Edgar Filing: CIMAREX ENERGY CO

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

x	Quarterly Report Pursuant To Section 13 or 15(d) of the Securities Exchange Act of 1934

o	Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the Quarterly Period ended September 30, 2006

Commission File No. 001-31446

CIMAREX ENERGY CO.

1700 Lincoln Street, Suite 1800
Denver, Colorado 80203-4518
(303) 295-3995

Incorporated in the		Employer Identification
State of Delaware		No. 45-0466694

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer (as defined in Rule 12b-2 of the Exchange Act). (Check One)

Large accelerated filer x Accelerated Filer o Non-accelerated filer o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes oNo x

The number of shares of Cimarex Energy Co. common stock outstanding as of September 30, 2006 was 82,850,019.

CIMAREX ENERGY CO.

Table of Contents

PART I

Item 1 – Financial Statements

Consolidated balance sheets (unaudited) as of September 30, 2006 and December 31, 2005

Consolidated statements of operations (unaudited) for the three and nine months ended September 30, 2006 and 2005

Consolidated statements of cash flows (unaudited) for the nine months ended September 30, 2006 and 2005

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 6 – Exhibits and Reports on Form 8-K

Signatures

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.

PART I

ITEM 1 - Financial Statements

CIMAREX ENERGY CO.

Consolidated Balance Sheets

(Unaudited)

	September 30,			December 31,
	2006			2005
	(In thousands, except share data)

Assets

Current assets:
Cash and cash equivalents	$	8,084		$	61,647
Receivables, net	256,206			289,184
Inventories	46,233			34,784
Deferred income taxes	11,056			17,959
Derivative instruments, net	19,395			—
Other current assets	13,247			25,454
Total current assets	354,221			429,028
Oil and gas properties at cost, using the full cost method of accounting:
Proved properties	4,348,788			3,602,797
Unproved properties and properties under development, not being amortized	462,036			388,839
	4,810,824			3,991,636
Less – accumulated depreciation, depletion and amortization	(1,392,650		)	(1,114,677		)
Net oil and gas properties	3,418,174			2,876,959
Fixed assets, net	91,272			86,916
Goodwill	691,432			717,391
Derivative instruments	9,976			—
Other assets, net	38,780			70,041
	$	4,603,855		$	4,180,335

Liabilities and Stockholders’ Equity

Current liabilities:
Accounts payable	$	53,650		$	81,947
Accrued liabilities	154,153			179,076
Derivative instruments	—			41,926
Revenue payable	99,594			94,469
Total current liabilities	307,397			397,418
Long-term debt	399,613			352,451
Deferred income taxes	867,724			717,790
Other liabilities	122,436			117,223
Stockholders’ equity:
Preferred stock, $0.01 par value, 15,000,000 shares authorized, no shares issued	—			—
Common stock, $0.01 par value, 200,000,000 shares authorized, 83,928,841 and 83,524,285 shares issued, respectively	839			835
Treasury stock, at cost, 1,078,822 and 1,146,822 shares held, respectively	(40,628		)	(43,554		)
Paid-in capital	1,864,054			1,865,597
Unearned compensation	—			(15,862		)
Retained earnings	1,062,011			788,356
Accumulated other comprehensive income	20,409			81
	2,906,685			2,595,453
	$	4,603,855		$	4,180,335

See accompanying notes to consolidated financial statements.

CIMAREX ENERGY CO.

Consolidated Statements of Operations

(Unaudited)

	For the Three Months						For the Nine Months
	Ended September 30,						Ended September 30,
	2006			2005			2006			2005
	(In thousands, except per share data)
Revenues:
Gas sales	$	197,460		$	245,010		$	622,841		$	488,043
Oil sales	111,801			98,459			308,911			177,829
Gas gathering and processing	13,126			19,273			36,520			21,976
Gas marketing, net of related costs of $31,191, $45,208, $118,153 and $160,560 respectively	495			352			3,241			1,248
	322,882			363,094			971,513			689,096
Costs and expenses:
Depreciation, depletion and amortization	104,904			82,826			290,305			172,493
Asset retirement obligation accretion	1,977			1,331			4,918			2,266
Production	42,624			40,473			128,200			68,056
Transportation	5,845			4,237			15,636			10,319
Gas gathering and processing	7,325			13,750			20,264			15,612
Taxes other than income	22,912			21,418			68,392			45,913
General and administrative	10,804			8,418			31,679			23,967
Stock compensation, net	2,265			1,225			6,329			3,663
Expenses related to merger	—			1,402			(61		)	8,087
(Gain) loss on derivative instruments	(4,782		)	81,946			(23,598		)	83,976
	193,874			257,026			542,064			434,352

Operating income	129,008			106,068			429,449			254,744

Other (income) and expense:
Interest expense net of capitalized interest of $6,726, $4,978, $18,555 and $6,157, respectively	1,388			3,302			3,446			6,082
Amortization of fair value of debt	(947		)	(771		)	(2,838		)	(1,187		)
Other, net	(20,137		)	3,456			(25,515		)	(700		)

Income before income tax expense	148,704			100,081			454,356			250,549
Income tax expense	54,747			36,006			167,382			90,632

Net income	$	93,957		$	64,075		$	286,974		$	159,917

Earnings per share:

Basic	$	1.15		$	0.78		$	3.50		$	2.72

Diluted	$	1.11		$	0.76		$	3.41		$	2.63

Weighted average shares outstanding:
Basic	82,052			82,284			82,062			58,815
Diluted	84,311			84,840			84,275			60,767

See accompanying notes to consolidated financial statements.

CIMAREX ENERGY CO.

Condensed Consolidated Statements of Cash Flows

(Unaudited)

	For the Nine Months
	Ended September 30,
	2006			2005
	(In thousands)

Cash flows from operating activities:
Net income	$	286,974		$	159,917
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	290,305			172,493
Asset retirement obligation accretion	4,918			2,266
Deferred income taxes	174,602			32,644
Stock compensation, net	6,329			3,663
Derivative instruments	(39,200		)	66,538
Gain on liquidation of equity investees	(18,322		)	—
Other	(947		)	12,870
Changes in operating assets and liabilities
(Increase) decrease in receivables, net	51,067			(23,765		)
(Increase) in other current assets	(9,454		)	(24,420		)
Increase (decrease) in accounts payable and accrued liabilities	(69,336		)	15,081
Increase in other non-current liabilities	200			188

Net cash provided by operating activities	677,136			417,475

Cash flows from investing activities:
Oil and gas expenditures	(802,155		)	(398,191		)
Acquisition of proved oil and gas properties	(5,530		)	(1,973		)
Merger costs	(439		)	(12,405		)
Cash received in connection with acquisition	—			33,407
Proceeds from sale of assets	10,659			70,576
Distributions received from equity investees	58,285			235
Other expenditures	(23,212		)	(20,033		)

Net cash used by investing activities	(762,392		)	(328,384		)

Cash flows from financing activities:
Borrowings (payments) on long-term debt, net	50,000			(188,422		)
Treasury Stock acquired	(11,016		)	—
Dividends paid	(10,006		)	—
Proceeds from issuance of common stock and other	2,715			11,058

Net cash (used in) provided by financing activities	31,693			(177,364		)

Net change in cash and cash equivalents	(53,563		)	(88,273		)

Cash and cash equivalents at beginning of period	61,647			115,746

Cash and cash equivalents at end of period	$	8,084		$	27,473

See accompanying notes to consolidated financial statements.

CIMAREX ENERGY CO.

Notes to Consolidated Financial Statements

September 30, 2006

(Unaudited)

1. Basis of Presentation

The accompanying unaudited financial statements have been prepared by Cimarex Energy Co. pursuant to rules and regulations of the Securities and Exchange Commission (“SEC”). Accordingly, certain disclosures required by accounting principles generally accepted in the United States and normally included in annual reports on Form 10-K have been omitted. Although management believes that our disclosures in these interim financial statements are adequate, they should be read in conjunction with the financial statements, summary of significant accounting policies, and footnotes included in our 2005 Annual Report on Form 10-K.

In the opinion of management, the accompanying financial statements reflect all adjustments necessary to present fairly our financial position, results of operations, and cash flows for the periods shown.

Full Cost Accounting Method and Ceiling Limitation

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.

At the end of each quarter, a full cost ceiling limitation calculation is made whereby net capitalized costs related to proved properties less associated deferred income taxes may not exceed an amount equal to the present value discounted at ten percent of estimated future net revenues from proved reserves less estimated future production and development costs and related income tax expense. Future net revenues used in the calculation of the full cost ceiling limitation are determined based on current oil and gas prices and are adjusted for designated cash flow hedges if it is determined that net capitalized costs exceed the full cost ceiling limit. If net capitalized costs subject to amortization exceed this limit, the excess should be charged to expense. The Company determined under the full cost ceiling limitation calculation, using September 30, 2006 prices, that net capitalized costs exceeded the full cost ceiling limit by $561 million before tax ($354 million after tax), after being reduced by $133 million resulting from the effect of the Company’s designated cash flow hedges (See Note 3). This amount has not been charged against earnings, because the increase in gas prices subsequent to September 30, 2006 and prior to the issuance of the financial statements indicate that the capitalized costs were not in fact impaired.

Use of Estimates

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. 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.

The more significant areas requiring the use of management’s estimates and judgments relate to the estimation of proved 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 ceiling test

limitations and estimates of future abandonment obligations used in recording asset retirement obligations and the assessment of goodwill. Estimates and judgments are also required in determining reserves for bad debt, impairments of undeveloped properties, the purchase price allocation, and valuation of deferred tax assets.

Certain amounts in prior years’ financial statements have been reclassified to conform to the 2006 financial statement presentation.

2. Business Combination

On June 7, 2005, Cimarex completed the acquisition of Magnum Hunter Resources, Inc, an independent oil and gas exploration and production company with operations concentrated in the Permian Basin of West Texas and New Mexico and in the Gulf of Mexico. Terms of the merger agreement provided that Magnum Hunter stockholders receive 0.415 shares of Cimarex common stock for each share of Magnum Hunter common stock. As a result of the merger, Cimarex issued 39.7 million common shares to Magnum Hunter’s common stockholders. The results of operations of Magnum Hunter are included in our consolidated statements of operations for the period since the acquisition on June 7, 2005.

The allocation of the purchase price to oil and gas properties utilized prevailing oil and gas prices at the time of negotiations and announcement of the merger. The overall allocation of the purchase price has been finalized and the goodwill amount related to the purchase as of September 30, 2006 equals $646.4 million.

The following unaudited pro forma information has been prepared to give effect to the Magnum Hunter acquisition as if it had occurred at the beginning of the periods presented. The unaudited pro forma data is presented for illustrative purposes only, based on estimates and assumptions deemed appropriate by management, and should not be relied upon as an indication of the operating results that Cimarex would have achieved if the transaction had occurred on January 1, 2005. The pro forma information also should not be used as an indication of future results or trends.

	Three Months Ended		Nine Months Ended
	September 30, 2005		September 30, 2005

(Thousands of dollars, except per share data)
Pro Forma Statement of Operations Data
Revenues	$	363,094	$	964,189
Net income	64,075		235,517
Net income per share:
Basic	$	0.78	$	2.86
Diluted	$	0.76	$	2.78

3. Derivative Instruments

SFAS No.133, Accounting for Derivative Instruments and Hedging activities, requires that all derivatives be recorded on the balance sheet at fair value. We determine the fair value of derivative contracts based on the stated contract prices and current and projected market prices at the determination date discounted to reflect the time value of money until settlement. The accounting treatment for the changes in fair value is dependent upon whether or not a derivative instrument is designated as a hedge for accounting treatment purposes. Realized and unrealized gains and losses on derivatives that are not designated as hedges are recognized currently in costs and expenses associated with operating income in our consolidated statements of operations. For derivatives designated as cash flow hedges, changes in the fair value, to the extent the hedge is effective, are recognized in other comprehensive income until the hedged item is settled. Changes in the fair value of the hedge resulting from ineffectiveness are recognized currently as unrealized gains or losses in other income and expense in the consolidated statements of operations. Gains and losses upon settlement of the cash flow hedges will be recognized in gas revenues in the period the contracts are settled.

In connection with the Magnum Hunter merger, Cimarex recognized a $39.3 million liability associated with Magnum Hunter’s existing commodity derivatives at the merger date (June 7, 2005). These derivative instruments have not been designated for hedge accounting treatment. As a result, Cimarex recognized net gains for the quarter and nine months ended September 30, 2006 of $4.8 million and $23.6 million, respectively. From the date of the merger through the third quarter of 2005 we recorded a total net loss of $84.0 million. Activity includes both non-cash mark-to-market derivative gains and losses as well as cash settlements. Cash payments related to these contracts that settled in the quarter and nine months ended September 2006 totaled $4.2 million and $15.7 million, respectively, and $15.6 million from the date of the merger through the third quarter of 2005. The derivative liability at September 30, 2006 related to these contracts equals $2.7 million. Cimarex will continue to recognize gains and losses as these remaining derivative instruments expire through December 31, 2006. Actual gains and losses to be recognized may differ materially from the current fair value of amounts recorded. The following is a summary of the company’s open derivative contracts not designated for hedge accounting treatment as of September 30, 2006:

Nymex
Weighted Average

Fair Value

Commodity

Type

Volume/Day

Duration

Price

(000’s)

Natural Gas

Collar

20,000 MMBTU

Oct 06 – Dec 06

$5.25 - $6.30

(130

)

Crude Oil

Collar

1,000 BBL

Oct 06 – Dec 06

$30.00 - $35.85

(2,596

)

(2,726

)

The current derivative liability of $2.7 million is included in derivative instruments, net, within current assets at September 30, 2006. Weighted average Nymex prices at September 30, 2006 for the remaining three months of 2006 approximated $5.72 per Mcf of gas and $62.51 per barrel of oil.

During the quarter ended September 30, 2006, we recognized an unrealized loss of $60 thousand related to the ineffective portion of the derivative contracts. The following table sets forth the terms of the related derivative contracts at September 30, 2006:

Mid-Continent
Weighted Average

Fair Value

Commodity

Type

Volume/Day

Duration

Price

(000’s)

Natural Gas

Collars

80,000 MMBTU

Jan 07 – Dec 07

$7.00 - $10.17

22,674

Natural Gas

Collars

40,000 MMBTU

Jan 08 – Dec 08

$7.00 - $9.90

9,424

32,098

At September 30, 2006 the $32.1 million fair value of the derivative contracts was recorded as a current asset of $22.1 million and a long term asset of $10 million on our consolidated balance sheet. An unrealized gain (net of deferred income taxes) of $20.3 million was recorded in other comprehensive income. Based on the estimated fair values of the derivative contracts at September 30, 2006, the amount of unrealized gain (net of deferred income taxes) to be reclassified from accumulated other comprehensive income to gas revenue in the next twelve months would be approximately $14 million; however, actual gains and losses recognized may differ significantly. At September 30, 2006, the weighted average Mid-Continent prices for the 2007 and 2008 contracts approximated $6.83 and $7.15, respectively. We believe that we have sufficient production volumes such that the hedge contract transactions will occur as expected.

4. Stock Plans

Stock Options

Cimarex’s 2002 Stock Incentive Plan reserves 12.7 million shares of common stock for issuance to directors and employees, including officers. Options granted under the plan after December 5, 2002, expire ten years from the grant date and vest in one-fifth increments on each of the first five anniversaries of the grant date. All grants are made at the average of the high and low prices of our common stock as reported on the New York Stock Exchange on the date of grant.

Upon the exercise of the options for shares of common stock, the employee is required to hold at least 50 percent of the profit shares, as defined in the plan, until the eighth anniversary of the grant date. The incentive plan provides for accelerated vesting if there is a change in control (as defined in the plan).

Effective January 1, 2005, we adopted the provisions of Statement of Financial Accounting Standards (“SFAS”) No. 123R, Share Based Payment on a prospective basis. SFAS No. 123R requires companies to recognize in the income statement the grant-date fair value of stock options and other equity-based compensation to employees. For each of the quarters ended September 30, 2006 and 2005, compensation expense related to stock options was approximately $0.5 million, or $0.3 million after tax. For the nine months ended September 30, 2006 and 2005, compensation expense related to stock options was approximately $1.4 million and $1.9 million or $0.9 million and $1.2 million after tax ($0.01 and $0.02 per diluted share), respectively.

As discussed more fully in the notes to the financial statements of our annual report on form 10-K for the year ended December 31, 2005, the merger with Magnum Hunter constituted a “change of control event” under the incentive plan. As a result, all participants became entitled to acceleration of vesting of their options. Cimarex obtained waivers of the accelerated vesting from certain option holders including the company’s CEO and other senior officers. Option holders who were not requested to or did not choose to execute a waiver became fully vested in their options on June 7, 2005. Compensation expense related to the accelerated vesting of options was approximately $1.1 million or $0.7 million after tax.

The fair value of each option award was estimated as of the date of grant using the Black-Scholes option-pricing model. Expected volatilities were based on the historical volatility of our common stock. The risk free interest rate is based on U.S. Treasury Securities at a constant five year fixed maturity in effect at the date of the grant. Historical data was also used to estimate the probability of option exercise, expected years until exercise and employee termination within the valuation model.

There were no stock options granted to employees during the nine months ended September 30, 2006 and 2005.

The following summary reflects the status of stock options granted to employees and directors as of September 30, 2006, and changes during the period:

	Shares		Weighted Average Exercise Price		Weighted Average Remaining Term	Aggregate Intrinsic Value ($000)

Outstanding as of January 1, 2006	2,023,388		$	15.64
Exercised	(105,940	)	15.56
Granted	—		—
Canceled	—		—
Outstanding as of September 30, 2006	1,917,448		$	15.65	4.7 Years	$	37,639
Exercisable as of September 30, 2006	1,465,988		$	14.75	4.2 Years	$	29,889

The total intrinsic value of options exercised during the three months ended September 30, 2006 and 2005 was $65 thousand and $8.6 million, respectively. The total intrinsic value of options exercised during the nine months ended September 30, 2006 and 2005 was $3.1 million and $16.4 million, respectively.

The following summary reflects the status of non-vested stock options granted to employees and directors as of September 30, 2006 and changes during the period:

	Shares		Weighted Average Grant Date Fair Value

Non-vested as of January 1, 2006	456,260		$	8.75
Vested	(10,860	)	12.98
Granted	—		—
Forfeited	—		—
Non-vested as of September 30, 2006	445,400		$	8.65

As of September 30, 2006 there was $2.6 million of total unrecognized compensation cost related to non-vested stock options granted under our incentive plan. That cost is expected to be recognized pro rata over a

weighted-average period of 2.3 years. The weighted average exercise price of the non-vested stock options was $18.23. Generally, options vest on the anniversary of the grant date.

Cash received from option exercises during the nine months ended September 30, 2006 and 2005 was approximately $1.6 million and $8.5 million, respectively. The tax benefit realized for the tax deductions from option exercises totaled approximately $1.1 million and $6.1 million, for the nine months ended September 30, 2006 and 2005, respectively, and was recorded in paid-in capital.

Restricted Stock and Units

We have a long-term incentive program whereby grants of restricted stock and/or units are awarded to certain employees. The restrictions related to these awards are associated with the continued employment of the grantee for one to five years from the date of the original grant, at which time these shares will vest.

Awards of restricted stock units vest from one to five years from the date of grant and are payable in shares of stock on the eighth anniversary of the date of grant. In accordance with SFAS No 123R, deferred compensation of $13.9 million and the related unearned compensation were reclassified to paid-in capital. There were 696,641 restricted stock units outstanding as of September 30, 2006.

Awards of restricted stock vest from one to five years from the date of grant and are payable in shares of unrestricted stock on vesting. In accordance with SFAS No 123R, unearned compensation attributable to restricted stock was reclassified to paid-in-capital. At September 30, 2006 there were 796,057 shares of restricted stock outstanding.

The restricted stock and stock unit agreements provide that the grantees will be entitled to receive dividends, when and if declared.

The following summary reflects the status of restricted stock and units granted to employees and directors as of September 30, 2006, and changes during the year:

	Stock		Units

Outstanding as of January 1, 2006	249,905		697,937
Vested	(7,637	)	—
Granted	597,589		4,954
Canceled	(43,800	)	(6,250	)
Outstanding as of September 30, 2006	796,057		696,641

Compensation expense for restricted shares or units is based upon the market price of the restricted grant multiplied by the number of shares of restricted stock or units granted. Compensation cost is being recognized over the associated vesting period. For the nine months ended September 30, 2006 and 2005, we recorded compensation expense of $4.9 million and $4.4 million, respectively. We also capitalized to oil and gas properties associated costs of $2.3 million and $1.2 million, respectively. At September 30, 2006, there was $33.0 million of unrecognized compensation cost related to grants of restricted stock and units.

Declared Dividends and Stock Repurchases

In December 2005, the Board of Directors declared the Company’s first quarterly dividend of $0.04 per share payable on March 1, 2006 to shareholders of record as of February 15, 2006. Subsequently, in March, May, and September of 2006, quarterly dividends of $0.04 per share have been declared, payable on June 1,

September 1, and December 1, 2006 to shareholders of record as of May 15, August 15, and November 15 2006, respectively.

In December 2005, the Board of Directors authorized the repurchase of up to four million shares of common stock. Through December 31, 2005, 68,000 shares had been repurchased at an average price of $43.03. Since December 31, 2005 and through September 2006, an additional 182,100 shares have been repurchased for an average price of $44.43 per share.

5. Asset Retirement Obligations

The Company recognizes the fair value of a liability for an asset retirement obligation in the period in which it is incurred if a reasonable estimate of fair value can be made, and the associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. Oil and gas producing companies incur this liability which includes costs related to the plugging of wells, the removal of facilities and equipment, and site restorations, upon acquiring or drilling a successful well.

The following table reflects the components of the change in the carrying amount of the asset retirement obligation for the nine months ended September 30, 2006 (in thousands):

Balance as of January 1, 2006	$	101,128
Liabilities incurred in the current period	13,957
Liabilities settled in the current period	(1,209		)
Accretion expense	4,749
Revision of estimated liabilities	(146		)
Balance as of September 30, 2006	118,479
Less: Current asset retirement obligation	(4,320		)
Long-term asset retirement obligation	$	114,159

6. Long-Term Debt

At December 31, 2005, debt consisted of the following (in thousands):

Bank debt	$	___
9.6% Notes due 2012 (face value $195,000)	213,770		(1)
Floating rate convertible notes due 2023 (face value $125,000)	138,681		(2)
Total long-term debt	$	352,451

Debt at September 30, 2006 consisted of the following (in thousands):

Bank debt	$	50,000
9.6% Notes due 2012 (face value $195,000)	211,502		(1)
Floating rate convertible notes due 2023, 5.39% at September 30, 2006 (face value $125,000)	138,111		(2)
Total long-term debt	$	399,613

(1) Fair market value at June 7, 2005 (date of acquisition of Magnum Hunter) equaled $215.5 million. The subsequent noted balances represent the fair market value at date of acquisition less amortization of the premium of fair market value over face value.

(2) Fair market value at June 7, 2005 equaled $144.75 million. The subsequent noted balances represent the fair market value at date of acquisition less amortization of the premium of fair market value over face value. Paid-in-Capital was credited with $49.6 million related to the fair value of common stock associated with the convertible debt at date of acquisition.

Cimarex’s Revolving Credit Facility provides for $500 million of long-term committed credit. The facility is scheduled to mature on July 1, 2010 and is secured by mortgages on certain oil and gas properties and the stock of certain wholly-owned operating subsidiaries. At September 30, 2006, there were outstanding borrowings of $50 million under the Revolving Credit Facility at a weighted average interest rate of approximately 6.32%. We also had letters of credit for approximately $2.8 million posted against the borrowing base, leaving an unused borrowing amount of approximately $447.2 million at September 30, 2006.

The Credit Facility agreement contains both financial and non-financial covenants. Cimarex continues to comply with these covenants and does not view them as materially restrictive.

The 9.6% notes assumed in the Magnum Hunter merger have a face value of $195 million and are due March 15, 2012. The notes are unsecured and are redeemable, as a whole or in part, at Cimarex’s option, on and after March 15, 2007 at the following redemption prices (expressed as percentages of the principal amount), plus accrued interest, if any, thereon to the date of redemption.

Year	Percentage

2007	104.8	%
2008	103.2	%
2009	101.6	%
2010 and thereafter	100.0	%

The floating rate convertible senior notes were assumed in the Magnum Hunter merger and mature on December 15, 2023. The notes are senior unsecured obligations and bear interest at an annual rate equal to three-month LIBOR, reset quarterly. On September 30, 2006, the interest rate equaled 5.39%.

Holders of the convertible notes may surrender their notes for conversion into a combination of cash and shares of our common stock upon the occurrence of certain circumstances, including if the price of our common stock has been trading above the fixed conversion price of $28.99 per share. On September 29, 2006, the closing price of our common stock traded on the New York Stock Exchange was $35.19. There is not an observable market for the notes. Based on an average common stock price of $35.19, management estimates the fair value of the notes at September 30, 2006 was approximately $151.7 million (or $1,214 per bond).

In addition to the holders’ right to redeem the notes if our common stock price is above the conversion price, the holders also have the right to require Cimarex to repurchase all or a portion of the notes at a repurchase price equal to 100% of the principal amount (plus accrued interest) on December 15, 2008, 2013, and 2018. The indenture agreement also provides Cimarex with an option to redeem some or all of the notes at a redemption price equal to 100% of the principal amount (plus accrued interest) anytime after December 22, 2008.

All long-term debt is guaranteed by Cimarex and all of its subsidiaries, except Canvasback. Assets held by Canvasback consist primarily of 790 thousand shares of Cimarex stock, which is included in Cimarex’s Treasury stock.

Total borrowings at September 30, 2006 on the construction loan of Magnum Hunter’s 40% owned affiliate, Apple Tree Holdings, LLC (“Apple Tree”) were $20.6 million, of which our share was $8.2 million. We have provided a guarantee to the lender for this Construction Loan. In return for our guarantee, we received an up-front fee as well as the right to receive 55% of distributable cash flows from Apple Tree until certain financial tests are met. In the event that the Construction Loan goes into default and we have to perform under the guarantee, we will have recourse against the project and related subsidiaries.

7. Income Taxes

Federal income tax expense for the periods ended September 30, 2006 and 2005 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 other deductible costs.

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

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2006			2005			2006			2005

Current taxes (benefits)	$	(11,537	)	$	39,481		$	(7,219	)	$	57,988
Deferred taxes (benefits)	66,284			(3,475		)	174,601			32,644
	$	54,747		$	36,006		$	167,382		$	90,632

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

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2006		2005		2006		2005

Cash paid during the period for:
Interest	$	11,968	$	8,906	$	26,085	$	11,777
Capitalized interest	6,726		4,978		18,555		6,157
Income taxes (net of refunds received)	$	183	$	26,415	$	36,268	$	39,517

9. Earnings per Share and Comprehensive Income

Earnings per Share

The calculations of basic and diluted net earnings per common share are presented below (in thousands, except per share data):

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2006		2005		2006		2005

Net Income available to common stockholders for basic diluted shares	$	93,957	$	64,075	$	286,974	$	159,917

Basic weighted-average shares outstanding	82,052		82,284		82,062		58,815
Incremental shares from assumed exercise of stock options, vesting of restricted stock units and conversion of convertible senior notes	2,259		2,556		2,213		1,952
Diluted weighted-average shares outstanding	84,311		84,840		84,275		60,767

Earnings per share:
Basic	$	1.15	$	0.78	$	3.50	$	2.72
Diluted	$	1.11	$	0.76	$	3.41	$	2.63

There were stock options outstanding for 1,917,448 and 2,041,892 shares of Cimarex common stock at September 30, 2006 and 2005, respectively. All stock options and restricted units and shares were considered potentially dilutive securities for each of the periods presented.

Comprehensive Income

Comprehensive income is a term used to refer to net income plus other comprehensive income. Other comprehensive income is comprised of revenues, expenses, gains and losses that under generally accepted accounting principles are reported as separate components of shareholders’ equity instead of net income.

The components of comprehensive income are as follows (in 000’s):

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2006			2005		2006		2005
Net Income	$	93,957		$	64,075	$	286,974	$	159,917
Other comprehensive income:
Unrealized gain on derivative instruments, net of tax	20,308			—		20,308		—
Change in fair value of marketable securities available for sale	(13		)	26		20		(7		)
Total comprehensive income	$	114,252		$	64,101	$	307,302	$	159,910

10. Commitments and Contingencies

Litigation

A liability for $6.5 million for estimated future litigation settlements was recorded in the third quarter of 2005. The proposed settlement will be reviewed by the court for approval.

Cimarex has various litigation related matters in the normal course of business, none of which are material individually or in aggregate.

Other

At September 30, 2006, we had firm sales contracts to deliver approximately 2 Bcf of natural gas over the next 11 months. If this gas is not delivered, our financial commitment would be approximately $12.5 million. This commitment will fluctuate due to price volatility and actual volumes delivered. However, we believe no financial commitment will be due based on our reserves and current production levels.

Cimarex has other various delivery commitments in the normal course of business, none of which are individually material. In aggregate these commitments have a maximum amount that would be payable, if no gas is delivered, of approximately $3.1 million.

The Company has contractual commitments on oil and gas wells approved for drilling or in the process of being drilled at September 30, 2006 of approximately $68.2 million.

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

11. Property Sales

The Company’s limited partnership affiliates, Teal Hunter L.P. and Mallard Hunter L.P., sold all of their interests in oil and gas properties during the quarter ended September 30, 2006. Cimarex’s investments in these partnerships had been reflected in other assets, net. Net sales consideration received to date via distributions from the partnerships equaled $57.9 million, which are in excess of the Company’s investment balance in the partnerships. The excess distributions of $18.3 million have been recorded in other income for the quarter.

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 operations are presently focused primarily in Oklahoma, Texas, New Mexico, Kansas, Louisiana, and the Gulf of Mexico.

Our primary focus is to explore for and discover new reserves. To supplement our growth, we also consider mergers and acquisitions. On June 7, 2005, Cimarex completed the acquisition of Magnum Hunter Resources, Inc., an independent oil and gas exploration and production company with operations concentrated in the Permian Basin of West Texas and New Mexico and in the Gulf of Mexico. Terms of the merger agreement provided that Magnum Hunter stockholders receive 0.415 shares of Cimarex common stock for each share of Magnum Hunter common stock. As a result of the merger, Cimarex issued 39.7 million common shares to Magnum Hunter’s common stockholders and assumed $633 million of debt. The merger was accounted for as a purchase of Magnum Hunter by Cimarex. Results of operations from Magnum Hunter’s properties are included in our consolidated statements of operations beginning June 7, 2005.

As a result of the merger, our proved reserves tripled and production doubled. Our common shares outstanding increased by 93 percent to 82.4 million and we went from having no debt to taking on $633 million of debt. Using proceeds from property sales and cash flow in excess of capital investments, we reduced our debt to $352 million by year end 2005. Debt at September 30, 2006

equals $399.6 million. Operationally, we now have a large base of properties in the Permian Basin with operational characteristics similar to our Mid-Continent assets. The merger also extended our onshore Gulf Coast activities into the Gulf of Mexico. Overall, about 44 percent of our proved reserves are in the Permian Basin and 39 percent are in our Mid-Continent region. Our onshore Gulf Coast and Gulf of Mexico operations collectively make up 12 percent of our proved reserves.

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, wide swings in prices often have 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 and usually move up and down together with prices.

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

Extensive federal, state, and local regulation of the industry significantly affects our operations. In particular, our activities are subject to comprehensive environmental regulations. Compliance with these regulations increases the cost 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 achieve 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. In connection with the acquisition of Magnum Hunter, we acquired existing commodity derivatives, as well as in July 2006, we entered into additional derivative contracts as discussed more fully below.

Implementation of our business approach relies on our ability to fund ongoing exploration and development projects with cash flow provided by operating activities, periodic sales of non-core properties, and external sources of capital.

We project that 2006 exploration and development expenditures will approximate $1.0 billion, up from the $642 million invested in 2005. Approximately 33 percent of the expenditures will be in the Mid Continent area, 30 percent in the Permian Basin, 21 percent in the Gulf Coast area and 13 percent in the Gulf of Mexico.

Exploration and development expenditures during the third quarter of 2006 totaled $249.7 million, up from $192.9 million for the third quarter of 2005. Capital expenditures for exploration and development during the first nine months of 2006 were $804.6 million, up from $426.6 million during the first three quarters of 2005. In the nine months of 2006, we participated in drilling 429 gross (270 net) wells, with an overall completion rate of 92 percent.

Cash flow from operating activities for the nine months ended September 30, 2006 totaled $677.1 million, helping to fund our drilling program.

Based on expected cash provided by operating activities and monies available under our Senior Secured Revolving Credit Facility, we believe we are well positioned to fund the projects identified for the remainder of 2006 and beyond.

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 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 1 to our Consolidated Financial Statements included in this report. 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.

Full Cost Accounting Method and Ceiling Limitation

capitalized costs exceeded the full cost ceiling limit by $561 million before tax ($354 million after tax), after being reduced by $133 million resulting from the effect of the Company’s designated cash flow hedges (See Note 3). This amount has not been charged against earnings, because the increase in gas prices subsequent to September 30, 2006 and prior to the issuance of the financial statements indicate that the capitalized costs were not in fact impaired.

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. We market and sell natural gas for working interest partners under short term sales and supply agreements and earn a fee for such services. Revenues are recognized as gas is delivered and are reflected net of gas purchases on the accompanying consolidated statement of operations.

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, especially during interim quarters.

We use the units-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.

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 which we perform in the fourth quarter. 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 goodwill. 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 goodwill. If the estimated fair value exceeds its carrying amount, goodwill 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.

Allocation of Purchase Price

The allocation of the Magnum Hunter purchase price to oil and gas properties utilized prevailing oil and gas prices at the time of negotiations and announcement of the merger. The overall allocation of the purchase price has been finalized and the goodwill amount related to the purchase was $646.4 million.

Derivative Instruments

In connection with the Magnum Hunter merger, Cimarex recognized a $39.3 million net liability associated with Magnum Hunter’s existing commodity derivatives at the merger date (June 7, 2005). These derivative instruments have not been designated for hedge accounting treatment. As a result, Cimarex recognized a net gain of $23.6 million during the first nine months of 2006. Activity includes both non-cash mark-to-market derivative gains and losses as well as cash settlements. Cash payments related to these contracts that settled in the first nine months of 2006 totaled $15.7 million. At September 30, 2006, the liability related to these contracts was $2.7 million and is included in derivative instruments, net, in our current assets. Cimarex will continue to recognize gains and losses in future earnings until these derivative instruments mature on December 31, 2006.

In July 2006, we entered into additional derivative contracts to mitigate a portion of our potential exposure to adverse market changes in an environment of volatile gas prices. Using zero-cost collars, we hedged 29.2 million MMBTU and 14.6 million MMBTU of our anticipated Mid-Continent gas production for 2007 and 2008, respectively. At September 30, 2006, this represented approximately 62% and 38% of our current anticipated Mid-Continent gas production for 2007 and 2008, respectively.

Under the collar agreements, we will receive the difference between an agreed upon Mid-continent index price and a floor price if the index price is below the floor price. We will pay the difference between the agreed upon contracted ceiling price and the index price only if the index price is above the contracted ceiling price. No amounts are paid or received if the index price is between the contracted floor and ceiling prices. These hedges have been designated for hedge accounting treatment as cash flow hedges.

During the quarter ended September 30, 2006, we recorded an unrealized loss of $60 thousand related to the ineffective portion of the hedges. At September 30, 2006, $22.1 million and $10 million of the hedges were recorded as current and long-term assets, respectively, and an unrealized gain (net of deferred income taxes) of $20.3 million was recorded in other comprehensive income. See Note 3 to the Consolidated Financial Statements and Item 3 of this report for additional information regarding our derivative instruments.

Depending on changes in oil and gas futures markets and management’s view of underlying oil and natural gas supply and demand trends, we may increase or decrease our current hedging positions.

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.

Asset Retirement Obligations

Stock Options

The fair value of each option award is estimated as of the date of grant using the Black-Scholes option-pricing model. Expected volatilities are based on the historical volatility of our common stock. Historical data is also used to estimate option exercise, expected years until exercise and employee termination within the valuation model. The risk free interest rate is based on U.S. Treasury Securities at a constant five year fixed maturity in effect at the date of the grant.

Segment Information

Cimarex has one reportable segment (exploration and production).

Recent Accounting Developments

In July 2006, the FASB issued Interpretation 48, Accounting for Uncertainty in Income Taxes, which defines the threshold for recognizing the benefits of tax-return positions in the financial statements as “more-likely-than-not” to be sustained by the taxing authority. The term “more-likely-than-not” means a likelihood of more than 50 percent. The interpretation also requires quantitative and qualitative disclosures of estimates of tax benefits of positions taken for tax-return purposes that have not been recognized for financial reporting, if it is “reasonably possible” the estimates will significantly change in the twelve months after the balance sheet date. Along with these disclosures, a tabular presentation of significant changes during each period will be required. The Interpretation is effective as of the beginning of the first fiscal year beginning after December 15, 2006 (January 1, 2007 for calendar-year companies). We do not expect the adoption of this interpretation to have a material impact on our financial statements.

In September 2006 the Securities and Exchange Commission issued Staff Accounting Bulletin No. 108 regarding the process of quantifying misstatements within a financial statement, addressing in particular materiality analysis related to the correction of errors. The impact on the current year financial statements of correcting all misstatements, including both the carryover and reversing effects of prior year misstatements, must be quantified. Adjustment would be required if the misstatement is deemed material, after considering all relevant quantitative and qualitative factors. Materiality determinations are based on whether it is probable that the judgment of a reasonable person relying upon the report would have been changed or influenced by the inclusion or correction of the item. The periods in which the correction would be recorded would be dependent on the materiality considerations for each affected period. We do not expect the adoption of this bulletin to have a material impact on our financial statements.

Also in September 2006 the Financial Accounting Standards Board issued Statement No. 157, Fair Value Measurements, which establishes a single authoritative definition of fair value, sets out a framework for measuring fair value, and requires additional disclosures about fair-value measurements. The Statement applies only to fair-value measurements that are already required or permitted by other accounting standards and is expected to increase the consistency of those measurements. The Statement is effective for financial statements issued for fiscal years beginning after November 15, 2007 and interim periods within those fiscal years. We do not expect the adoption of Statement No. 157 to have a material impact on our financial statements.

Overview

Our results of operations are primarily impacted by changes in oil and gas prices and changes in our production volumes. Realized oil prices increased from $59.45 per barrel in the third quarter of 2005 to $66.57 per barrel in the third quarter of 2006. Realized gas prices decreased from $7.88 per Mcf in the third quarter of 2005 to $6.35 per Mcf in the third quarter of 2006.

Gas marketing revenues, net of related costs, pertain to sales of gas on behalf of third parties that are incidental to sales of our own production. Sales and costs associated with our production are reflected in gas sales and transportation expense.

We also own interests in gas gathering systems and gas processing plants that are connected to our production operations. We transport and process third party gas that is associated with our gas.

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, both the gross revenues and gross costs are shown in sales and expenses, respectively.

Production costs are composed of lease operating expenses, which generally consist of pumpers’ salaries, utilities, water disposal, maintenance and other costs necessary to operate our producing properties.

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

Depreciation, depletion and amortization of our producing properties is computed using the units-of-production method. Because the economic life of each producing well depends upon the assumed price for future sales of 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. In addition, changes in estimates of reserve quantities and estimates of future development costs or reclassifications from unproved properties to proved properties will impact 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. Expenses related to the merger are costs associated with the Magnum Hunter transaction.

Stock compensation expense consists of non-cash charges resulting from the issuance of restricted stock and restricted stock units to certain employees and the expensing of stock options resulting from the adoption of SFAS No. 123R.

Basis of Presentation

In June 2005, Cimarex acquired Magnum Hunter Resources, Inc, by issuing 0.415 shares of Cimarex common stock for each share of outstanding Magnum Hunter common stock, resulting in the issuance of 39.7 million Cimarex common shares. At September 30, 2006, Cimarex had 82.9 million shares outstanding. The merger was accounted for as a purchase of Magnum Hunter by Cimarex. The results of operations of Magnum Hunter were included in our consolidated statements of operations beginning June 7, 2005.

Certain amounts in prior years’ financial statements have been reclassified to conform to the 2006 financial statement presentation.

RESULTS OF OPERATIONS

Periods Ended September 30, 2006 Compared with Periods Ended September 30, 2005:

SUMMARY DATA:

	For the Three Months Ended						For the Nine Months Ended
	September 30,						September 30,
(in thousands or as indicated)	2006			2005			2006			2005
Net income	$	93,957		$	64,075		$	286,974		$	159,917
Per share-basic	1.15			0.78			3.50			2.72
Per share-diluted	1.11			0.76			3.41			2.63

Gas sales	$	197,460		$	245,010		$	622,841		$	488,043
Oil sales	111,801			98,459			308,911			177,829
Total oil and gas sales	$	309,261		$	343,469		$	931,752		$	665,872

Total gas volume-Mcf	31,096			31,075			94,429			69,854
Gas volume-MMcf per day	338.0			337.8			345.9			255.9
Average gas price-per Mcf	$	6.35		$	7.88		$	6.60		$	6.99

Total oil volume-thousand barrels	1,679			1,656			4,819			3,269
Oil volume-barrels per day	18,255			18,002			17,651			11,975
Average oil price-per barrel	$	66.57		$	59.45		$	64.11		$	54.40

Gas gathering and processing revenues	$	13,126		$	19,273		$	36,520		$	21,976
Gas gathering and processing costs	(7,325		)	(13,750		)	(20,264		)	(15,612		)
Gas gathering and processing margin	$	5,801		$	5,523		$	16,256		$	6,364

Gas marketing revenues, net of related costs	$	495		$	352		$	3,241		$	1,248

Costs and expenses:
Depreciation, depletion and amortization	$	104,904		$	82,826		$	290,305		$	172,493
Production	42,624			40,473			128,200			68,056
Transportation	5,845			4,237			15,636			10,319
Taxes other than income	22,912			21,418			68,392			45,913
General and administrative	10,804			8,418			31,679			23,967
Stock compensation	2,265			1,225			6,329			3,663
Expenses related to merger	—			1,402			(61		)	8,087
Loss (gain) on derivative instruments	(4,782		)	81,946			(23,598		)	83,976
Interest expense, net of capitalized interest	441			2,531			608			4,895
Asset retirement obligation accretion	1,977			1,331			4,918			2,266
Other, net	(20,137		)	3,456			(25,515		)	(700		)

Net income for the third quarter of 2006 was $94.0 million, or $1.11 per diluted share, compared to net income of $64.1 million, or $0.76 per diluted share for the same period in 2005. For the nine months ended September 30, 2006, net income was $287.0 million, or $3.41 per diluted share, compared to net income of $159.9 million, or $2.63 per diluted share, for the first nine months of 2005. The change in net income results from the effect of changes in revenues and costs, as

discussed further. The results of operations of Magnum Hunter are included in our consolidated statements of operations only for the period since the acquisition on June 7, 2005.

Oil and gas sales for the third quarter of 2006 totaled $309.3 million, compared to $343.5 million for the third quarter of 2005. The $34.2 million decrease in sales between the two periods results from $35.7 million related to lower commodity prices, offset by $1.5 million due to higher production volumes. For the nine months ended September 30, 2006, oil and gas sales increased by $265.9 million, or 40 percent, to $931.8 million from $665.9 million during the nine months of 2005. Higher production volumes (due primarily to increased production resulting from the acquisition of Magnum Hunter) increased sales by $256.0 million and higher commodity prices contributed $9.9 million to the increase between the two nine-month periods.

Realized gas prices averaged $6.35 per Mcf for the three months ended September 30, 2006, compared to $7.88 per Mcf for the third quarter of 2005. This 19.4 percent change decreased sales by $47.7 million between the two periods. Realized oil prices averaged $66.57 per barrel for the third quarter of 2006, compared to $59.45 per barrel for the same period in 2005. The increase in sales between periods resulting from this 12.0 percent improvement in oil prices totaled $12.0 million.

For the nine months ended September 30, 2006, realized gas prices decreased to $6.60 per Mcf from $6.99 per Mcf realized in the nine months of 2005. This price decrease reduced sales by $36.9 million between the two nine-month periods. Realized oil prices averaged $64.11 per barrel for the nine months of 2006, compared to $54.40 per barrel for the same period in 2005, resulting in a $46.8 million increase in sales between periods. Changes in realized prices were the direct result of overall market conditions.

Sales benefited from higher production volumes. Average gas volumes rose 0.2 MMcf per day in the third quarter of 2006 to 338.0 MMcf per day from 337.8 MMcf per day in the third quarter of 2005, resulting in $0.2 million of incremental revenues. Oil volumes averaged 18,255 barrels per day for the third quarter of 2006, compared to 18,002 barrels per day in the same period of 2005, resulting in increased revenues of $1.3 million. For the nine months of 2006, gas volumes averaged 345.9 MMcf per day and oil volumes equaled 17,651 barrels per day, compared to nine months of 2005 volumes of 255.9 MMcf per day and 11,975 barrels per day. The higher gas volumes increased sales between the two periods by $171.7 million, and higher oil volumes resulted in $84.3 million of additional revenues. The increase in sales volumes between the periods of 2006 and 2005 is due to positive drilling results during 2005 and the nine months of 2006, and the inclusion of production from Magnum Hunter operations from June 7, 2005. Daily production volumes in the Gulf of Mexico and along the Texas and Louisiana Gulf Coast area were negatively impacted during 2006 by 10 to 15 MMcf equivalents and 20 to 25 MMcf equivalents during the second and first quarters of 2006, respectively, as a result of hurricanes. No oil and gas reserves have been lost as a result of the storms and essentially all associated repair costs will be covered by insurance. The majority of these volumes have been restored.

Gas gathering and processing revenues, net of related costs, equaled $5.8 million in the third quarter of 2006, compared to $5.5 million in the third quarter of 2005. For the nine months ended September 30, 2006 and 2005, such revenues net of related costs totaled $16.3 million and $6.4 million, respectively. The increase for the nine months is due to the inclusion of related activities from Magnum Hunter operations. We own interests in gas gathering systems and gas processing plants that are connected to our production operations. We transport and process third party gas that is associated with our gas.

Gas marketing net revenues increased to $0.5 million from $0.4 million, net of related costs of $31.2 million and $45.2 million for the third quarters of 2006 and 2005, respectively. Gas marketing net revenues increased to $3.2 million from $1.2 million, net of related costs of $118.2 million and $160.6 million for the nine months of 2006 and 2005, respectively. Gas marketing revenues, net of related costs, pertain to sales of gas on behalf of third parties that is incidental to sales of our own production.

Costs and Expenses

Net costs and expenses (not including gas gathering, marketing and processing costs) were $166.9 million in the third quarter of 2006 compared to $249.3 million in the third quarter of 2005. For the nine months of 2006 and 2005, these overall costs and expenses equaled $496.9 million and $422.9 million, respectively. Depreciation, depletion and amortization (DD&A) was a large component of these changes between periods. DD&A equaled $104.9 million in the third quarter of 2006 compared to $82.8 million in the same period of 2005. For the nine months of 2006 and 2005, DD&A totaled $290.3 million and $172.5 million, respectively. On a unit of production basis, DD&A was $2.55 per Mcfe in the third quarter of 2006 compared to $2.02 per Mcfe for the third quarter of 2005. For the nine months of 2006 and 2005, DD&A on a unit of production basis equaled $2.35 per Mcfe and $1.93 per Mcfe, respectively. The increases largely stem from costs associated with Magnum Hunter operations and higher costs for reserves added during 2005 and 2006. Certain high cost wells that were determined not to be productive have influenced our per unit rates, even though overall drilling success rates have remained high.

Production costs rose $2.1 million from $40.5 million ($0.99 per Mcfe) in the third quarter of 2005 to $42.6 million ($1.04 per Mcfe) in the third quarter of 2006. For the nine months of 2006 and 2005, production costs equaled $128.2 million ($1.04 per Mcfe) and $68.1 million ($0.76 per Mcfe), respectively. The higher costs in 2006 resulted primarily from the inclusion of costs associated with Magnum Hunter operations, higher field operating expenses from an expanded number of properties, and higher maintenance costs.

Transportation costs increased from $4.2 million, or $0.10 per Mcfe, in the third quarter of 2005 to $5.8 million, or $0.14 per Mcfe, in the third quarter of 2006. Transportation costs for the nine months of 2006 equaled $15.6 million compared to $10.3 million for the same period in 2005. The increase is the result of expiring contracts being renewed with increased current market rates, and the inclusion of transportation costs associated with Magnum Hunter operations.

Taxes other than income were $1.5 million greater, rising from $21.4 million in the third quarter of 2005 to $22.9 million in the same period of 2006. For the nine months of 2006 and 2005, these costs totaled $68.4 million and $45.9 million, respectively. The increases between periods resulted from increases in oil and gas sales stemming from inclusion of Magnum Hunter operations and higher production volumes.

General and administrative (G&A) expenses increased $2.4 million from $8.4 million in the third quarter of 2005 to $10.8 million in the third quarter of 2006. G&A expenses for the nine months of 2006 equaled $31.7 million compared to $24.0 million for the same period of 2005. The increases between periods are due to an expansion of staff and higher employee-benefit costs.

Stock compensation expense consists of non-cash charges resulting from the issuance of restricted stock, restricted stock units and stock option awards net of amounts capitalized. Stock compensation increased from $3.7 million in the nine months of 2005 to $6.3 million in the nine months of 2006.

As of September 30, 2005, expenses associated with the Magnum Hunter merger totaled $8.1 million. Of the $8.1 million, $3.6 million was due to the acceleration of vesting of stock options and restricted stock units resulting from change of control provisions under our stock incentive plan becoming effective due to the Magnum Hunter merger. The remaining $4.5 million consisted of $3.0 million of general integration costs, $1.0 million for retention bonuses, and $0.5 million of related financing costs.

Another component of net costs and expenses for 2006 and 2005 was the gain and loss on derivative instruments. In connection with the Magnum Hunter merger, Cimarex recognized a $39.3 million liability associated with Magnum Hunter’s existing commodity derivatives at the merger date (June 7, 2005). These derivative instruments were not designated for hedge accounting treatment. As a result, Cimarex recognized net gains for the quarter and nine months ended September 30, 2006 of $4.8 million and $23.6 million, respectively. From the date of the merger through the third quarter of 2005 we recorded a total net loss of $84.0 million. Activity includes both non-cash mark-to-market derivative gains and losses as well as cash settlements. Cash payments related to these contracts that settled in the quarter and nine months ended September 2006 totaled $4.2 million and $15.7 million, respectively, and $15.6 million from the date of the merger through the third quarter of 2005. The derivative liability at September 30, 2006 related to these contracts equals $2.7 million. Cimarex will continue to recognize gains and losses as these remaining derivative instruments expire through December 31, 2006. Actual gains and losses to be recognized may differ materially from the current fair value of amounts recorded.

To mitigate a portion of the potential exposure to adverse market changes in an environment of volatile gas prices, we entered into additional derivative contracts in July 2006. These derivatives have been designated for hedge accounting treatment as cash flow hedges. Changes in the fair value of the hedges, to the extent the hedge is effective, are recognized in other comprehensive income until the hedged item is settled. Changes in the fair value of the hedge resulting from ineffectiveness are recognized currently as unrealized gains or losses in other income and expense in the consolidated statements of operations. Gains and losses upon settlement of the cash flow hedges will be recognized in gas revenues in the period the contracts are settled. During the quarter ended September 30, 2006, we recognized an unrealized loss of $60 thousand related to the ineffective portion of the derivative contracts.

Net interest expense in the third quarter of 2006 of $0.4 million is comprised of $7.1 million of interest expense, offset by $6.7 million of capitalized interest resulting from interest recognized on borrowings associated with costs incurred to bring properties under development, not being amortized, to their intended use. Net interest expense in the third quarter of 2005 of $2.5 million is comprised of $7.5 million of interest expense, offset by $5.0 million of capitalized interest. Net interest expense in the nine months of 2006 of $0.6 million is comprised of $19.2 million of interest expense, offset by $18.6 million of capitalized interest. Net interest expense in the nine months of 2005 of $4.9 million is comprised of $11.1 million of interest expense, offset by $6.2 million of capitalized interest. The increase in the various components of the 2006 net interest amount from 2005, results from amounts associated with the debt assumed in the Magnum Hunter merger and an increase in costs incurred to bring properties under development, not being amortized, to their intended use. Prior to the Magnum Hunter merger, Cimarex had no outstanding debt.

Other net income for the third quarter of 2006 equaled $20.1 million, compared to other net expense of $3.5 million for the third quarter of 2005. For the nine months of 2006, other net income equaled $25.5 million, compared to $0.7 million for the nine months of 2005. The components of other income and expense consist of miscellaneous items that will vary from period to period, including income and loss in equity investees. The large increase from 2005 to 2006 is due primarily to liquidation distributions received in excess of the Company’s investment in the Company’s limited

partnership affiliates, Teal Hunter L.P. and Mallard Hunter L.P. These partnerships sold all of their interests in oil and gas properties during the quarter ended September 30, 2006. Cimarex’s investments in these partnerships had been reflected in other assets, net. Net sales consideration received via distributions from the partnerships equaled $57.8 million, which are in excess of the Company’s investment balance in the partnerships. The excess distributions of $18.3 million have been recorded in other income for 2006.

Income tax expense

Income tax expense totaled $54.7 million for the third quarter of 2006 versus $36.0 million for the third quarter of 2005. Tax expense equaled a combined Federal and state effective income tax rate of 36.8 percent and 36.0 percent in the third quarters of 2006 and 2005, respectively. Income tax expense for the nine months of 2006 equaled $167.4 million compared to $90.6 million for the same period of 2005, equating to combined Federal and state effective income tax rates of 36.8 percent and 36.2 percent, respectively. We estimate that of our nine-month 2006 income tax expense $7.2 million is a current benefit.

LIQUIDITY AND CAPITAL RESOURCES

Cash Flows

Our primary source of capital is cash flow generated from operating activities. Prices we receive for 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 large 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.

Cash flow provided by operating activities for the nine months of 2006 was $677.1 million, compared to $417.5 million for the nine months ended September 30, 2005. The increase in 2006 from the earlier period resulted primarily from higher oil and gas production and oil prices, and the acquisition of Magnum Hunter.

Higher revenues from oil and gas sales facilitated the funding of our exploration and development expenditure program for the nine months of 2006.

Cash flow used in investing activities for the nine months of 2006 was $762.4 million, compared to $328.4 million for the nine months ended September 30, 2005. The increase in 2006 stemmed from a larger exploration and development program.

Cash flow provided by financing activities for the nine months of 2006 was $31.7 million versus $177.4 million used in the nine months of 2005. The cash provided in financing activities in 2006 resulted from $50.0 million of net borrowings on long-term debt and $2.7 million of proceeds from the issuance of common stock from stock option exercises, offset by $11.0 million of treasury stock acquired and $10.0 million of dividends paid. The cash used in financing activities in 2005 resulted primarily from the payment of $188.4 million on debt assumed in the Magnum Hunter acquisition, offset by proceeds from issuance of common stock.

Financial Condition

As of September 30, 2006, stockholders’ equity totaled $2.9 billion, up from $2.6 billion at December 31, 2005. The increase resulted primarily from nine-month net income of $287.0 million. At September 30, 2006 our cash balance equaled $8.1 million.

Working Capital

Working capital at September 30, 2006 was $46.8 million, compared to $31.6 million at December 31, 2005. The increase is primarily the result of settlement of a majority of the liability associated with derivative contracts outstanding at December 31, 2005 and entering into new derivative contracts for which a current asset was recorded at September 30, 2006. 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

At December 31, 2005, debt consisted of the following (in thousands):

Bank debt	$	—
9.6% Notes due 2012 (face value $195,000)	213,770		(1)
Floating rate convertible notes due 2023 (face value $125,000)	138,681		(2)

Total long-term debt	$	352,451

Debt at September 30, 2006 consisted of the following (in thousands):

Bank debt	$	50,000
9.6% Notes due 2012 (face value $195,000)	211,502		(1)
Floating rate convertible notes due 2023, 5.39% at September 30, 2006 (face value $125,000)	138,111		(2)
Total long-term debt	$	399,613

The Credit Facility agreement contains both financial and non-financial covenants. Cimarex continues to comply with these covenants and does not view them as materially restrictive.

Year	Percentage

2007	104.8	%
2008	103.2	%
2009	101.6	%
2010 and thereafter	100.0	%

Contractual Obligations and Material Commitments

At September 30, 2006, we had contractual obligations and material commitments as follows:

	Payments Due by Period
	(In thousands)
Contractual Obligations	Total		Less than 1 Year		1-3 Years			3-5 Years			More than 5 Years
Long-term debt(1)	$	370,000	$	—	$	—		$	—		$	370,000
Fixed-Rate interest payments(1)	102,960		18,720		37,440			37,440			9,360
Commodity derivatives	2,726		2,726		—			—			—
Operating leases	32,285		5,053		10,169			8,034			9,029
Drilling commitments	68,227		68,227		—			—			—
Asset retirement obligation	118,479		4,320		—		(2)	—		(2)	—		(2)
Other liabilities	5,630		190		63			47			5,330

(1)See item 3: Interest Rate Risk for more information regarding fixed and variable rate debt.

(2)We have excluded the long term asset retirement obligations because we are not able to precisely predict the timing of these amounts.

At September 30, 2006, we had firm sales contracts to deliver approximately 2.0 Bcf of natural gas over the next 11 months. If this gas is not delivered, our financial commitment would be approximately $12.5 million. This commitment will fluctuate due to price volatility and actual volumes delivered. However, we believe no financial commitment will be due based on our reserves and current production levels.

All of the noted 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.

2006 Outlook

Our projected 2006 exploration and development expenditure program of approximately $1.0 billion 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 2006 are estimated to increase to levels above those realized in late 2005. Should factors beyond our control change, 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.

Production estimates for 2006 range from 450 to 455 MMcfe per day. Revenues will be dependent not only on the level of oil and gas actually produced, but also the prices that will be realized. During 2005, our realized prices averaged $8.05 per Mcf of gas and $55.25 per barrel of oil. Prices can be very volatile and the possibility of 2006 realized prices being less than they were in 2005 is high.

ITEM 3. QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT MARKET RISK

Commodity Price Risk

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 third quarter of 2006 ranged from $6.05 per Mcf to $6.88 per Mcf. Oil prices ranged from $60.79 per barrel to $70.61 per barrel. Monthly gas price realizations during the nine months of 2006 ranged from $5.61 per Mcf to $8.43 per Mcf. Oil prices for the nine months of 2006 ranged from $58.10 per barrel to $70.61 per barrel. It is impossible to predict future oil and gas prices with any degree of certainty.

In July 2006, we entered into derivative contracts to mitigate a portion of our potential exposure to adverse market changes in the Mid-Continent region, in an environment of volatile gas prices. These arrangements, which were based on prices available in the financial markets at the time the contracts were entered into, will be settled in cash and will not require physical delivery of hydrocarbons. These hedges have been designated for hedge accounting treatment as cash flow hedges under SFAS No. 133 and therefore, gains and losses upon settlement of the hedges will be recognized in gas revenue in the period the contracts are settled. We believe that we have sufficient production volumes such that the hedge contract transactions will occur as expected.

We also have Nymex indexed derivative hedging contracts that we acquired in connection with the Magnum Hunter merger. These contracts were not designated for hedge accounting treatment. Realized and unrealized gains and losses associated with these hedges are recognized currently in costs and expenses associated with operating income.

The following tables reflect the volumes, weighted average contract prices and fair values of the contracts we have in place as of September 30, 2006. We are exposed to risks associated with these contracts arising from volatility in commodity prices and the unlikely event of non-performance by the counterparties to the agreements. See Note 3 to the Consolidated Financial Statements and Derivative Instruments in Item 2 of this report for additional information regarding our derivative instruments.

Mid-Continent
Weighted Average

Fair Value

Commodity

Type

Volume/Day

Duration

Price

(000’s)

Natural Gas

Collars

80,000 MMBTU

Jan 07 – Dec 07

$7.00 - $10.17

22,674

Natural Gas

Collars

40,000 MMBTU

Jan 08 – Dec 08

$7.00 - $9.90

9,424

32,098

At September 30, 2006, the weighted average Mid-Continent prices for the 2007 and 2008 contracts approximated $6.83 and $7.15, respectively.

Nymex
Weighted Average

Fair Value

Commodity

Type

Volume/Day

Duration

Price

(000’s)

Natural Gas

Collar

20,000 MMBTU

Oct 06 – Dec 06

$5.25 - $6.30

(130

)

Crude Oil

Collar

1,000 BBL

Oct 06 – Dec 06

$30.00 - $35.85

(2,596

)

(2,726

)

Weighted average Nymex prices at September 30, 2006 for the remaining three months of 2006 approximated $5.72 per Mcf of gas and $62.51 per barrel of oil.

Interest Rate Risk

Fixed and Variable Rate Debt. Cimarex assumed fixed and variable rate debt as part of the acquisition of Magnum Hunter. These agreements expose the company to market risk related to changes in interest rates. The company has a credit facility that bears interest at either a Base rate or a Eurodollar rate at the Company’s option.

The following table presents the carrying and fair value of the company’s debt along with average interest rates as of September 30, 2006. The fair value for the Convertible Notes was based on an average price per share of $35.19 for Cimarex common stock. The fair value for the fixed rate Senior Notes was based on their last traded value before September 30, 2006.

Expected Maturity Dates (in thousands of dollars)	2010		2012		2023		Total		Book Value		Fair Value

Variable Rate Debt:
Bank debt (a)	$	50,000	$	—	$	—	$	50,000	$	50,000	$	50,000
Convertible Notes (b)	$	—	$	—	$	125,000	$	125,000	$	138,111	$	151,744

Fixed Rate Debt:
Senior Notes (c)	$	—	$	195,000	$	—	$	195,000	$	211,502	$	200,850

(a) At September 30, 2006, the weighted average interest rate on outstanding borrowings under the credit facility was approximately 6.32%.

(b) The interest rate on the convertible notes is 5.39%. The rate on these notes is equal to the three month LIBOR, reset quarterly. A holder of these notes has the right to require us to repurchase all or a portion of these notes on December 15, 2008, 2013, and 2018. The repurchase will be equal to the face value of the notes plus accrued and unpaid interest up to the date of repurchase. Included in Paid in Capital is $49.6 million related to the fair value of common stock associated with the convertible debt.

ITEM 4. CONTROLS AND PROCEDURES

EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES

Cimarex’s management, with the participation of the Chief Executive Officer (“CEO”) and Chief Financial Officer (“CFO”), have evaluated the effectiveness of Cimarex’s disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e)) as of September 30, 2006 and concluded that the disclosure controls and procedures are effective in providing reasonable assurance that the information required to be disclosed in reports filed with the SEC is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. The disclosure controls and procedures are also designed to provide reasonable assurance that such information is accumulated and communicated to our management, including the CEO and CFO, as appropriate to allow such persons to make timely decisions regarding required disclosures.

Our management does not expect that our disclosure controls and procedures will prevent all errors and all fraud. The design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Based on the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty and that breakdowns can occur because of simple errors or mistakes. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the controls. The design of any system of controls is also based upon certain assumptions about the likelihood of future events. Therefore, a control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Our disclosure controls and procedures are designed to provide such reasonable assurances of achieving our desired control objectives, and our CEO and CFO have concluded, as of September 30, 2006, that our disclosure controls and procedures are effective in achieving that level of reasonable assurance.

CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING

There have been no changes in our internal controls over financial reporting or in other factors that occurred during the fiscal quarter ended September 30, 2006, that have materially affected or are reasonably likely to materially affect our internal controls over financial reporting.

PART II

ITEM 6 – EXHIBITS

(a)

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) Forms 8-K filed during quarter ended September 30, 2006:

Date Filed	Items Reported

July 25, 2006	Update on oil and gas production volumes and operations
August 2, 2006	Second Quarter Earnings
September 21, 2006	Declaration of Quarterly Dividend

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.

November 6, 2006


	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
	Vice President, Chief Accounting Officer and Controller
	(Principal Accounting Officer)