UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-Q

 

 

Commission File No. 001-31446

 

CIMAREX ENERGY CO.

1700 Lincoln Street, Suite 1800

Denver, Colorado 80203-4518

(303) 295-3995

 

 

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes  ý   No  o

 

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act).  Yes  ý   No  o

 

The number of shares Cimarex Energy Co. common stock outstanding as of June 30, 2004 was 41,393,306.

 

 

CIMAREX ENERGY CO.

 

Table of Contents

 

PART I
Item 1 – Financial Statements
Consolidated balance sheets (unaudited) as of June 30, 2004 and December 31, 2003
Consolidated statements of operations (unaudited) for the three and six months ended June 30, 2004 and 2003
Consolidated statements of cash flows (unaudited) for the six months ended June 30, 2004 and 2003
Consolidated statement of stockholders’ equity (unaudited) for the six months ended June 30, 2004
Notes to consolidated financial statements
Item 2 – Management’s Discussion and Analysis of Financial Condition and Results of Operations
Item 3 – Qualitative and Quantitative Disclosures About Market Risk
Item 4 – Controls and Procedures
PART II
Item 4 - Submission of Matters to a Vote of Security Holders
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) or equivalent million cubic feet (MMcfe). 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

 

PART I

 

ITEM 1 - Financial Statements

 

CIMAREX ENERGY CO.

Consolidated Balance Sheets

(Unaudited)

 

		June 30, 2004			December 31, 2003
		(In thousands, except share data)
Assets
Current assets:
Cash and cash equivalents		$	58,081		$	40,420
Receivables, net		90,353			68,293
Inventories		13,272			6,700
Deferred income taxes		1,557			1,631
Other current assets		4,023			6,160
Total current assets		167,286			123,204
Oil and gas properties at cost, using the full cost method of accounting:
Proved properties		1,443,776			1,331,095
Unproved properties and properties under development, not being amortized		78,030			39,370
		1,521,806			1,370,465
Less – accumulated depreciation, depletion and amortization		(801,803		)	(746,161		)
Net oil and gas properties		720,003			624,304
Fixed assets, net		14,033			12,092
Goodwill		44,967			44,967
Other assets, net		774			941
		$	947,063		$	805,508
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable		$	24,676		$	18,394
Accrued liabilities		67,217			48,339
Revenue payable		34,049			18,776
Total current liabilities		125,942			85,509
Deferred income taxes		180,847			155,293
Other liabilities		32,320			29,966
Stockholders’ equity:
Preferred stock, $0.01 par value, 15,000,000 shares authorized, no shares issued		—			—
Common stock, $0.01 par value, 100,000,000 shares authorized, 41,393,306 and 41,063,653 shares issued and outstanding, respectively		414			411
Paid-in capital		243,752			237,430
Unearned compensation		(8,986		)	(9,540		)
Retained earnings		372,774			306,439
		607,954			534,740
		$	947,063		$	805,508

 

See accompanying notes to consolidated financial statements.

 

3

 

CIMAREX ENERGY CO.

Consolidated Statements of Operations

(Unaudited)

 

		For the Three Months Ended June 30,						For the Six Months Ended June 30,
		2004			2003			2004			2003
		(In thousands, except per share data)
Revenues:
Gas sales		$	90,864		$	59,071		$	165,196		$	130,560
Oil sales		24,450			17,026			45,628			36,698
Marketing sales		53,831			23,230			90,592			68,637
Other		1,048			(57		)	4,696			(66		)
		170,193			99,270			306,112			235,829
Costs and expenses:
Depreciation, depletion and amortization		30,834			20,887			57,172			42,004
Asset retirement obligation accretion		304			255			594			496
Production		9,419			8,155			18,888			15,143
Transportation		2,493			1,896			4,848			3,155
Taxes other than income		9,464			6,147			17,829			13,318
Marketing purchases		53,286			23,105			89,586			68,098
General and administrative		5,133			4,072			9,642			8,139
Stock compensation		484			436			952			902
Financing costs -
Interest expense		280			274			576			696
Capitalized interest		—			(39		)	—			(304		)
Interest income		(102		)	(53		)	(189		)	(82		)
		111,595			65,135			199,898			151,565
Income before income tax expense and cumulative effect of a change in accounting principle		58,598			34,135			106,214			84,264
Income tax expense		22,128			13,095			39,879			32,081
Income before cumulative effect of a change in accounting principle		36,470			21,040			66,335			52,183
Cumulative effect of a change in accounting principle, net of tax		—			—			—			1,605
Net income		$	36,470		$	21,040		$	66,335		$	53,788
Earnings per share:
Basic -
Income before cumulative effect of a change in accounting principle		$	0.88		$	0.51		$	1.60		$	1.26
Cumulative effect of a change in accounting principle, net of tax		—			—			—			0.04
Net income		$	0.88		$	0.51		$	1.60		$	1.30
Diluted -
Income before cumulative effect of a change in accounting principle		$	0.85		0.50			1.56			1.24
Cumulative effect of a change in accounting principle, net of tax		—			—			—			0.04
Net income		$	0.85		$	0.50		$	1.56		$	1.28
Weighted average basic shares outstanding		41,379			41,545			41,342			41,512
Weighted average diluted shares outstanding		42,704			42,246			42,657			42,142

 

See accompanying notes to consolidated financial statements.

 

4

 

CIMAREX ENERGY CO.

Consolidated Statements of Cash Flows

(Unaudited)

 

		For the Six Months Ended June 30,
		2004			2003
		(In thousands)
Cash flows from operating activities:
Net income		$	66,335		$	53,788
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		57,172			42,004
Amortization of restricted stock compensation		952			902
Cumulative effect of a change in accounting principle, net of taxes		—			(1,605		)
Deferred income taxes		27,299			17,727
Asset retirement obligation accretion		594			496
Income tax benefit related to stock options exercised		1,672			673
Other		(6		)	17
Changes in operating assets and liabilities:
(Increase) decrease in receivables, net		(22,060		)	2,009
Increase in inventories		(6,572		)	(1,246		)
(Increase) decrease in other current assets		2,137			(584		)
Increase (decrease) in accounts payable		21,555			(6,087		)
Increase (decrease) in accrued liabilities		(4,743		)	11,452
Increase (decrease) in other non-current liabilities		158			(248		)
Net cash provided by operating activities		144,493			119,298
Cash flows from investing activities:
Oil and gas expenditures		(128,299		)	(56,269		)
Acquisition of proved oil and gas properties		(2		)	(2,169		)
Proceeds from sale of assets		452			164
Other capital expenditures		(3,386		)	(5,887		)
Net cash used by investing activities		(131,235		)	(64,161		)
Cash flows from financing activities:
Payments on long-term debt		—			(32,000		)
Common stock reacquired and retired		(121		)	(5		)
Proceeds from issuance of common stock		4,524			2,031
Net cash provided by (used in) financing activities		4,403			(29,974		)
Net increase in cash and cash equivalents		17,661			25,163
Cash and cash equivalents at beginning of period		40,420			22,327
Cash and cash equivalents at end of period		$	58,081		$	47,490

 

See accompanying notes to consolidated financial statements.

 

5

 

CIMAREX ENERGY CO.

Consolidated Statement of Stockholders’ Equity

For the Six Months Ended June 30, 2004

(Unaudited)

 

		Common Stock					Paid-in Capital			Unearned Compensation			Retained Earnings			Total Shareholders’ Equity
		Shares		Amount
							(In thousands)
Balance, December 31, 2003		41,064		$	411		$	237,430		$	(9,540	)	$	306,439		$	534,740
Net income		—		—			—			—			66,335			66,335
Issuance of restricted stock awards		14		—			400			(400		)	—			—
Inssuance of restricted stock units awards		—		—			—			(312		)	—			(312		)
Common stock reacquired and retired		(5	)	—			(121		)	—			—			(121		)
Shares of restricted stock exchanged for restricted stock units		(5	)	—			(150		)	—			—			(150		)
Amortization of unearned compensation		—		—			—			1,266			—			1,266
Exercise of stock options		325		3			4,521			—			—			4,524
Tax benefit related to stock options exercised		—		—			1,672			—			—			1,672
Balance, June 30, 2004		41,393		$	414		$	243,752		$	(8,986	)	$	372,774		$	607,954

 

See accompanying notes to consolidated financial statements.

 

6

 

CIMAREX ENERGY CO.

 

Notes to Consolidated Financial Statements

 

June 30, 2004

 

(Unaudited)

 

1.                                      Basis of Presentation

 

The accompanying financial statements are unaudited and were prepared from the records of Cimarex Energy Co. (Cimarex or the Company).  We believe these financial statements include all adjustments necessary for a fair presentation of our financial position and results of operations.  We 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 and notes in our Annual Report on Form 10-K for the year ended December 31, 2003.

 

Cimarex was formed in February 2002 as a wholly-owned subsidiary of Helmerich & Payne, Inc. (H&P).  As a result of a dividend declared and paid by H&P on September 30, 2002, in the form of Cimarex common stock, Cimarex was spun-off and became a stand-alone company.  Also on September 30, 2002, Cimarex acquired 100 percent of the outstanding common stock of Key Production Company, Inc. (Key) in a tax-free exchange.

 

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

 

We make certain 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.  Changes in facts and circumstances may result in revised estimates and actual results could differ from those estimates.

 

The more significant areas requiring the use of management’s estimates and judgments relate to preparation of estimated oil and gas reserves, the use of these oil and gas reserves in calculating depletion, depreciation and amortization, the use of the estimates of future net revenues in computing the ceiling test limitations and estimates of abandonment obligations used in such calculations and in recording asset retirement obligations.  Estimates and judgments are also required in determining the reserves for bad debts, the impairments of undeveloped properties, the assessment of goodwill and the valuation of deferred tax assets.

 

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

 

2.                                      Stock Options

 

We apply Accounting Principles Board (APB) Opinion 25, Accounting for Stock Issued to Employees, and related interpretations to account for all stock option grants and grants of restricted stock.  No compensation cost has been recognized for stock options granted as the option prices are equal to the market price of the underlying common stock on the date of grant.

 

7

 

Statement of Financial Accounting Standard (SFAS) No. 123, Accounting for Stock Based Compensation, as amended by SFAS No. 148, Accounting for Stock-Based Compensation-Transition and Disclosure, requires us to provide pro forma information regarding net income as if the compensation cost for our stock option plans had been determined in accordance with the fair value based method prescribed in SFAS No. 123.  In addition, SFAS No. 148 amends the disclosure requirements of SFAS No. 123 to require prominent disclosures in both annual and interim financial statements about the method of accounting for stock-based employee compensation and the effect of the method used on reported results.  To provide the required pro forma information, Cimarex estimated the theoretical fair value of each stock option at the grant date by using the Black Scholes option-pricing model.

 

Had compensation cost for the plan been determined based on the fair value at the grant dates for awards to employees under the plan, consistent with the methodology of SFAS No. 123, pro forma net income would have been as indicated below:

 

These pro forma amounts may not be representative of future disclosures since the estimated fair value of stock options is amortized to expense over the vesting period and additional options may be granted in future years.

 

		Three Months Ended June 30,					Six Months Ended June 30,
		2004			2003		2004		2003
Net income, as reported		$	36,470		21,040		66,335		53,788
Less:  Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects		(538		)	(592	)	(1,075	)	(1,183	)
Pro forma net income		$	35,932		20,448		65,260		52,605
Earnings per share:
Basic – as reported		$	0.88		0.51		1.60		1.30
Basic – pro forma		$	0.87		0.49		1.58		1.27
Diluted – as reported		$	0.85		0.50		1.56		1.28
Diluted – pro forma		$	0.84		0.48		1.53		1.25

 

These pro forma amounts may not be representative of future disclosures since the estimated fair value of stock options is amortized to expense over the vesting period and additional options may be granted in future years.

 

8

 

The following summary reflects the status of stock options granted to employees and directors as of June 30, 2004, and changes during the period:

 

		Options Outstanding		Weighted Average Exercise Price			Options Exercisable
Outstanding as of January 1, 2004		3,321,299		$	14.39
Exercised		324,995		13.96
Outstanding as of June 30, 2004		2,996,304		$	14.44		1,667,367

 

The following table summarizes information about Cimarex stock options held by employees and directors at June 30, 2004:

 

		Outstanding Stock Options
				Weighted-					Exercisable Stock Options
				Average		Weighted-					Weighted-
				Remaining		Average					Average
				Contractual		Exercise					Exercise
Range of Exercise Prices		Options		Life		Price			Options		Price
$6.11 to $8.14		165,685		4.3 Years		$	7.84		165,685		$	7.84
$8.15 to $10.17		138,200		5.2 Years		9.69			138,200		9.69
$10.18 to $12.21		489,434		3.8 Years		11.51			489,434		11.51
$12.22 to $14.25		503,367		6.9 Years		13.78			303,523		13.63
$14.26 to $16.28		336,713		6.4 Years		15.20			232,537		15.20
$16.29 to $18.32		1,313,905		8.2 Years		16.72			312,988		16.83
$18.33 to $20.36		49,000		8.0 Years		19.54			25,000		18.77

 

3.                                      Asset Retirement Obligations

 

On January 1, 2003, we adopted SFAS No. 143, Accounting for Asset Retirement Obligations.  This Statement addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs.  The Statement 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, and that the associated asset retirement costs be capitalized as part of the carrying amount of the long-lived asset.  Oil and gas producing companies incur this liability upon acquiring or drilling a well.

 

9

 

The adoption of the Statement resulted in our recording income reported as a cumulative effect of a change in accounting principle of approximately $1.6 million net of income taxes of $1.0 million.

 

The following table reflects the components of the change in the carrying amount of the asset retirement obligation for the six months ended June 30, 2004 (in thousands):

 

Balance as of January 1, 2004		$	16,463
Liabilities incurred in the current period		1,141
Liabilities settled in the current period		—
Accretion expense		594
Balance as of June 30, 2004		$	18,198

 

4.                                      Long-Term Debt

 

At June 30, 2004, we had no debt outstanding.  We have the capability to borrow on our Senior Secured Revolving Credit Facility led by Bank One, N.A.  This facility presently has a borrowing base of $275 million and we have commitments from our lenders totaling $200 million.  The borrowing base is subject to redetermination each April and October.

 

Borrowings under this facility bear interest at a LIBOR rate plus 1.25 to 2.00 percent, based on borrowing base usage.  Unused borrowings are subject to a commitment fee of 0.375 to 0.50 percent, also depending on the borrowing base usage.

 

The credit facility is secured by mortgages on certain of our oil and gas properties and the stock of our operating subsidiaries.  We are also subject to customary financial and non-financial covenants and are in compliance with those covenants.  The term of the credit facility expires in October 2005.

 

10

 

5.                                      Income Taxes

 

Federal income tax expense for the three and six months ended June 30, 2004 and 2003 differ from the amounts that would be provided by applying the U.S. Federal income tax rate due to the effect of state income taxes and percentage depletion.

 

The components of the provision for income taxes are as follows (in thousands):

 

		Three Months Ended June 30,						Six Months Ended June 30,
		2004			2003			2004			2003
Current taxes		$	5,753		$	7,504		$	12,580		$	14,354
Deferred taxes		16,375			5,591			27,299			17,727
		$	22,128		$	13,095		$	39,879		$	32,081

 

6.                                      Supplemental Disclosure of Cash Flow Information (in thousands):

 

		Three Months Ended June 30,						Six Months Ended June 30,
		2004			2003			2004			2003
Cash paid during the period for:
Interest (net of amounts capitalized)		$	42		$	238		$	475		$	407
Income taxes (net of refunds received)		$	11,346		$	4,519		$	13,052		$	4,775

 

11

 

7.                                      Earnings Per Share

 

The calculations of basic and diluted net earnings per common share are presented below:

 

		Three Months Ended June 30,						Six Months Ended June 30,
(in thousands, except per share data)		2004			2003			2004			2003
Income before cumulative effect of a change in accounting principle		$	36,470		$	21,040		$	66,335		$	52,183
Cumulative effect of a change in accounting principle		—			—			—			1,605
Net income available to common stockholders for basic and diluted		$	36,470		$	21,040		$	66,335		$	53,788
Basic weighted-average shares outstanding		41,379			41,545			41,342			41,512
Incremental shares from assumed exercise of stock options and vesting of restricted stock units		1,325			701			1,315			630
Diluted weighted-average shares outstanding		42,704			42,246			42,657			42,142
Basic:
Before cumulative effect of a change in accounting principle		$	0.88		$	0.51		$	1.60		$	1.26
Cumulative effect of a change in accounting principle		—			—				—			0.04
Earnings per share		$	0.88		$	0.51		$	1.60		$	1.30
Diluted:
Before cumulative effect of a change in accounting principle		$	0.85		$	0.50		$	1.56		$	1.24
Cumulative effect of a change in accounting principle		—			—				—			0.04
Earnings per share		$	0.85		$	0.50		$	1.56		$	1.28

 

There were stock options outstanding for 2,996,304 and 3,421,461 shares of Cimarex common stock at June 30, 2004 and 2003, respectively.  All stock options were considered potentially dilutive securities for the three and six months ended June 30, 2004 and 2003.

 

12

 

8.                                      Segment Information

 

Cimarex operates in the oil and gas industry, and is comprised of an exploration and production segment and a natural gas marketing segment.  Exploration and production activities are located primarily in Oklahoma, Kansas, Texas, Louisiana and California.  We have a wholly owned subsidiary, Cimarex Energy Services, Inc. (CESI) through which we conduct a majority of our gas marketing activity.  Information presented for our natural gas marketing segment represents business conducted with third parties, usually incidental to sales of our own production.

 

Summarized financial information of Cimarex’s reportable segments for the three and six months ended June 30, 2004 and 2003 is shown in the following table:

 

		External Sales			Operating Profit Before Income Taxes			Depreciation, Depletion and Amortization			Total Assets			Additions to Long- Lived Assets
		(In thousands)
Three Months Ended June 30, 2004:
Exploration and Production		$	115,314		$	57,280		$	30,771		$	899,418		$	82,974
Natural Gas Marketing		53,831			448			63			47,645			82
Total		$	169,145		$	57,728		$	30,834		$	947,063		$	83,056
Three Months Ended June 30, 2003:
Exploration and Production		$	76,097		$	34,310		$	20,833		$	709,323		$	36,000
Natural Gas Marketing		23,230			64			54			28,962			5
Total		$	99,327		$	34,374		$	20,887		$	738,285		$	36,005
Six Months Ended June 30, 2004:
Exploration and Production		$	210,824		$	101,058		$	57,049		$	899,418		$	153,241
Natural Gas Marketing		90,592			847			123			47,645			394
Total		$	301,416		$	101,905		$	57,172		$	947,063		$	153,635
Six Months Ended June 30, 2003:
Exploration and Production		$	167,258		$	84,215		$	41,898		$	709,323		$	74,508
Natural Gas Marketing		68,637			425			106			28,962			278
Total		$	235,895		$	84,640		$	42,004		$	738,285		$	74,786

 

13

 

The following table reconciles segment operating profit per the above table to income before taxes as reported on the consolidated statements of operations (in thousands).

 

		Three Months Ended June 30,						Six Months Ended June 30
		2004			2003			2004			2003
Segment operating profit, including depreciation, depletion and amortization		$	57,728		$	34,374		$	101,905		$	84,640
Unallocated amounts:
Other revenue (expense)		1,048			(57		)	4,696			(66		)
Interest expense, net		(178		)	(182		)	(387		)	(310		)
Income before income taxes and cumulative effect of a change in accounting principle		$	58,598		$	34,135		$	106,214		$	84,264

 

9.                                      Commitments and Contingencies

 

Litigation

 

Cimarex is a defendant to certain claims relating to drainage of gas from two properties that it operates. The royalty owner plaintiffs have filed suit on behalf of themselves and a class of allegedly similar situated royalty owners in two 640-acre-spacing units. The plaintiffs allege that the two units have suffered approximately 20 Bcf of gross gas drainage. Cimarex denies that the drainage, if any, was in an amount that significant.  The plaintiffs have stated that the royalty owner class has sustained actual damages of approximately $20 million exclusive of interest and costs. We estimate that the share of such alleged damages attributable to our working interest ownership would total approximately $3.0 million exclusive of interests and costs. Plaintiffs further allege that, as a former operator, Cimarex is liable for all damages attributable to the drainage. We believe that our liability, if any, should not exceed our working interest share of any actual damages attributable to the alleged drainage.  In this regard, the court granted our request to assert third-party claims against all of the other working interest owners.  Our contention is that the other working interest owners should bare responsibility for their respective pro rata shares of damages, if any.  We cannot predict the outcome of this litigation, and accordingly, no accrual has been recorded in connection with this action.

 

Cimarex has other various litigation related matters in the normal course of business, none of which are material, individually or in aggregate.  We are also party to certain litigation as plaintiffs that could result in potential gains of between $.5 million to $1.0 million, net to our interest.  Settlements of $3.0 million, which exceeded our initial estimates, were received in the first quarter of 2004 related to this type of litigation for which we were plaintiffs.  Such amounts were recorded as other income.

 

14

 

Transportation and Gas Deliveries

 

We have one firm transportation contract to transport 10,000 MMBtus per day, at $0.09 per MMBtu through December 31, 2004.  We have a right to extend this contract annually.  The maximum amount that would be payable if deliveries are not made would be $0.2 million.

 

We have also guaranteed delivery of 6.7 Bcf of natural gas from 13 wells over a three-year period as reimbursement for connection costs to a pipeline.  If the minimum delivery is not met, our maximum exposure is approximately $0.5 million.  We have agreed to reimburse another gatherer for connection costs to its pipeline via delivery of 1 Bcf of natural gas per well or a prorated payment based on the total reserves on 19 wells.  The maximum amount that would be payable if no gas is delivered would be $0.6 million.

 

Additionally, we have firm sales contracts to deliver fixed volumes of gas based on an index price.  These contracts are typically one year in length.  As of June 30, 2004, we had an obligation to deliver approximately 1.2 Bcf of natural gas.  If this gas is not delivered our financial commitment would approximate $6.7 million based on index prices as of June 30, 2004.  This commitment will fluctuate due to price volatility and actual volumes delivered.  We believe no financial commitment will be due based on our proved reserves and current production levels.

 

Parental Guarantees

 

As of June 30, 2004, Cimarex had $8.5 million of parental guarantees outstanding.  These guarantee the credit of certain CESI agreements and are for the benefit of certain counterparties.

 

Drilling Commitments

 

The Company has contractual commitments on oil and gas wells approved for drilling or in the process of being drilled at June 30, 2004 of approximately $17.4 million.

 

All of the commitments noted above were routine and made in the normal course of our business.

 

Tax Sharing Agreement

 

On September 30, 2002, Cimarex entered into an agreement with H&P that imposes certain restrictions on Cimarex’s ability to redeem or issue a material number of shares of its common stock or to undergo a change of control.  These restrictions expire on October 1, 2004.  Such actions by Cimarex could cause the spin off of Cimarex by H&P to be deemed a taxable event, potentially resulting in a substantial amount of taxable income to H&P.  Under the terms of the agreement, if Cimarex takes or permits an action to be taken that causes the spin off to be taxable, Cimarex would generally be liable for all or a portion of the resultant tax liability.  It is expected that any such taxes allocated to Cimarex would be material.

 

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Cimarex has also provided indemnification of H&P in connection with any future tax claims that may be made relating to the oil and gas exploration and production assets contributed to Cimarex by H&P.

 

ITEM 2.  MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

 

Throughout this Form 10-Q, we make statements that may be deemed “forward-looking” statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities and Exchange Act of 1934.  These forward-looking statements include, among others, statements concerning Cimarex’s outlook with regard to timing and amount of future production of oil and gas, price realizations, amounts, nature and timing of capital expenditures for exploration and development, plans for funding operations and capital expenditures, drilling of wells, operating costs and other expenses, marketing of oil and gas 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 we receive for our 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. In addition, exploration and development opportunities pursued by Cimarex may not result in productive oil and gas properties.  There are also numerous uncertainties inherent in estimating quantities of proved reserves, projecting future rates of production and the timing of development expenditures.  These and other risks and uncertainties affecting Cimarex are discussed in greater detail in this report and in other filings by Cimarex with the Securities and Exchange Commission.

 

INTRODUCTION

 

Cimarex Energy Co. is an independent oil and gas exploration and production company.  Our primary focus is to explore for and discover new reserves.  To supplement our growth, from time to time we also consider acquisitions and mergers.  Our operations are presently focused in Oklahoma, Texas, Kansas, Louisiana and California.

 

Industry and Economic Factors

 

In managing our business, we must deal with many factors inherent in our industry.  First and foremost is wide fluctuation of oil and gas prices. Historically, oil and gas markets have been cyclical and volatile, with future price movements difficult to predict.  While our revenues are a function of both production and prices, it is wide swings in prices that have most often had the greatest impact on our results of operations.

 

Our operations entail significant complexities.  Advanced technologies requiring highly trained personnel are utilized in both exploration and production.  Even when the technology is properly used, the interpreter still may not know conclusively if hydrocarbons will be present or the rate at which they will be produced.  Exploration is a high-risk activity, often times resulting in no commercially productive reservoirs being discovered.  Moreover, costs associated with operating within the industry are substantial.

 

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The oil and gas industry is highly competitive.  We compete with major and diversified energy companies, independent oil and gas businesses, and individual operators.  In addition, the industry as a whole competes with other businesses that supply energy to industrial and commercial end users.

 

Extensive Federal, state and local regulation of the industry significantly affects our operations.  In particular, our activities are subject to stringent environmental regulations.  These regulations have increased the costs of planning, designing, drilling, installing, operating, and abandoning oil and gas wells and related facilities.  These regulations may become more demanding in the future.

 

Approach to the Business

 

Profitable growth of our assets will largely depend upon our ability to successfully find and develop new proved reserves. To accommodate an overall acceptable rate of growth, we maintain a blended portfolio of low, moderate and higher risk exploration and development projects.  We believe that this approach allows for consistent increases in our oil and gas reserves, while minimizing the chance of failure. To further mitigate risk, we have chosen to seek geologic and geographic diversification by operating in multiple basins. We may also consider the use of transaction-specific hedging of oil and gas prices to reduce price risk.  However, to date the use of hedging has not been implemented.

 

Implementation of our business approach relies on our ability to fund ongoing exploration and development projects with cash flow provided by operating activities and external sources of capital.

 

We project that 2004 exploration and development expenditures will approximate $230-260 million, up from $161 million in 2003.  We are expanding our 2004 program as a result of successful exploration wells drilled in 2003, growth in our western Oklahoma development projects and entry into new basins.  Similar to 2003, a large portion of our 2004 expenditures will be directed to our projects in Oklahoma, Texas and Louisiana. Approximately 60 percent of the 2004 expenditures will be spent in the mid-continent area of Oklahoma and north Texas, with nearly 30 percent to be spent in the coastal regions of Texas, Louisiana and Mississippi. The remainder of our projected expenditures will be focused in California and other western states.

 

Exploration and development expenditures during the second quarter of 2004 totaled $81.6 million, up from $30.4 million for the second quarter of 2003. Year to date, a total of $150.2 million has been incurred. Of these 2004 expenditures, 63 percent ($95.3 million) was invested in projects in the mid-continent area, with 29 percent, or $43.6 million, directed toward prospects in our coastal region areas of focus. In the second quarter of 2004, we participated in drilling 73 gross wells, with an overall success rate of 89 percent.  On a net basis, 32 of 36 wells drilled during the second quarter were successful.  During the first six months of 2004, we drilled 117 gross (58 net) wells, realizing a success rate of 88 percent.

 

Cash flow from operating activities for the six months ended June 30, 2004 totaled $144.5 million, helping to fund our exploration and development expenditure program.  Due to positive drilling results during 2003 and the first half of 2004, 15 percent of our first half oil and gas production contributing to this cash flow was generated from new wells going on line within the first six months of 2004.

 

Based on expected production levels, current commodity prices, and existing operating conditions, we believe we are well positioned to fund the projects identified for the remainder of 2004 and beyond.  We also have available a cash balance of $58.1 million as well as the existing borrowing capacity from our Senior Credit Facility.

 

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

 

Our discussion and analysis of our financial condition and results of operation are based upon consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States of America, or GAAP.  The preparation of these financial

 

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statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses.  Our significant accounting policies are described in Note 3 to our consolidated financial statements included in our Form 10-K for the year ended December 31, 2003.  In response to SEC Release No. 33-8040, “Cautionary Advice Regarding Disclosure About Critical Accounting Policies,” we have identified certain of these policies as being of particular importance to the portrayal of our financial position and results of operations and which require the application of significant judgment by our management.  We analyze our estimates, including those related to oil and gas revenues, reserves and properties, as well as goodwill and contingencies, and base our estimates on historical experience and various other assumptions that we believe to be reasonable under the circumstances.  Actual results may differ from these estimates under different assumptions or conditions.  We believe the following critical accounting policies affect our more significant judgments and estimates used in the preparation of our consolidated financial statements.

 

Revenue Recognition

 

Revenues from oil and gas sales are recognized based on the sales method, with revenue recognized on actual volumes sold to purchasers.  There is a ready market for oil and gas, with sales occurring soon after production.

 

Oil and Gas Reserves

 

The process of estimating quantities of oil and gas reserves is complex, requiring significant decisions in the evaluation of all available geological, geophysical, engineering and economic data.  The data for a given field may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. As a result, material revisions to existing reserve estimates may occur from time to time.  Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the subjective decisions and variances in available data for various fields make these estimates generally less precise than other estimates included in the financial statement disclosures. Revisions of reserve estimates as of December 31, 2003 equaled an increase of 41 MBbls of oil and an increase of 6.7 Bcf of gas, representing 0.3 percent and 2.0 percent of total proved oil and gas reserves, respectively.

 

We use the unit-of-production method to amortize our oil and gas properties.  Changes in reserve quantities will cause corresponding changes in depletion expense in periods subsequent to the quantity revision or, in some cases, a full cost ceiling limitation charge in the period of the revision.  To date, changes in expense resulting from changes in previous estimates of reserves have not been material.

 

Carrying Value of Long-Lived Assets

 

We use the full cost method of accounting for our oil and gas operations.  All costs associated with property acquisition, exploration and development activities are capitalized. Exploration and development costs include dry hole costs, geological and geophysical costs, direct overhead related to exploration and development activities and other costs incurred for the purpose of finding oil and gas reserves. Salaries and benefits paid to employees directly involved in the exploration and development of properties, as well as other internal costs that can be directly identified with acquisition, exploration and development activities, are also capitalized.

 

We perform an impairment analysis whenever events or changes in circumstances indicate an asset’s carrying amount may not be recoverable.  Cash flows used in the full cost ceiling limitation are determined based upon estimates of proved oil and gas reserves, future prices, and the costs to extract these reserves.  Downward revisions in estimated reserve quantities, increases in future cost estimates or depressed oil and gas prices could cause us to reduce the carrying amounts of our properties. In accordance with the full cost accounting rules, capitalized costs of proved oil and gas properties, net of accumulated

 

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depreciation, depletion and amortization 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.  This is referred to as the “full cost ceiling limitation.”  At the end of each quarter, a full cost ceiling limitation calculation is made.

 

Goodwill

 

We account for goodwill in accordance with Statement of Financial Accounting Standard (SFAS) No. 142, Goodwill and Other Intangible Assets.  SFAS No. 142 requires an annual impairment assessment.  A more frequent assessment is required if certain events occur that reasonably indicate an impairment may have occurred.  The volatility of oil and gas prices may cause more frequent assessments.  The impairment assessment requires us to make estimates regarding the fair value of the reporting unit.  The estimated fair value is based on numerous factors, including future net cash flows of our estimates of proved reserves as well as the success of future exploration for and development of unproved reserves. These factors are each individually weighted to estimate the total fair value of the reporting unit.  If the estimated fair value of the reporting unit exceeds its carrying amount, goodwill of the unit is considered not impaired.  If the carrying amount exceeds the estimated fair value, then a measurement of the loss must be performed, with any deficiency recorded as an impairment.  We recorded $45.0 million of goodwill in the purchase of Key on September 30, 2002.  To date, no related impairment has been recorded, nor is any currently anticipated.

 

Contingencies

 

A provision for contingencies is charged to expense when the loss is probable and the cost can be reasonably estimated.  Determining when expenses should be recorded for these contingencies and the appropriate amounts for accrual is a complex estimation process that includes subjective judgment.  In many cases, this judgment is based on interpretation of laws and regulations, which can be interpreted differently by regulators and/or courts of law.  We closely monitor known and potential legal, environmental and other contingencies and periodically determine when we should record losses for these items based on information available to us. As of June 30, 2004, no liabilities have been accrued for known contingencies.  See Note 9 of Notes to Consolidated Financial Statements.

 

Recent Accounting Developments

 

The FASB has determined that the provisions of SFAS No. 141, Business Combinations, and SFAS No. 142, Goodwill and Other Intangible Assets, do not apply to the characterization of mineral rights as intangible assets and thus their segregation in the balance sheet as intangible assets.

 

The FASB formally proposed to require companies to recognize the fair value of stock options and other stock-based compensation to employees for 2005 reporting periods.  Comments on the exposure draft are due by June 30, 2004.  We currently provide in our Notes to Consolidated Financial Statements pro forma information regarding net income as if the compensation cost for our stock option plans had been determined in accordance with the fair value based method prescribed in SFAS No. 123, Accounting for Stock Based Compensation, as amended by SFAS No. 148, Accounting for Stock-Based Compensation-Transition and Disclosure.

 

Overview

 

Our results of operations are impacted by oil and gas prices, which are volatile.  Realized oil prices increased from $28.14 per barrel in the second quarter of 2003 to $37.40 per barrel in the second quarter of 2004, while gas prices increased from $4.91 per Mcf to $5.65 per Mcf for the respective periods.  The majority of our revenues are from oil and gas sales, so price fluctuations can significantly affect our financial results.

 

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Marketing sales and related purchases pertain to activities with third parties conducted by our marketing group.  Natural gas sales transactions are conducted with various purchasers under a variety of terms and conditions and supplied by purchasing gas from other producers and marketing companies.  For the sales transactions in which the gas is supplied by our own production, related sales and costs are reflected in Cimarex’s gas sales and transportation expense.

 

Transportation expenses are comprised of costs paid to carry and deliver oil and gas to a specified delivery point.  In some cases we receive a payment from purchasers, which is net of transportation costs, and in other instances we separately pay for transportation.  If costs are netted in the proceeds received, the respective revenues and related transportation costs are shown gross in sales and expenses.

 

Production costs are generally composed of pumpers’ salaries, utilities, maintenance and other expenses necessary to operate our producing properties.

 

Taxes other than income are taxes assessed by applicable taxing authorities pertaining to production, revenues or the value of our properties.  These typically include production severance, ad valorem and excise taxes.

 

Depreciation, depletion and amortization of our producing properties is computed using the unit-of-production method.  Because the economic life of each producing well depends upon the assumed price for production, fluctuations in oil and gas prices may impact the level of proved reserves used in the calculation.  Higher prices generally have the effect of increasing reserves, which reduces depletion, while lower prices generally have the effect of decreasing reserves, which increases depletion.

 

General and administrative expenses consist primarily of salaries and related benefits, office rent, legal fees, consultants, systems costs and other administrative costs incurred in our offices.  While we expect such costs to increase with our growth, we expect such increases to be proportionately smaller than our production growth.

 

Stock compensation expense consists of non-cash charges resulting from the issuance of restricted stock and restricted stock units to certain employees.

 

Basis of Presentation

 

Cimarex was formed in February 2002 as a wholly-owned subsidiary of Helmerich & Payne, Inc. (H&P).  As a result of a dividend declared and paid by H&P on September 30, 2002, in the form of Cimarex common stock, Cimarex was spun-off and became a stand-alone company.  Also on September 30, 2002, Cimarex acquired 100 percent of the outstanding common stock of Key Production Company, Inc. (Key) in a tax-free exchange.

 

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RESULTS OF OPERATIONS

 

Periods Ended June 30, 2004 Compared with Periods Ended June 30, 2003

 

SUMMARY DATA:

 

		For the Three Months Ended June 30,						For the Six Months Ended June 30,
(IN THOUSANDS OR AS INDICATED)		2004			2003			2004			2003
Net Income		$	36,470		$	21,040		$	66,335		$	53,788
Per share-basic		0.88			0.51			1.60			1.30
Per share-diluted		0.85			0.50			1.56			1.28
Gas sales		$	90,864		$	59,071		$	165,196		$	130,560
Oil sales		24,450			17,026			45,628			36,698
Total oil and gas sales		$	115,314		$	76,097		$	210,824		$	167,258
Total gas volume-MMcf		16,096			12,037			30,226			24,234
Gas volume-MMcf per day		176.9			132.3			166.1			133.9
Average gas price-per Mcf		$	5.65		$	4.91		$	5.47		$	5.39
Total oil volume-thousand barrels		654			605			1,280			1,254
Oil volume-barrels per day		7,184			6,650			7,035			6,930
Average oil price-per barrel		$	37.40		$	28.14		$	35.64		$	29.26
Marketing sales		$	53,831		$	23,230		90,592			68,637
Marketing purchases		53,286			23,105			89,586			68,098
Marketing margin		$	545		$	125		$	1,006		$	539
Other revenues		$	1,048		$	(57	)	$	4,696		$	(66	)
Costs and expenses:
Depreciation, depletion and amortization		$	30,834		$	20,887		$	57,172		$	42,004
Production		9,419			8,155			18,888			15,143
Transportation		2,493			1,896			4,848			3,155
Taxes other than income		9,464			6,147			17,829			13,318
General and administrative		5,133			4,072			9,642			8,139
Stock compensation		484			436			952			902
Asset retirement obligation accretion		304			255			594			496
Financing costs, net		178			182			387			310

 

We reported net income of $36.5 million, or $0.85 per diluted share in the second quarter of 2004 compared to net income of $21.0 million, or $0.50 per diluted share for the same period in 2003. For the six months ended June 30, 2004, net income was $66.3 million, or $1.56 per diluted share, compared to net

 

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income of $53.8 million, or $1.28 per diluted share, for the same period in 2003. Included in first-half 2003 net income is $1.6 million of earnings (net of income taxes) from the cumulative effect of change in accounting principle resulting from the adoption of SFAS 143, Accounting for Asset Retirement Obligations.  The remainder of the decrease results from the net effect of changes in revenues and costs, as discussed further.

 

Oil and gas sales for second quarter of 2004 totaled $115.3 million, compared to $76.1 million for the second quarter of 2003.  The $39.2 million increase in sales between the two periods results from $21.2 million due to higher production volumes and $18.0 million related to higher commodity prices.  For the six months ended June 30, 2004, oil and gas sales increased by $43.6 million, or 26 percent, to $210.8 million from $167.3 million during the first six months of 2003.  Higher production volumes increased sales by $33.0 million and higher commodity prices contributed $10.6 million to the increase between the two six-month periods

 

Realized gas prices averaged $5.65 per Mcf for the three months ended June 30, 2004, compared to $4.91 per Mcf for the second quarter of 2003.  This 15 percent change increased sales by $11.9 million between the two periods. Realized oil prices averaged $37.40 per barrel for the second quarter of 2004, compared to $28.14 per barrel for the same period in 2003.  The increase in sales between periods resulting from this 33 percent improvement in oil prices totaled $6.1 million.  For the six months ended June 30, 2004, realized gas prices increased to $5.47 per Mcf from $5.39 per Mcf realized in the first half of 2003.  This price increase contributed $2.4 million to the increase in sales between the two six-month periods.  Realized oil prices averaged $35.64 per barrel for the first half of 2004, compared to $29.26 per barrel for the same period in 2003, resulting in an $8.2 million increase in sales between periods.  Changes in realized prices were the direct result of overall market conditions.  We have not entered into any derivative contracts or hedges with respect to our production.

 

Sales also benefited from higher production volumes.  Average gas volumes rose 44.6 MMcf per day in the second quarter of 2004 to 176.9 MMcf per day from 132.3 MMcf per day in the second quarter of 2003, resulting in $19.9 million of incremental revenues.  Oil volumes averaged 7,184 barrels per day for the second three months of 2004, compared to 6,650 barrels per day in the same period of 2003, resulting in increased revenues of $1.3 million.  For the first six months of 2004, gas volumes averaged 166.1 MMcf per day and oil volumes equaled 7,035 barrels per day, compared to first-half 2003 volumes of 133.9 MMcf per day and 6,930 barrels per day.  The higher gas volumes increased sales between the two periods by $32.3 million, and higher oil volumes resulted in $0.7 million of additional revenues. The increase in sales volumes between the periods of 2004 and 2003 is due to positive drilling results during 2003 and the first half of 2004.

 

Marketing sales net of related purchases equaled $0.5 million in the second quarter of 2004 compared to $0.1 million in the second quarter of 2003.  For the six months ended June 30, 2004 and 2003, marketing sales net of related purchases totaled $1.0 million and $0.5 million, respectively.  These sales relate to marketing activities with outside parties conducted by our marketing group.  The financial impact from these activities is small relative to our overall results of operations. Revenues and costs related to marketing of our own production are eliminated in consolidation.

 

Other revenues of $4.7 million in the first half of 2004 consist of $3.0 million of settlements related to litigation for which we were plaintiffs.  The remaining $1.7 million pertains to gains on the sale of miscellaneous equipment.

 

Costs and Expenses

 

Costs and expenses (not including marketing purchases) were $58.3 million in the second quarter of 2004 compared to $42.0 million in the same period of 2003.  For the first six months of 2004 and 2003, these overall costs and expenses equaled $110.3 million and $83.5 million, respectively.  Depreciation, depletion and amortization (DD&A) was the largest component of these increases between periods. DD&A

 

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equaled $30.8 million in the second quarter of 2004 compared to $20.9 million in the same period of 2003. For the first six months of 2004 and 2003, DD&A totaled $57.2 million and $42.0 million, respectively. On a unit of production basis, DD&A was $1.54 per Mcfe in the second quarter of 2004 compared to $1.33 per Mcfe for the second quarter of 2003.  For the first six months of 2004 and 2003, DD&A on a unit of production basis equaled $1.51 per Mcfe and $1.32 per Mcfe, respectively. The increases largely stem from higher costs for reserves added during 2003.

 

Production costs rose $1.2 million from $8.2 million ($0.52 per Mcfe) in the second three months of 2003 to $9.4 million ($0.47 per Mcfe) in the second quarter of 2004.  For the first six months of 2004 and 2003, production costs equaled $18.9 million ($0.50 per Mcfe) and $15.1 million ($0.48 per Mcfe), respectively.  The higher year-to-date costs resulted primarily from the installation and operation of additional compressors (primarily in Kansas) to enhance production, higher field operating expenses from an expanded number of properties, and higher maintenance costs.  As production increases, however, due to additional successful wells and enhanced production rates from existing wells, costs on a per unit basis is slowly decreasing.

 

Transportation costs increased from $1.9 million, or $0.12 per Mcfe, in the second quarter of 2003 to $2.5 million, or $0.13 per Mcfe, in the second quarter of 2004.  Transportation costs for the first half of 2004 equaled $4.8 million compared to $3.2 million for the same period in 2003.  The increase is the result of expiring contracts being renewed with increased current market rates. The cost of $0.13 per Mcfe in the second three months of 2004 is consistent with the last four previous quarters.

 

Taxes other than income were $3.4 million greater, rising from $6.1 million in the second quarter of 2003 to $9.5 million in the same period of 2004.  For the first six months of 2004 and 2003, these costs totaled $17.8 million and $13.3 million, respectively.  The increases between periods resulted from increases in oil and gas sales stemming from higher production volumes and commodity prices.

 

General and administrative (G&A) expenses increased $1.0 million from $4.1 million in the second quarter of 2003 to $5.1 million in the second quarter of 2004.  G&A expenses for the first half of 2004 equaled $9.6 million compared to $8.1 million for the same period of 2003.  The increases between periods are due mainly to an expansion of staff and higher employee-benefit costs.

 

Income tax expense

 

Income tax expense totaled $22.1 million for the second quarter of 2004 versus $13.1 million for the second three months of 2003.  Tax expense equaled a combined Federal and state effective income tax rate of 37.8 percent and 38.4 percent in the second quarters of 2004 and 2003, respectively.  Income tax expense for the first six months of 2004 equaled $39.9 million compared to $32.1 million for the same period of 2003, equating to combined Federal and state effective income tax rates of 37.5 percent and 38.1 percent, respectively.  We estimate that $12.6 million of our first-half 2004 income tax expense is current.

 

LIQUIDITY AND CAPITAL RESOURCES

 

Cash Flows

 

Our primary source of capital is cash flow generated from operating activities. Prices we receive for future oil and gas sales and our level of production will impact these future cash flows.  No prediction can be made as to the prices we will receive.  Production volumes will in part be dependent upon the amount and results of future capital expenditures.  In turn, actual levels of capital expenditures may vary due to many factors, including drilling results, oil and gas prices, industry conditions, prices and availability of goods and services, and the extent to which proved properties are acquired.

 

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Cash flow provided by operating activities for the six months ended June 30, 2004 was $144.5 million, compared to $119.3 million for the six months ended June 30, 2003. The increase in 2004 from the earlier period results primarily from higher oil and gas production and prices.

 

Higher revenues from oil and gas sales facilitated the funding of our exploration and development expenditure program for the first half of 2004.

 

Cash flow used in investing activities for the six months ended June 30, 2004 was $131.2 million, compared to $64.2 million for the six months ended June 30, 2003. The increase in 2004 stems from a larger exploration and development program.

 

Cash flow provided by financing activities in the first half of 2004 was $4.4 million versus cash used in financing activities of $30.0 million in the first half of 2003, a change of $34.4 million. The most significant item that occurred during the first quarter of 2003 was the repayment of $27.0 million of our long-term credit facility.  The cash provided by financing activities in 2004 resulted from the exercise of employee stock options.

 

Financial Condition

 

As of June 30, 2004, stockholders’ equity totaled $608.0 million, up from $534.7 million at December 31, 2003.  The increase resulted primarily from first-half 2004 net income of $66.3 million and the exercise of employee stock options.  At June 30, 2004 our cash balance equaled $58.1 million.

 

Working Capital

 

Working capital at June 30, 2004 totaled $41.3 million, compared to $37.7 million at December 31, 2003.  The largest components of this increase were higher balances in cash and receivables due to higher oil and gas production and prices. Our receivables are from a diverse group of companies including major energy companies, pipeline companies, local distribution companies and end-users in various industries.  The collection of receivables during the period presented has been timely.  Historically, losses associated with uncollectible receivables have not been significant.

 

Financing

 

In October 2002, we closed on a three-year $400 million Senior Secured Revolving Credit Facility.  The Facility has a borrowing base of $275 million and we have elected a $200 million commitment amount.  The borrowing base is subject to redetermination each April and October.  Borrowings under this Facility bear interest at a LIBOR rate plus 1.25 percent to 2.00 percent, based on borrowing base usage.  Unused borrowings are subject to a commitment fee of 0.375 percent to 0.50 percent, also depending on borrowing base usage.  The Credit Facility is secured by mortgages on our oil and gas properties and the stock of our subsidiaries.  We are also subject to customary financial and non-financial covenants.  We are in compliance with all such covenants.  There were no borrowings under the Facility at December 31, 2003 and at June 30, 2004.  Because we have no publicly-traded debt, we have not sought a corporate credit rating.

 

Contractual Obligations and Material Commitments

 

We have issued parental guarantees of $8.5 million related to our marketing business for the benefit of companies we purchase gas from.

 

We have one firm transportation contract to transport 10,000 MMBtus per day, at $0.09 per MMBtu through December 31, 2004.  We have a right to extend this contract annually.  Maximum amount that would be payable if deliveries are not made would be $0.2 million.

 

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We have also guaranteed delivery of 6.7 Bcf of natural gas from 13 wells over a three-year period as reimbursement for connection costs to a pipeline.  If the minimum delivery is not met, the maximum exposure is $0.5 million.  We have agreed to reimburse another gatherer for connection costs to its pipeline via delivery of 1 Bcf of natural gas per well or a prorated payment based on the total reserves on 19 wells.  The maximum amount that would be payable if we deliver no natural gas would be $0.6 million.

 

Additionally, we have firm sales contracts to deliver fixed volumes of gas based on an index price.  These contracts are typically one year in length.  As of June 30, 2004, we had an obligation to deliver approximately 1.2 Bcf of natural gas.  If this gas is not delivered our financial commitment would approximate $6.7 million based on index prices as of June 30, 2004.  This commitment will fluctuate due to price volatility and actual volumes delivered.  We believe no financial commitment will be due based on our proved reserves and current production levels.

 

All of the commitments were routine and were made in the normal course of our business.

 

Based on current commodity prices and anticipated levels of production, we believe that the estimated net cash generated from operations, coupled with the cash on hand 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.

 

Our projected 2004 exploration and development expenditure program of $230-260 million will require a great deal of coordination and effort.  Though there are a variety of factors that could curtail, delay or even cancel some of our drilling operations, we believe our projected program has a high degree of occurrence.  The majority of projects are in hand, drilling rigs are being scheduled, and the historical results of our drilling efforts in these areas warrant pursuit of the projects.

 

Costs of operations on a per Mcfe basis for 2004 are estimated to approximate or slightly exceed levels realized in 2003.  Should factors beyond our control fluctuate, our program and realized costs will vary from current projections.  These factors could include volatility in commodity prices, changes in the supply of and demand for oil and gas, weather conditions, governmental regulations and more.

 

Estimated production for 2004 ranges between 210 to 215 MMcfe per day.  The revenues to be realized from the sale of this production will be highly dependent on oil and gas prices. During 2003, the average price realized for our gas sales was $4.96 per Mcf and our average oil price was $29.30 per barrel.  Current indications are that 2004 prices should exceed 2003 levels. During the first half of 2004, average prices realized from our sales were $5.47 per Mcf of gas and $35.64 per barrel of oil. Prices can be highly volatile, and the probability of realized prices for 2004 to vary from current estimates is high.

 

ITEM 3.  Qualitative and Quantitative Disclosures about Market Risk

 

Price Fluctuations

 

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

 

Monthly gas price realizations during the second quarter of 2004 ranged from $5.08 per Mcf to $6.18 per Mcf.  Oil prices ranged from $35.48 per barrel to $40.33 per barrel, and for the first half of 2004, monthly realized gas prices ranged from $4.86 per Mcf to $6.18 per Mcf, with realized monthly oil prices for the period ranging from $32.71 per barrel to $40.33 per barrel. It is impossible to predict future oil and gas prices with any degree of certainty.

 

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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, or similar arrangements using commodity futures contracts or options.  To date, we have not used any of these financial instruments to mitigate commodity price changes.

 

Any sustained weakness in prices may affect our financial condition and results of operations, and may also reduce the amount of net oil and gas reserves that we can produce economically.  Any reduction in reserves, including reductions due to price fluctuations, can have an adverse effect on our ability to obtain capital for our exploration and development activities and could cause us to record a reduction in the carrying value of our oil and gas properties.

 

Interest Rate Risk

 

Cimarex may be exposed to risk resulting from changes in interest rates as a result of our variable-rate bank credit facility.  However, because we presently have no debt outstanding, the potential for changes in interest rates would have no affect on our results of operations.

 

ITEM 4.  CONTROLS AND PROCEDURES

 

As of the end of the period covered by this report, with the participation of management, Cimarex’s Chief Executive Officer and Chief Financial Officer carried out an evaluation of the effectiveness of the design and operation of Cimarex’s disclosure controls and procedures (as defined in Securities Exchange Act Rules 13a-14(c) and 15(d)-14(c)) to ensure that information required to be disclosed by Cimarex under the Securities Exchange Act is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms.  Based upon that evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that Cimarex’s disclosure controls and procedures are effective.

 

There were no significant changes in Cimarex’s internal controls or in other factors that could significantly affect these controls subsequent to the Evaluation Date.

 

PART II – OTHER INFORMATION

 

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

 

The annual meeting of the Company was held on May 19, 2004.  The only matter voted upon at the annual meeting was the election of three directors.  The following directors were elected to serve until the 2007 annual meeting:

 

		For		Against
Cortlandt S. Dietler		35,636,658		1,158,806
Hans Helmerich		36,604,252		191,212
L.F. Rooney, III		36,191,043		604,421

 

The terms of office of Glenn A. Cox, David A. Hentschel, Paul D. Holleman, F.H. Merelli, Michael J. Sullivan and L. Paul Teague continued after the meeting.

 

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ITEM 6 – EXHIBITS AND REPORTS ON FORM 8-K

 

(a)		Exhibits:
		31.1	Certification of F.H. Merelli, Chief Executive Officer of Cimarex Energy Co. pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
		31.2	Certification of Paul Korus, Chief Financial Officer of Cimarex Energy Co. pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
		32.1	Certification of F.H. Merelli, Chief Executive Officer of Cimarex Energy Co. pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, 18 U.S.C. Section 1350.
		32.2	Certification of Paul Korus, Chief Financial Officer of Cimarex Energy Co. pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, 18 U.S.C. Section 1350.

 

 

(b)		Reports on Form 8-K:
		Current Report on Form 8-K filed with the Securities and Exchange Commission on May 4, 2004 attaching a copy of Registrant’s first quarter financial and operating results under Item 12.
		Current Report on Form 8-K filed with the Securities and Exchange Commission on April 26, 2004 updating the Registrant’s production volume guidance under Item 9.

 

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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 5, 2004
	CIMAREX ENERGY CO.
	/s/ Paul Korus
	Paul Korus
	Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer)
	/s/ James H. Shonsey
	James H. Shonsey
	Chief Accounting Officer and Controller (Principal Accounting Officer)

 

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