form 8-K. The Form 8-K announced the proposed merger between Key and Helmerich & Payne's oil and gas division.

On March 13, 2002, the Company filed a report on Form 8-K. The Form 8-K announced earnings for the quarter and year ended December 31, 2001.

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SIGNATURE

        Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

May 13, 2002
	KEY PRODUCTION COMPANY, INC.
	/s/  PAUL KORUS      Paul Korus Vice President and Chief Financial Officer (Principal Financial Officer)
	/s/  DAVID W. HONEYFIELD      David W. Honeyfield Controller and Chief Accounting Officer (Principal Accounting Officer)

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