Key Production 10-Q 2002 Q2 Quarterly report

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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 June 30, 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 June 30, 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

		Page
PART I
Item 1—	Financial Statements
	Consolidated statements of operations (unaudited) for the three and six months ended June 30, 2002 and June 30, 2001	3
	Consolidated statements of cash flows (unaudited) for the six months ended June 30, 2002 and June 30, 2001	4
	Consolidated balance sheets (unaudited) as of June 30, 2002 and December 31, 2001	5
	Consolidated statement of stockholders' equity (unaudited) for the six months ended June 30, 2002	6
	Notes to consolidated financial statements	7
Item 2—	Management's Discussion and Analysis of Financial Condition and Results of Operations	12
Item 3—	Quantitative and Qualitative Disclosures About Market Risk	19
PART II
Item 6—	Exhibits and Reports on Form 8-K	20

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.

2

KEY PRODUCTION COMPANY, INC.

Consolidated Statements of Operations

(Unaudited)

				For the Three Months Ended June 30,						For the Six Months Ended June 30,
				2002			2001			2002			2001
				(In thousands, except per share data)
Revenues:
	Gas sales			$	12,107		$	19,700		$	20,834		$	48,471
	Oil sales				9,129			9,789			16,449			20,492
	Plant product sales				299			388			510			637
	Other				39			9			146			57
					21,574			29,886			37,939			69,657
Operating expenses:
	Depreciation, depletion and amortization				8,583			9,566			16,496			18,170
	Lease operating				4,034			4,341			8,342			8,193
	Production taxes				1,329			1,845			2,333			4,331
	General and administrative				2,142			847			7,784			1,698
	Financing costs:
		Interest expense			341			500			639			1,193
		Capitalized interest			(98	)		(306	)		(179	)		(657	)
		Interest income			(8	)		(47	)		(18	)		(120	)
					16,323			16,746			35,397			32,808
Income before income tax expense					5,251			13,140			2,542			36,849
Income tax expense					1,729			5,059			1,129			13,838
Income before cumulative effect of change in accounting method					3,522			8,081			1,413			23,011
Cumulative effect of change in accounting method, net of income taxes					—			—			—			(1,825	)
			Net income	$	3,522		$	8,081		$	1,413		$	21,186
Earnings per share:
	Basic:
		Income before cumulative effect of change in accounting method		$	0.25		$	0.58		$	0.10		$	1.65
		Cumulative effect of change in accounting method, net of income taxes			—			—			—			(0.13	)
			Net income	$	0.25		$	0.58		$	0.10		$	1.52
	Diluted:
		Income before cumulative effect of change in accounting method		$	0.24		$	0.56		$	0.10		$	1.60
		Cumulative effect of change in accounting method, net of income taxes			—			—			—			(0.13	)
			Net income	$	0.24		$	0.56		$	0.10		$	1.47
Weighted average basic shares					14,080			13,977			14,069			13,969
Weighted average diluted shares					14,413			14,450			14,371			14,400

See accompanying notes to consolidated financial statements.

3

KEY PRODUCTION COMPANY, INC.

Consolidated Statements of Cash Flows

(Unaudited)

				For the Six Months Ended June 30,
				2002			2001
				(In thousands)
Cash flows from operating activities:
	Net income			$	1,413		$	21,186
	Adjustment to reconcile net income to net cash provided by operating activities:
		Depreciation, depletion and amortization			16,496			18,170
		Cumulative effect of change in accounting method			—			2,968
		Deferred income taxes			1,054			6,101
		Common stock issued as compensation			233			112
		Amortization of unearned compensation			93			80
		Income tax benefit related to stock options exercised			18			235
	Changes in operating assets and liabilities:
		Increase in receivables			(1,835	)		(259	)
		Decrease in prepaid expenses and other			202			379
		Increase (decrease) in accounts payable and accrued expenses			835			(328	)
		Increase (decrease) in other liabilities			(254	)		29
			Net cash provided by operating activities		18,255			48,673
Cash flows from investing activities:
	Oil and gas exploration and development expenditures				(20,712	)		(43,529	)
	Acquisition of oil and gas properties				(560	)		(119	)
	Proceeds from sale of oil and gas properties				—			1
	Other capital expenditures				(333	)		(230	)
			Net cash used by investing activities		(21,605	)		(43,877	)
Cash flows from financing activities:
	Long-term borrowings				—			2,000
	Payments on long-term debt, net				(1,000	)		(12,000	)
	Payments to reacquire common stock				—			(9	)
	Net proceeds from issuance of common stock				387			380
			Net cash used by financing activities		(613	)		(9,629	)
Net decrease in cash and cash equivalents					(3,963	)		(4,833	)
Cash and cash equivalents at beginning of year					5,003			6,746
Cash and cash equivalents at end of period				$	1,040		$	1,913

See accompanying notes to consolidated financial statements.

4

KEY PRODUCTION COMPANY, INC.

Consolidated Balance Sheets

(Unaudited)

		June 30, 2002			December 31, 2001
		(In thousands, except share data)
Assets
Current assets:
	Cash and cash equivalents	$	1,040		$	5,003
	Receivables		15,192			13,357
	Prepaid expenses and other		1,961			2,163
			18,193			20,523
Oil and gas properties, on the basis of full cost accounting:
	Proved properties		413,645			390,794
	Unproved properties and properties under development, not being amortized		14,032			11,961
			427,677			402,755
	Less—accumulated depreciation, depletion and amortization		(223,292	)		(207,139	)
			204,385			195,616
Other assets, net			1,519			1,529
		$	224,097		$	217,668
Liabilities and Stockholders' Equity
Current liabilities:
	Accounts payable	$	13,626		$	13,210
	Accrued exploration and development		6,128			2,478
	Accrued lease operating expense and other		982			467
	Current portion of long-term debt		33,000			4,857
			53,736			21,012
Long-term debt			—			29,143
Deferred income taxes			33,753			32,699
Other liabilities			333			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		70,537			69,924
	Unearned compensation		(266	)		(278	)
	Retained earnings		62,484			61,071
			136,275			134,227
		$	224,097		$	217,668

See accompanying notes to consolidated financial statements.

5

KEY PRODUCTION COMPANY, INC.

Consolidated Statement of Stockholders' Equity

For the Six Months Ended June 30, 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 income	—			—			—			—			1,413		1,413
Common stock issued for options exercised	40			10			377			—			—		387
Stock option compensation	—			—			233			—			—		233
Income tax benefit from stock options exercised	—			—			18			—			—		18
Common stock withheld from options exercised	(6	)		(1	)		(95	)		—			—		(96	)
Unearned compensation related to restricted stock awards	5			1			80			(81	)		—		—
Amortization of unearned compensation	—			—			—			93			—		93
Balance, June 30, 2002	14,080		$	3,520		$	70,537		$	(266	)	$	62,484	$	136,275

See accompanying notes to consolidated financial statements.

6

KEY PRODUCTION COMPANY, INC.

Notes to Consolidated Financial Statements

June 30, 2002

(Unaudited)

1. Basis of Presentation

        The accompanying financial statements are unaudited and were prepared from the Company's records. We believe 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 and six months ended June 30, 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 $0.13 per diluted share for the six months ended June 30, 2001. The effect of the change was to decrease net income for the three months ended June 30, 2001 by $1.4 million, $0.8 million net of income taxes, or $0.06 per diluted share. The effect of the change was to increase net income for the six months ended June 30, 2001 by $1.3 million, $0.8 million net of income taxes, or $0.06 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

7

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 stockholders 26,591,321 shares of Cimarex common stock upon distribution in the pro rata spin-off of Cimarex (Spin-off). Immediately thereafter, Merger Sub will be merged with and into Key, with Key as the surviving subsidiary of Cimarex (Merger) and each share of our common stock will be exchanged for one share of Cimarex common stock.

        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 unanimously approved by the respective Boards of Directors of Key and H&P. In July 2002, H&P received a ruling from the Internal Revenue Service qualifying the Spin-off as a tax-free transaction. The Merger is subject to, among other things, the completion of the Spin-off and the approval of our stockholders. The Merger is anticipated to close prior to the end of September 2002.

3. Long-Term Debt

        We have a long-term credit agreement with a group of banks led by Bank of America, N.A. that was amended as of May 31, 2002 to extend the revolving facility to be payable in full on December 31, 2002. The agreement provides for a maximum loan amount of $150 million limited to a borrowing base. Our borrowing base was $90 million at June 30, 2002. 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 June 30, 2002, we had $33 million outstanding and $57 million unused and available on the credit facility. The amended credit agreement has a maturity date of December 31, 2002 and as such, we have classified the loan as current at June 30, 2002.

        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 June 30, 2002.

8

4. Income Taxes

        Income tax expense (benefit) consisted of the following:

		Three Months Ended June 30,					Six Months Ended June 30,
		2002			2001		2002		2001*
		(In thousands)
Current taxes:
	Federal	$	(53	)	$	2,304	$	73	$	5,995
	State		(14	)		165		2		599
			(67	)		2,469		75		6,594
Deferred taxes			1,796			2,590		1,054		7,244
		$	1,729		$	5,059	$	1,129	$	13,838

*

Excludes the $1.1 million tax benefit related to the cumulative effect of the change in accounting method.

5. Supplemental Disclosure of Cash Flow Information

		For the Six Months Ended June 30,
		2002		2001
		(In thousands)
Cash paid during the period for:
	Interest (net of amounts capitalized)	$	461	$	562
	Income taxes (net of refunds received)	$	365	$	4,328

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6. Earnings Per Share

        The calculations of basic and diluted net income per common share for the periods ended June 30, 2002 and 2001 are presented in the table below:

		Three Months Ended June 30,				Six Months Ended June 30,
		2002		2001		2002		2001
		(In thousands, except per share data)
Basic earnings per share:
	Income available to common stockholders	$	3,522	$	8,081	$	1,413	$	21,186
	Weighted average basic shares outstanding		14,080		13,977		14,069		13,969
	Basic earnings per share	$	0.25	$	0.58	$	0.10	$	1.52
Diluted earnings per share:
	Income available to common stockholders	$	3,522	$	8,081	$	1,413	$	21,186
	Incremental shares assuming the exercise of stock options		333		473		302		431
	Weighted average diluted shares outstanding		14,413		14,450		14,371		14,400
	Diluted earnings per share	$	0.24	$	0.56	$	0.10	$	1.47

        All stock options outstanding as of June 30, 2002 and 2001 were considered dilutive and included in the calculation for the incremental shares assuming exercise of the stock options.

7. Stock Plans

Stockholder Rights Plan

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

        In adopting the plan, the board declared a dividend of one common share purchase right for each outstanding share of common stock of Key, payable to our 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 our 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 acquisition of

10

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 our stockholders. Because the rights may be redeemed by the board, the plan will not interfere with any transaction which the board has approved, and the merger with H&P's oil and gas division will not trigger a distribution under the plan.

Stock Options

        We periodically grant stock options under stockholder approved stock option plans. In the six months ended June 30, 2002 and 2001, 40,000 and 41,108 stock options were exercised. No stock options were granted during these periods. We accelerated the vesting of 40,000 stock options, which resulted in compensation expense of $233,000 for the six months ended June 30, 2002. As of June 30, 2002 and December 31, 2001, there were 788,834 and 828,834 stock options outstanding. The proposed merger with Cimarex will constitute a change in control of Key. As a result, all unvested stock options will immediately vest upon the closing of the merger.

Restricted Stock Grants

        Key has an employee retention program where we award restricted stock grants to certain employees. There were 31,000 and 26,000 shares of restricted stock outstanding as of June 30, 2002 and December 31, 2001, respectively. The restrictions related to these stock grants are associated with the continued employment of the grantee for three years from the date of the grant; at which time these shares will vest. A grant of 10,000 restricted shares was made in September 1999, grants totaling 16,000 restricted shares were made in January 2001 and a grant of 5,000 restricted shares was made in January 2002 to executive and non-executive personnel. The restricted stock agreements provide that, during the vesting period, if we pay a dividend on our common stock, the grantees will be entitled to receive such dividend. We do not currently pay dividends on our common stock.

        Compensation expense is based upon the difference between the market price of the restricted stock and the price the employees paid for the restricted stock (zero in each of these cases) multiplied by the number of shares of restricted stock granted. Compensation cost is being recognized over the period that ends when all risks of forfeiture have passed. Compensation expense is amortized on a straight-line basis over the three year vesting period.

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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 June 30,				For the Six Months Ended June 30,
		2002		2001		2002		2001
		(In thousands, except per share amounts)
Revenues		$	21,574	$	29,886	$	37,939	$	69,657
Net income			3,522		8,081		1,413		21,186
	Per share—basic		0.25		0.58		0.10		1.52
	Per share—diluted		0.24		0.56		0.10		1.47

Net Income

        We generated net income of $3.5 million, or $0.24 per diluted share, for the second quarter of 2002 compared with net income of $8.1 million, or $0.56 per diluted share, for the second quarter of 2001. For the first six months of 2002, net income was $1.4 million, or $0.10 per diluted share, compared to net income of $21.2 million, or $1.47 per diluted share, for the same period in 2001. The year-to-date 2002 net income includes $5.2 million of charges including charges for our planned merger with Helmerich & Payne, Inc.'s (H&P) oil and gas division of $1.7 million, separation pay of $3.3 million and other unusual items of $0.2 million. The decrease in income is also the result of a 46 percent decline in revenues due to lower oil and gas prices. The decline in income for the second quarter is attributable to a decrease in revenues to $21.6 million for the second quarter of 2002 compared to $29.9 million for the same period of 2001.

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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 June 30,				For the Six Months Ended June 30,
		2002		2001		2002		2001
		(In thousands)
Gas sales		$	12,107	$	19,700	$	20,834	$	48,471
Oil sales			9,129		9,789		16,449		20,492
Plant product sales			299		388		510		637
	Total oil and gas sales	$	21,535	$	29,877	$	37,793	$	69,600
Gas volume—Mcf per day			43,411		44,418		43,500		43,378
Gas price—per Mcf		$	3.06	$	4.87	$	2.65	$	6.17
Oil volume—barrels per day			4,222		4,150		4,195		4,288
Oil price—per barrel		$	23.76	$	25.92	$	21.66	$	26.40

        Oil and gas sales declined 28 percent, or $8.3 million between the second quarter of 2002 and 2001 to $21.5 million. Compared to a year earlier, gas sales decreased $7.6 million, oil sales decreased $0.7 million and plant product sales were essentially unchanged. The decline was due primarily to lower oil and gas prices during the second quarter of 2002. We produced combined oil and gas volumes of 68.7 MMcfe per day in the second quarter of 2002, a slight decrease from the 69.3 MMcfe per day produced in the second quarter of 2001.

        For the six months ended June 30, 2002, oil and gas sales dropped by $31.8 million, or 46 percent, to $37.8 million compared to the first six months of 2001. Gas sales declined $27.6 million, oil sales decreased $4.1 million and plant products decreased $0.1 million. Consistent with the quarter results, reduced oil and gas prices resulted in the decreased revenues. Combined oil and gas production volumes were 68.7 MMcfe per day in the first six months of 2002 compared to 69.1 MMcfe per day in the first two quarters of 2001.

        Driven by lower prices in the second quarter of 2002, gas sales decreased $7.6 million, or 39 percent, as compared to $12.1 million in the same quarter of 2001. Lower gas prices caused $7.2 million of the decrease and slightly lower production volume resulted in the remaining $0.4 million decrease. The average realized gas price for the second quarter of 2002 was $3.06 per Mcf, compared to $4.87 per Mcf during the same three months of 2001. Daily gas production declined two percent to 43.4 MMcf versus 44.4 MMcf in the second quarter of 2001. The slight fall in daily gas production is due to natural declines in wells in the Mid-continent region, partially offset by production from wells that were completed since June 30, 2001.

        Gas sales for the first six months of 2002 of $20.8 million were also impacted by significantly lower gas prices. Gas prices decreased to $2.65 per Mcf in 2002 from $6.17 per Mcf in 2001 causing a $27.7 million decline in sales. Gas production was relatively constant at 43.5 Mcf per day in 2002 compared to 43.4 Mcf per day in 2001.

        Oil sales decreased $0.7 million, or seven percent, to $9.1 million in the second quarter of 2002 compared to the same period in 2001. Approximately $0.8 million of the decrease is related to lower oil prices partially offset by $0.1 million increase in oil production. We produced an average of 4,222 barrels per day in 2002 compared to 4,150 barrels per day in 2001. We realized an average price of $23.76 per barrel in second quarter of 2002, compared to $25.92 per barrel in the second quarter of 2001.

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        Oil sales decreased $4.1 to $16.4 million in the first six months of 2002 compared to $20.5 million in the same period of 2001. Average oil prices declined to $21.66 per barrel in 2002 from $26.40 per barrel in 2001 resulting in $3.6 million of the decrease. Daily oil production was 4,195 barrels per day, a two percent decline from the 4,288 barrels per day produced in 2001.

        The decline in gas and oil prices is a 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 six months of 2002, our revenues came from the following product mix: 55 percent gas, 44 percent oil, and one percent plant products. This compares to the following mix for the first six months of 2001: 70 percent gas, 29 percent oil, and one percent plant products. On a volumetric basis, we produced 63 percent gas and 37 percent oil in 2002 and 2001.

Costs and Expenses

        Depreciation, depletion and amortization expense (DD&A) decreased ten percent between the second quarter of 2002 and 2001. On a unit of production basis, DD&A was $1.37 per Mcfe in the second quarter of 2002 compared to $1.52 per Mcfe for the same period in 2001. DD&A for the six months ended June 30, 2002 decreased nine percent to $1.33 per Mcfe compared to $1.45 per Mcfe for the same period in 2001. The declines are a result of a lower basis in our net oil and gas properties as a result of a full cost ceiling write-down recorded at the end of 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 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 June 30, 2002 and 2001, we were not required to record a full cost ceiling write-down in the first six 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) decreased seven percent between the second quarter of 2002 and the same period of 2001. On a unit of production basis, second quarter LOE decreased to $0.65 per Mcfe in 2002 from $0.69 per Mcfe in 2001. Second quarter 2002 LOE included $0.4 million of workover expense, or $0.06 per Mcfe, compared to second quarter 2001 workover expense of $0.7 million, or $0.11 per Mcfe. Excluding workover expenses, our routine operating expenses on a unit of production basis would be $0.59 and $0.58 per Mcfe for the second quarter of 2002 and 2001, respectively.

        For the six months, LOE increased by two percent between 2002 and 2001. Compared on a unit of production basis, year to date expenses increased to $0.67 per Mcfe in 2002 from $0.66 per Mcfe in 2001. General LOE increased $0.4 million, partially offset by a $0.3 million decrease in workover expenses and ad valorem taxes.

        Production taxes for the second quarter of 2002 decreased 28 percent to $1.3 million from $1.8 million last year. The tax for 2002 equates to 6.3 percent of oil and gas sales, or $0.21 per Mcfe. This compares to 6.3 percent of oil and gas sales, or $0.29 per Mcfe in 2001. The decline in production taxes, on a unit of production basis, for the quarter was a result of the 28 percent decrease in oil and gas sales due to lower oil and gas prices. Production taxes for the first six months of 2002 and 2001

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were 6.3 percent of oil and gas sales, or $0.19 per Mcfe and $0.35 per Mcfe, respectively. The decrease on a per unit basis is the result of lower oil and gas prices.

        General and administrative expense (G&A) increased 153 percent between the second quarter of 2002 and 2001. On a unit basis, second quarter G&A increased to $0.34 per Mcfe compared to $0.13 per Mcfe for the comparable period in 2001 primarily due to separation pay of $0.3 million and charges related to our proposed merger with H&P's oil and gas division of $0.5 million. Excluding these charges, G&A on a unit of production basis would be $0.22 per Mcfe for the second quarter of 2002. G&A for the two quarters of 2002 increased 358% to $0.63 per Mcfe compared to $0.14 per Mcfe in 2001. The increase includes $5.2 million of charges, or $0.42 per Mcfe, including charges for our planned merger with H&P's oil and gas division of $1.7 million, separation pay of $3.3 million and other unusual items of $0.2 million. 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 ten employees since June 2001 owing to increased activity and the proposed merger with Cimarex. The cost of our health insurance benefits also increased approximately 50 percent.

        Interest expense before capitalization was $0.3 million and $0.5 million for the second quarter of 2002 and 2001, respectively. We capitalized interest of $0.1 million and $0.3 million in 2002 and 2001, respectively. Interest expense before capitalization was $0.6 million and $1.2 million for the first six months of 2002 and 2001, respectively. We capitalized interest of $0.2 and $0.7 million in each of those periods. The capitalized amounts were for borrowings associated with undeveloped leases. We paid less interest in the first six months of 2002 because of average lower interest rates. Our average interest rate at June 30, 2002 was 3.1 percent compared to 5.1 percent at June 30, 2001.

        Income tax expense totaled $1.1 million for the first six months of 2002 versus $13.8 million a year earlier. Tax expense was calculated using a combined federal 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 $18.3 million in the first six months of 2002, a decrease of 62 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 $20.7 million. In the six months ended June 30, 2002, we participated in drilling 21 gross wells, with an overall success rate of 76 percent, or 71 percent on a net well basis. In the first six months of 2001, we made cash expenditures for E&D of $43.5 million.

        During the first six months of 2002, we paid down $1.0 million to reduce our debt balance from the December 31, 2001 level. At June 30, 2002, we had outstanding debt of $33 million and $57 million of unused borrowing capacity under our existing bank credit facility. The credit facility has a maturity date of December 31, 2002. As such, we have classified the loan as current on our balance sheet.

        Following the merger with H&P's oil and gas division, the primary sources of liquidity are expected to be cash provided by operating activities, bank financing and access to other public and private markets for either debt or equity capital.

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        We are currently in negotiations with a lead arranger to procure a $400 million secured revolving credit facility for the combined companies. Management expects that this facility would close shortly following the completion of the merger. We expect to ask the lead arranger on the revolving credit facility to initially seek commitments of only $200 million.

        At June 30, 2002, we had commitments on oil and gas wells approved for drilling or in the process of being drilled at June 30, 2002 of approximately $3.6 million. We also had lease commitments for office space totaling $0.4 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. 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 June 30, 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. 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.

        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.

        Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes (1) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any, and (2) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data.

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        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 $0.13 per diluted share for the six months ended June 30, 2001. The financial results for the three and six months ended June 30, 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 June 30, 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 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 Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standard (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. We are currently assessing the impact of this statement on our financial statements.

        In July 2002, the FASB issued SFAS No. 146,Accounting for Costs Associated with Exit or Disposal Activities. SFAS No. 146 is to be applied prospectively to exit or disposal activities initiated after December 31, 2002. The standard requires companies to recognize costs associated with exit or disposal activities when they are incurred rather than at the date of a commitment to an exit or disposal plan. Examples of costs covered by the standard include lease termination costs and certain employee severance costs that are associated with a restructuring, discontinued operation, plant closing, or other exit or disposal activity. We have not yet assessed whether this will have an impact on Key.

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Future Trends and Significant Events

        On February 23, 2002, Key, 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 stockholders 26,591,321 shares of Cimarex common stock upon distribution in the pro rata spin-off of Cimarex (Spin-off). Immediately thereafter, Merger Sub will be merged with and into Key, with Key as the surviving subsidiary of Cimarex (Merger) and each share of our common stock will be exchanged for one share of Cimarex common stock.

        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 unanimously approved by the respective Boards of Directors of Key and H&P. In July 2002, H&P received a ruling from the Internal Revenue Service qualifying the Spin-off as a tax-free transaction. The Merger is subject to, among other things, the completion of the Spin-off and the approval of our stockholders. The Merger is anticipated to close prior to the end of September 2002. Cimarex also plans to change to a fiscal year that ends on December 31 versus the September 30 year-end presently used by Cimarex.

        As we move forward with the planned merger with Cimarex, we anticipate exploration and development expenditures of approximately $20 to $25 million for the last half of 2002. The amount and allocation of our future capital expenditures depends on a number of factors, including the impact of oil and gas prices on available cash flow and investment opportunities, availability of rigs, the availability of debt and equity capital, the availability of attractive drilling opportunities and the rate in which we evaluate these opportunities and our drilling success. 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.

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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 June 30, 2002, we had $33 million of debt outstanding at an average interest rate of 3.09 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 $51,000. 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:



10.1

Third Amendment to Credit Agreement, dated as of May 31, 2002, among Key Production Company, Inc., Bank of America, N.A., as Agent, and the Lenders under the Credit Agreement.



10.2

Employment Agreement, dated September 7, 1999, by and between Paul Korus and Key Production Company, Inc.



10.3

Employment Agreement, dated October 25, 1993, by and between Thomas E. Jorden and Key Production Company, Inc.



10.4

Employment Agreement, dated February 2, 1994, by and between Stephen P. Bell and Key Production Company, Inc.



10.5

Employment Agreement, dated March 11, 1994, by and between Joseph R. Albi and Key Production Company, Inc.



10.6

Employment Agreement, dated March 20, 2002, by and between David Honeyfield and Key Production Company, Inc.



99.1

Certification of F.H. Merelli, Chief Executive Officer of Key Production Company, Inc. Pursuant to 18 U.S.C. Section 1350.



99.2

Certification of Paul Korus, Chief Financial Officer of Key Production Company, Inc. Pursuant to 18 U.S.C. Section 1350.




(b)

Reports on Form 8-K:

On April 24, 2002, the Company filed a report on Form 8-K. The Form 8-K announced its teleconference and updated guidance.

On May 7, 2002, the Company filed a report on Form 8-K. The Form 8-K announced financial results for the quarter ended March 31, 2002.

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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.

August 13, 2002

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

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QuickLinks

KEY PRODUCTION COMPANY, INC. Table of Contents
KEY PRODUCTION COMPANY, INC. Consolidated Statements of Operations (Unaudited)
KEY PRODUCTION COMPANY, INC. Consolidated Statements of Cash Flows (Unaudited)
KEY PRODUCTION COMPANY, INC. Consolidated Balance Sheets (Unaudited)
KEY PRODUCTION COMPANY, INC. Consolidated Statement of Stockholders' Equity For the Six Months Ended June 30, 2002 (Unaudited)
KEY PRODUCTION COMPANY, INC. Notes to Consolidated Financial Statements June 30, 2002 (Unaudited)

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—OTHER INFORMATION
ITEM 6—EXHIBITS AND REPORTS ON FORM 8-K

SIGNATURE