8-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

CURRENT REPORT

Pursuant to Section 13 OR 15(d) of The Securities Exchange Act of 1934

Date of Report (Date of earliest event reported):  July 17, 2009

Cimarex Energy Co.

(Exact name of registrant as specified in its charter)

Delaware	001-31446	45-0466694
(State or other jurisdiction	(Commission	(IRS Employer
of incorporation)	File Number)	Identification No.)

1700 Lincoln Street, Suite 1800
Denver, Colorado 80203

(Address and Zip Code of principal executive offices)

(303) 295-3995

(Registrant’s telephone number, including area code)

N/A

(Former name or former address, if changed since last report.)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

o Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

o Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

o Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

o Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Item 8.01  Other Events.

During the first quarter of 2009, Cimarex Energy Co. adopted the provisions of Financial Accounting Standards Board (“FASB”) Staff Position APB 14-1 (APB 14-1), Accounting for Convertible Debt Instruments That May Be Settled in Cash upon Conversion (Including Partial Cash Settlement) and FASB Staff Position EITF 03-6-1 (EITF 03-6-1), Determining Whether Instruments Granted in Share Based Payment Transactions Are Participating Securities.  The requirements of these provisions are applied retrospectively to our financial statements.

APB 14-1 requires that the debt and equity components of convertible debt instruments that can be settled wholly or partly in cash upon conversion (including instruments issued prior to adoption, such as our floating rate convertible senior notes due 2023) are to be accounted for separately.  EITF 03-6-1 provides that unvested share based payment awards that contain non forfeitable rights to dividends or dividend equivalents (such as our unvested restricted stock and restricted stock units) are “participating securities” (as defined by EITF 03-6 as securities that may participate in undistributed earnings with common stock, whether that participation is conditioned upon the occurrence of a specified event or not, regardless of the form of participation), and therefore should be included in computing earnings per share using the two-class earnings allocation method.

In this Current Report on Form 8-K, we are filing our audited consolidated financial statements as of December 31, 2008 and 2007 and for each of the years in the three-year period ended December 31, 2008, which have been recast to give effect to the retrospective application of the adoption of APB 14-1 and EITF 03-06-1.  We also are filing in this Current Report on Form 8-K the following sections: Business (including Forward-Looking Statements and Certain Risks), Selected Financial Data, Management’s Discussion and Analysis of Financial Condition and Results of Operations and Qualitative and Quantitative Disclosures About Market Risk, which give effect to the retrospective application of these standards.  The following table reflects a summary comparison of certain financial statement line items affected by the retrospective application of these standards.

Summary of the Retrospective Application of Changes

(Amounts in thousands except per share data)

	For the Years Ended December 31,
	2008			2007			2006
Changes to the Consolidated Statements of Operations and Earnings Per Share:
As previously reported
Interest Expense	$	32,064		$	37,966		$	29,940
Amortization of fair value of debt	$	(709	)	$	(1,908	)	$	(3,784	)
Gain on early extinguishment of debt	$	(9,569	)	$	(5,099	)	—
Income (loss) before taxes	$	(1,430,298	)	$	544,625		$	544,324
Income tax expense (benefit)	$	(528,613	)	$	198,156		$	198,605
Net income (loss)	$	(901,685	)	$	346,469		$	345,719
Earnings (loss) per share:
Basic	$	(11.07	)	$	4.23		$	4.21
Diluted	$	(11.07	)	$	4.09		$	4.11

2

Summary of the Retrospective Application of Changes

(Amounts in thousands except per share data)

	For the Years Ended December 31,
	2008			2007			2006
After retrospective application:
Interest Expense	$	33,079		$	39,105		$	31,130
Amortization of fair value of debt	—			$	(1,146	)	$	(3,024	)
(Gain) loss on early extinguishment of debt	$	10,058		$	(5,099	)	—
Income (loss) before taxes	$	(1,451,649	)	$	542,724		$	542,374
Income tax expense (benefit)	$	(536,404	)	$	197,462		$	197,893
Net income (loss)	$	(915,245	)	$	345,262		$	344,481
Earnings (loss) per share to common shareholders:
Basic
Distributed	$	0.24		$	0.18		$	0.16
Undistributed	(11.46		)	3.97			3.96
	$	(11.22	)	$	4.15		$	4.12
Diluted
Distributed	$	0.24		$	0.18		$	0.16
Undistributed	(11.46		)	3.87			3.89
	$	(11.22	)	$	4.05		$	4.05
	December 31,
	2008			2007
Changes to the Consolidated Balance Sheets:
As previously reported
Long-term debt	$	591,223		$	487,159
Deferred income taxes	$	499,634		$	1,076,223
Paid-in capital	$	1,855,825		$	1,842,690
Retained earnings	$	526,998		$	1,448,763
After retrospective application:
Long-term debt	$	587,630		$	462,216
Deferred income taxes	$	500,945		$	1,085,325
Paid-in capital	$	1,874,834		$	1,861,699
Retained earnings	$	510,271		$	1,445,595

The information in this Current Report on Form 8-K should be read in conjunction with our Annual Report on Form 10-K for the fiscal year ended December 31, 2008, our Quarterly Report on Form 10-Q for the fiscal quarter ended March 31, 2009 and our other filings with the U.S. Securities and Exchange Commission.

3

Item 9.01  Financial Statements and Exhibits.

Exhibit Number	Description
23.1	Consent of KPMG LLP.
23.2	Consent of DeGolyer and MacNaughton.
99.1	Item 1 – Business (including Forward-Looking Statements and Certain Risks), Item 6 – Selected Financial Data, Item 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operations, Item 7A – Qualitative and Quantitative Disclosures About Market Risk and Item 8 – Consolidated Financial Statements of Cimarex Energy Co.

4

SIGNATURES

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 hereunto duly authorized.

	CIMAREX ENERGY CO.
	By:	/s/ Paul Korus
	Name:	Paul Korus
	Title:	Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer)
Dated: July 17, 2009

5

EXHIBIT INDEX

Exhibit Number	Description
23.1	Consent of KPMG LLP.
23.2	Consent of DeGolyer and MacNaughton.
99.1	Item 1 – Business (including Forward-Looking Statements and Certain Risks), Item 6 – Selected Financial Data, Item 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operations, Item 7A – Qualitative and Quantitative Disclosures About Market Risk and Item 8 – Consolidated Financial Statements of Cimarex Energy Co.

6

EX-23.1

EXHIBIT 23.1

Consent of Independent Registered Public Accounting Firm

The Board of Directors

Cimarex Energy Co.:

We consent to the incorporation by reference in the registration statements No. 333-100235 on Form S-8 and No. 333-158683 on Form S-3 of Cimarex Energy Co. of our report dated February 27, 2009, except for the last two paragraphs of note 3, notes 4, 6, 7, 9, and 17, which are as of July 17, 2009,  with respect to the consolidated balance sheets of Cimarex Energy Co. and subsidiaries as of December 31, 2008 and 2007, and the related consolidated statements of operations, stockholders’ equity and comprehensive income(loss), and cash flows for each of the years in the three-year period ended December 31, 2008, which report appears in the Form 8-K of Cimarex Energy Co. dated July 17, 2009.

Our report refers to the Company’s adoption of Financial Accounting Standards Board (FASB) Staff Position APB 14-1, Accounting for Convertible Debt Instruments That May Be Settled in Cash Upon Conversion (Including Partial Cash Settlement) and FASB Staff Position EITF 03-6-1, Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities, effective January 1, 2009, which have been applied retrospectively in the consolidated financial statements referred to above.

/s/ KPMG LLP

KPMG LLP

Denver, Colorado

July 17, 2009

EX-23.2

EXHIBIT 23.2

Consent of DeGolyer and MacNaughton

July 15, 2009

Cimarex Energy Co.

1700 Lincoln Street, Suite 1800

Denver, CO  80203-4518

Ladies and Gentlemen:

We hereby consent to the reference to DeGolyer and MacNaughton and to the reference to the review of proved oil and gas reserves as of December 31, 2008,  estimated by Cimarex Energy Company (Cimarex) that were presented in our letter report dated January 19, 2009, under the headings “Business,” “Properties — Oil and Gas Properties and Reserves,” and “Notes to the Consolidated Financial Statements — Unaudited Supplemental Oil and Gas Disclosures, Oil and Gas Reserve Information”  in the Annual Report on Form 10-K, as amended, of Cimarex for the fiscal year ended December 31, 2008, and to the incorporation by reference thereof under the heading of “Experts” in the registration statements on Form S-3 (No. 333-158683) and on Form S-8 (No. 333-100235) of Cimarex.

Very truly yours,

/s/ DeGolyer and MacNaughton

DeGOLYER and MacNAUGHTON

EX-99.1

EXHIBIT 99.1

Forward-Looking Statements

Throughout this Report, 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 Exchange Act of 1934. All statements, other than statements of historical facts, that address activities, events, outcomes and other matters that Cimarex plans, expects, intends, assumes, believes, budgets, predicts, forecasts, projects, estimates or anticipates (and other similar expressions) will, should or may occur in the future are forward-looking statements. These forward-looking statements are based on management’s current belief, based on currently available information, as to the outcome and timing of future events. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements in this Report. Forward-looking statements include statements with respect to, among other things:

·      amount, nature and timing of capital expenditures;

·drilling of wells;

·reserve estimates;

·timing and amount of future production of oil and natural gas;

·operating costs and other expenses;

·cash flow and anticipated liquidity;

·estimates of proved reserves, exploitation potential or exploration prospect size; and

·marketing of oil and natural gas.

We caution you that these forward-looking statements are subject to all of the risks and uncertainties, many of which are beyond our control, incident to the exploration for and development, production and sale of oil and gas. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of goods and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating proved oil and natural gas reserves and in projecting future rates of production and timing of development expenditures and other risks described herein.

Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data and the interpretation of such data by our engineers. As a result, estimates made by different engineers often vary from one another. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions could change the timing of future production and development drilling. Accordingly, reserve estimates are generally different from the quantities of oil and natural gas that are ultimately recovered.

Should one or more of the risks or uncertainties above or elsewhere in this Report cause our underlying assumptions to be incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements.

All forward-looking statements, express or implied, included in this Report and attributable to Cimarex are qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that Cimarex or persons acting on its behalf may issue. Cimarex does not undertake any obligation to update any forward-looking statements to reflect events or circumstances after the date of filing this Report with the Securities and Exchange Commission, except as required by law.

1

ITEM 1.  BUSINESS

General

Cimarex Energy Co. is an independent oil and gas exploration and production company. Our operations are mainly located in Texas, Oklahoma, New Mexico, Kansas, Louisiana and Wyoming. Proved oil and gas reserves as of year-end 2008 totaled 1.3 Tcfe, consisting of 1.1 Tcf of gas and 45.2 million barrels of oil and natural gas liquids. Of total proved reserves, 80 percent are gas and 82 percent are classified as proved developed. Our 2008 production averaged 485.8 MMcfe per day, comprised of 348.2 MMcf of gas per day and 22,937 barrels of oil per day. We operate the wells that account for 83 percent of our total proved reserves and approximately 81 percent of production.

Our corporate headquarters are located at 1700 Lincoln Street, Suite 1800, Denver, Colorado 80203 and our main telephone number at that location is (303) 295-3995. Cimarex is a Delaware corporation.

Our Web site address is www.cimarex.com. There you will find our news releases, annual reports, proxy statements, 10-Ks, 10-Qs, 8-Ks, insider (Section 16) filings and all other SEC filings. We have also posted our Code of Ethics, Code of Business Conduct, Corporate Governance Guidelines, Audit Committee Charter and Governance Committee Charter. Copies of these documents are also available in print upon a written or telephone request to our Corporate Secretary. Throughout this Report we use the terms “Cimarex,” “Company,” “we,” “our,” and “us” to refer to Cimarex Energy Co. and its subsidiaries.

History

Cimarex was formed in February 2002 as a wholly owned subsidiary of Tulsa-based Helmerich & Payne, Inc. On September 30, 2002, Cimarex was completely spun off to Helmerich and Payne shareholders and simultaneously merged with Denver-based Key Production Company, Inc. Our common stock began trading on the New York Stock Exchange on October 1, 2002 under the symbol XEC.

On June 7, 2005, we acquired Dallas-based Magnum Hunter Resources, Inc. in a $1.5 billion stock-for-stock merger including assumption of liabilities. That transaction effectively tripled our proved reserves and doubled our production. Since 2005, we have principally focused on exploration and development drilling and have funded these investments with cash flow provided by operating activities.

Market Conditions

During the fourth quarter of 2008, severe disruptions in the credit markets and reductions in global economic activity caused significant decreases in oil and gas prices. Oil prices fell from a mid-year 2008 peak of $130 per barrel to $37 per barrel at year-end. Gas prices fell from $12.00 per Mcf in mid 2008 to $4.50 per Mcf in the fourth quarter 2008. The large decrease in prices had a significant adverse impact on the amount of cash flow available to invest in exploration and development drilling, the present value of our proved reserves, our stock price and total market capitalization.

The continued credit crisis and related turmoil in the global financial system may have further impact on our business and our financial position. A further decrease in oil and gas prices would have a negative impact on our earnings, cash flow available for reinvestment, and future growth in proved reserves and production. Our ability to access the capital markets to fund our growth may also be restricted. Further, the economic situation could have an impact on our lenders and customers, causing them to fail to meet their obligations to us.

As a result of lower commodity prices we have sharply reduced our drilling activity. Our exploration and development capital investment is expected to decrease from $1.4 billion in 2008 to $400-$600 million in 2009, depending on prices and corresponding cash flow.

2

2008 Summary

During 2008 we accomplished the following positive highlights:

·Oil and gas sales increased 38 percent to a record $1.9 billion.

·Cash flow from operating activities increased 37 percent to an all-time high of $1,367.5 million.

·Production averaged 485.8 MMcfe per day in 2008, increasing throughout the year to a fourth quarter peak of 493.7 MMcfe per day.

·Added 215 Bcfe of proved reserves from extensions, discoveries and improved recovery, replacing 121 percent of production.

·Increased our western Oklahoma, Anadarko-Woodford position to 98,000 net acres, including a $180.9 million purchase of 38,000 net acres.

·Ended the year with a debt to total capitalization ratio of 20 percent.

However, largely as a result of the collapse in oil and gas prices we also experienced the following negative consequences:

·$1.4 billion after-tax, non-cash full-cost ceiling test write-down of oil and gas properties.

·Negative price-related revisions to proved reserves of 157 Bcfe, resulting in an overall 9% decrease in our proved reserves to 1.3 Tcfe.

Business Strategy

Our principal business objective is to profitably grow our proved reserves and production for the long-term benefit of our investors. Our strategy centers on maximizing cash flow from our producing properties and profitably reinvesting that cash flow in exploration and development.

A cornerstone to our approach is a detailed evaluation of each drilling decision based on its risk-adjusted discounted cash flow rate of return on investment. Our analysis includes estimates and assessments of potential reserve size, geologic and mechanical risks, expected costs, future production profiles and future oil and gas prices.

During 2008, our cash flow from operating activities totaled approximately $1.4 billion. Our 2008 investment in ongoing exploration and development activity also approximated $1.4 billion.

Our integrated teams of geoscientists, landmen and petroleum engineers continually generate new prospects to maintain a rolling portfolio of drilling opportunities in different basins with varying geologic characteristics. We have a centralized exploration management system that measures actual results and provides feedback to the originating exploration team in order to help them improve and refine future investment decisions. We believe that our detailed technical analysis and disciplined risk assessment is a competitive advantage and best positions us to continue to achieve attractive rates of return and consistent increases in proved reserves and production.

While our primary focus is drilling, we occasionally consider acquisition and merger opportunities that allow us to either enhance our competitive position in existing core areas or to add new areas. The 2005 Magnum Hunter acquisition significantly increased our presence in the Permian Basin and enhanced our Mid-Continent operations in the Texas Panhandle. In 2008, we acquired 38,000 net acres in our Western Oklahoma Woodford Shale core area. The cost of that acquisition was $180.9 million.

3

Conservative use of leverage has long been a part of our financial strategy. We believe that maintaining a strong balance sheet enables us to withstand low prices and challenging capital markets. At year-end 2008 we had $588 million of long-term debt and our debt to total capitalization ratio was 20 percent.

Business Segments

Cimarex has one reportable segment (exploration and production).

Exploration and Development Activity Overview

Our operations are currently focused in the Mid-Continent region which consists of Oklahoma, the Texas Panhandle and southwest Kansas; the Permian Basin region of west Texas and southeast New Mexico; and the Gulf Coast areas of Texas, south Louisiana, and offshore Louisiana. We also have operations in Michigan and Wyoming.

A summary of our 2008 exploration and development (E&D) activity by region is as follows.

	Exploration and Development Capital		Gross Wells Drilled	Net Wells Drilled	Completion Rate		12/31/08 Proved Reserves (Bcfe)
	(in millions)
Mid-Continent	$	648	256	138	96	%	609
Permian Basin	549		164	117	98	%	442
Gulf Coast	210		28	21	54	%	74
Other	31		2	1	50	%	214
	$	1,438	450	277	94	%	1,339

Company-wide, we participated in drilling 450 gross wells during 2008, with an overall completion rate of 94 percent. On a net basis, 253 of 277 total wells drilled during 2008 were completed as producers.

Our 2008 E&D investment totaled $1,438 million and resulted in 215 Bcfe of proved reserve additions. Of total expenditures, 45 percent were invested in projects located in the Mid-Continent area; 38 percent in the Permian Basin; and 15 percent in the Gulf Coast.

Mid-Continent

Our Mid-Continent region encompasses operations in Oklahoma, southwest Kansas and the Texas Panhandle. We drilled 256 gross (138 net) Mid-Continent wells during 2008, completing 96 percent as producers. The bulk of this drilling activity is directed at gas-bearing geological formations in the Anadarko Basin of western Oklahoma and Texas Panhandle. Full-year 2008 investment in this area was $648 million, or 45 percent of total E&D capital.

We drilled 82 gross (22 net) Anadarko Basin wells, of which 95 percent were completed as producers. Our drilling activity mainly targets the Woodford Shale, Red Fork and Clinton Lake/Atoka formations at depths ranging from 11,000-15,000 feet. Our largest investment in this area is the Anadarko-Woodford Shale play. Our activities began in this area in 2007, and our early success in drilling led to leasing a significant land position. We have approximately 98,000 net acres in the play, which includes the purchase of 38,000 net acres in the fourth quarter of 2008 for $180.9 million.

The Woodford formation is a shale interval that varies in thickness from 120-280 feet at depths of 12,000-16,000 feet throughout our acreage. During 2008, we drilled 22 (10 net) horizontal Anadarko-Woodford wells. At year-end 2008 our production was over 50 MMcfe per day gross. Our acreage position developed on 160-acre well spacing has multiple years of drilling opportunity.

4

In the Texas Panhandle, we drilled 118 gross (84 net) wells with 96 percent being completed as producers. Most of these wells targeted the Granite Wash formation in Roberts and Hemphill counties at depths ranging from 11,000-14,000 feet.

Permian Basin

Our Permian Basin operations cover both west Texas and southeast New Mexico. In total, we drilled 164 gross (117 net) wells in this area during 2008 completing 160 gross (114 net) as producers. Full-year 2008 investment in this area totaled $549 million, or 38 percent of total E&D capital. Our 2008 drilling focused on horizontal oil plays.

In West Texas, a total of 82 gross (59 net) wells were drilled, of which 100 percent were successful. Geologic targets include the Bone Spring, Devonian and Ellenburger formations. In Ward and Reeves Counties drilling totaled 30 gross (25 net) horizontal Third Bone Spring oil wells.

Southeast New Mexico drilling totaled 82 gross (58 net) wells with 95 percent being completed as producers. The primary formations we target in this area are the Abo/Wolfcamp, Morrow, Atoka and Strawn at depths ranging from 9,000-14,000 feet. Our largest investment was in drilling 33 gross (24 net) horizontal Abo/Wolfcamp oil wells during 2008.

Gulf Coast

Our onshore Gulf Coast focus area generally encompasses coastal Texas, south Louisiana and Mississippi. This effort is generally characterized by a greater reliance on three-dimensional (3-D) seismic information for prospect generation, larger potential reserves per well, greater drilling depths and lower success rates.

We also own interests in offshore Louisiana on the Gulf of Mexico shelf (water depth less than 300 feet). We obtained all of our offshore position through the Magnum Hunter acquisition. Our 2008 activity in this area consisted primarily of workovers and recompletions.

Full-year 2008 investment in the Gulf Coast area was $210 million, or 15 percent of total E&D capital. During 2008 we drilled 28 gross (21 net) Gulf Coast wells, realizing a 54 percent success rate. A significant portion of the drilling occurred in Liberty and Hardin Counties, Texas. Targeting the Yegua and Cook Mountain formations at approximately 10,500 feet, we drilled 18 gross (15 net) wells with a success rate of 50 percent.

Other

We have a large development project in Sublette County, Wyoming where we are developing the deep Madison gas formation and constructing a gas processing plant. During 2008 we invested a total of $23.9 million in this project and our cumulative investment in this project is $32.4 million. We presently expect that we will initiate gas sales from this project in 2010. Our total investment, including planned expansion, will approximate $208 million.

5

Production and Pricing Information

The following table sets forth certain information regarding the company’s production volumes and the average oil and gas prices received:

	Years Ending December 31,
	2008		2007		2006
Production Volumes
Gas (MMcf)	127,444		119,937		124,733
Oil (MBbls)	8,395		7,445		6,529
Equivalent (MMcfe)	177,814		164,607		163,907
Net Average Daily Volumes:
Gas (MMcf)	348.2		328.6		341.7
Oil (MBbls)	22.9		20.4		17.9
Equivalent (MMcfe)	485.8		451.0		449.1
Average Sales Price
Gas ($/Mcf)	$	8.43	$	7.05	$	6.50
Oil ($/Bbl)	$	96.03	$	69.71	$	61.96

Total 2008 oil and gas production grew eight percent averaging 485.8 MMcfe per day as compared to 451.0 MMcfe per day in 2007. Gas production in 2008 increased six percent to 348.2 MMcf per day and oil production grew 12 percent to 22,937 barrels per day. The gas volume growth resulted primarily from Texas Panhandle and Anadarko-Woodford shale drilling. The growing oil volume was principally a result of successful horizontal Third Bone Spring and Abo/Wolfcamp drilling in the Permian Basin.

We sold our 2008 gas at an average price of $8.43 per Mcf, which was 20 percent higher than the $7.05 per Mcf we received in 2007. We had natural gas collars for calendar year 2008 covering 40,000 MMBtu per day. The collars increased our 2008 average realized gas price by $0.09 per Mcf. For a discussion of derivatives, see Note 3 of Notes to Consolidated Financial Statements contained herein. Our annual average realized oil price during 2008 increased 38 percent to $96.03 per barrel from $69.71 per barrel in 2007.

Strong global demand and overall tight commodity market conditions for oil, natural gas and natural gas liquids for the first nine months of 2008 resulted in overall higher average realized price in 2008 compared to 2007. During the fourth quarter of 2008, reductions in global economic activity and energy demands caused significant decreases in oil and gas prices. Year-end 2008 oil and gas prices fell 50-70% from their mid-year peak. Our overall average fourth quarter equivalent price realization was approximately 50% below our average third quarter equivalent price.

The following table summarizes Cimarex’s daily production by region for 2008 and 2007.

	2008 Average Daily Production			2007 Average Daily Production
	Oil (MBbl/d)	Gas (MMcf/d)	Total (MMcfe/d)	Oil (MBbl/d)	Gas (MMcf/d)	Total (MMcfe/d)
Mid-Continent	5.6	190.3	223.9	5.4	160.2	192.3
Permian Basin	12.9	88.6	166.2	9.5	87.2	144.3
Gulf Coast	4.3	65.8	91.3	5.3	75.0	106.9
Other	0.1	3.5	4.4	0.2	6.2	7.5
	22.9	348.2	485.8	20.4	328.6	451.0

Our largest producing area is the Mid-Continent region. During 2008 our Mid-Continent production averaged 223.9 MMcfe per day, or 46 percent of our total 2008 production. Successful drilling programs in the Texas Panhandle and the Anadarko Basin helped boost our Mid-Continent production by 16 percent in 2008. The Permian Basin contributed 166.2 MMcfe per day in 2008, which was 34 percent of our total production for this period. Production increased 15 percent as a result of successful horizontal oil drilling in the Abo/Wolfcamp formations in southeast New Mexico and in the West Texas Third Bone Spring formation. Gulf Coast production

6

averaged 91.3 MMcfe per day during 2008, or 19 percent of total production. Gulf Coast volumes decreased in 2008 as a result of natural production declines and no new drilling in the Gulf of Mexico.

Acquisitions and Divestitures

Cimarex acquired Magnum Hunter Resources, Inc, on June 7, 2005. Magnum Hunter was an independent oil and gas exploration and production company with operations concentrated in the Permian Basin and the Gulf of Mexico. Magnum’s oil and gas properties were valued at $1.8 billion and resulted in the addition of 886.7 Bcfe of proved reserves (60 percent gas and 73 percent proved developed).

During 2007 we sold various interests in oil and gas properties located in West Texas, California and Gulf of Mexico. In total we sold 123 Bcfe of proved reserves for $177 million. During 2008 we sold various interests in oil and gas properties located in South Texas. In total we sold 17 Bcfe of proved reserves for $38.1 million.

During 2007 we purchased $40.9 million of assets, with the largest acquisition being in the Texas Panhandle Area. During 2008 we purchased 38,000 acres in western Oklahoma, Anadarko Basin Woodford Shale play for $180.9 million. In total we have approximately 98,000 net acres in the play.

Marketing

Our oil and gas production is sold under various short-term arrangements at market-responsive prices. We sell our oil at various prices directly or indirectly tied to field postings and monthly futures contract prices on the New York Mercantile Exchange (NYMEX). Our gas is sold under pricing mechanisms related to either monthly index prices on pipelines where we deliver our gas or the daily spot market.

We sell our oil and gas to a broad portfolio of customers. Our largest customer accounted for ten percent of 2008 revenues. Because over 95 percent of our gas production is from wells in Kansas, Oklahoma, Texas and Louisiana, most of our customers are either from those states or nearby end-user market centers. We regularly monitor the credit worthiness of all our customers and may require parental guarantees, letters of credit or prepayments when we deem such security is necessary.

Employees

We employed 831 people on December 31, 2008. None of our employees are subject to collective bargaining agreements.

Competition

The oil and gas industry is highly competitive. Competition is particularly intense for prospective undeveloped leases and purchases of proved oil and gas reserves. There is also competition for rigs and related equipment we use to drill for and produce oil and gas. Our competitive position is also highly dependent on our ability to recruit and retain geological, geophysical and engineering expertise. We compete for prospects, proved reserves, oil-field services and qualified oil and gas professionals with major and diversified energy companies and other independent operators that have larger financial, human and technological resources than we do.

We compete with integrated, independent and other energy companies for the sale and transportation of oil and gas to marketing companies and end users. The oil and gas industry competes with other energy industries that supply fuel and power to industrial, commercial and residential consumers. Many of these competitors have greater financial and human resources. The effect of these competitive factors cannot be predicted.

Title to Oil and Gas Properties

We undertake title examination and perform curative work at the time we lease undeveloped acreage, prepare for the drilling of a prospect or acquire proved properties. We believe that the titles to our properties are good and defensible, and are in accordance with industry standards. Nevertheless, we are involved in title disputes

7

from time to time which result in litigation. Our oil and gas properties are subject to customary royalty interests, liens incidental to operating agreements, tax liens and other burdens and minor encumbrances, easements and restrictions.

Government Regulation

Oil and gas production and transportation is subject to extensive federal, state and local laws and regulations. Compliance with existing laws often is difficult and costly, but has not had a significantly adverse effect upon our operations or financial condition. In recent years, we have been most directly affected by federal and state environmental regulations and energy conservation rules. We are also indirectly affected by federal and state regulation of pipelines and other oil and gas transportation systems.

The states in which we conduct operations establish requirements for drilling permits, the method of developing new fields, the size of well spacing units, drilling density within productive formations and the unitization or pooling of properties. In addition, state conservation laws include requirements for waste prevention, establish limits on the maximum rate of production from wells, generally prohibit the venting or flaring of natural gas and impose certain requirements regarding the ratability of production. The effect of these regulations is to limit the amounts of oil and natural gas that we can produce from our wells and to limit the number of wells or locations at which we can drill.

Environmental Regulation.  Various federal, state and local laws regulating the discharge of materials into the environment, or otherwise relating to the protection of the environment, directly impact oil and gas exploration, development and production operations, and consequently may impact our operations and costs. These laws and regulations govern, among other things, emissions to the atmosphere, discharges of pollutants into waters, underground injection of waste water, the generation, storage, transportation and disposal of waste materials, and protection of public health, natural resources and wildlife. These laws and regulations may impose substantial liabilities for noncompliance and for any contamination resulting from our operations and may require the suspension or cessation of operations in affected areas.

We are committed to environmental protection and believe we are in substantial compliance with applicable environmental laws and regulations. We routinely obtain permits for our facilities and operations in accordance with the applicable laws and regulations. There are no known issues that have a significant adverse effect on the permitting process or permit compliance status of any of our facilities or operations. We have made, and will continue to make, expenditures in our efforts to comply with environmental regulations and requirements. These costs are considered a normal, recurring cost of our ongoing operations and not an extraordinary cost of compliance with government regulations.

We do not anticipate that we will be required under current environmental laws and regulations to expend amounts that will have a material adverse effect on our financial position or operations. However, due to continuing changes in these laws and regulations, we are unable to predict with any reasonable degree of certainty any potential delays in development plans that could arise, or our future costs of complying with these governmental requirements. We do maintain levels of insurance customary in the industry to limit our financial exposure in the event of a substantial environmental claim resulting from sudden, unanticipated and accidental discharges of oil, produced water or other substances.

Gas Gathering and Transportation.  The Federal Energy Regulatory Commission (FERC) requires interstate gas pipelines to provide open access transportation. FERC also enforces the prohibition of market manipulation by any entity, and the facilitation of the sale or transportation of natural gas in interstate commerce. Interstate pipelines have implemented these requirements, providing us with additional market access and more fairly applied transportation services and rates. FERC continues to review and modify its open access and other regulations applicable to interstate pipelines.

Under the Natural Gas Policy Act (NGPA), natural gas gathering facilities are expressly exempt from FERC jurisdiction. What constitutes “gathering” under the NGPA has evolved through FERC decisions and judicial review of such decisions. We believe that our gathering systems meet the test for non-jurisdictional “gathering” systems under the NGPA and that our facilities are not subject to federal regulations. Although exempt from FERC

8

oversight, our natural gas gathering systems and services may receive regulatory scrutiny by state and Federal agencies regarding the safety and operating aspects of the transportation and storage activities of these facilities.

In addition to using our own gathering facilities, we may use third-party gathering services or interstate transmission facilities (owned and operated by interstate pipelines) to ship our gas to markets.

Additional proposals and proceedings that might affect the oil and gas industry are pending before the U.S. Congress, FERC, state legislatures, state agencies and the courts. We cannot predict when or whether any such proposals may become effective and what effect they will have on our operations. We do not anticipate that compliance with existing federal, state and local laws, rules or regulations will have a material adverse effect upon our capital expenditures, earnings or competitive position.

Federal and State Income and Other Local Taxation

Cimarex and the petroleum industry in general are affected by both federal and state income tax laws, as well as other local tax regulations involving ad valorem, personal property, franchise, severance and other excise taxes. We have considered the effects of these provisions on our operations and do not anticipate that there will be any undisclosed impact on our capital expenditures, earnings or competitive position.

Certain Risks

The following risks and uncertainties, together with other information set forth in this Report, should be carefully considered by current and future investors in our securities. If any of the following risks and uncertainties develop into actual events, this could have a material adverse affect on our business, financial condition or results of operations and could negatively impact the value of our common stock.

Oil and gas prices fluctuate due to a number of uncontrollable factors, creating a component of uncertainty in our development plans and overall operations. Continued declines in prices adversely affect our financial results and rate of growth in proved reserves and production.

The oil and gas markets are very volatile, and we cannot predict future oil and natural gas prices. The price we receive for our oil and natural gas production heavily influences our revenue, profitability, access to capital and future rate of growth. The prices we receive for our production depend on numerous factors beyond our control. These factors include, but are not limited to, changes in global supply and demand for oil and gas, the actions of the Organization of Petroleum Exporting Countries, the level of global oil and gas exploration and production activity, weather conditions, technological advances affecting energy consumption, domestic and foreign governmental regulations, proximity and capacity of oil and gas pipelines and other transportation facilities and the price and technological advancement of alternative fuels.

During the fourth quarter of 2008, severe disruptions in the credit markets and reductions in global economic activity caused significant decreases in oil and gas prices. Oil and gas prices fell 50-70% from the mid-year 2008 peak to the end of the year and 30-60% from the third to the fourth-quarter 2008.  The dramatic decrease in prices significantly decreased the amount available to invest in exploration and development drilling, the present value of our proved reserves and our stock price and corresponding market capitalization. As a result of the drop in commodity prices in 2008, we recorded $1.4 billion after-tax, full-cost ceiling test write-down of proved properties book-value.

Our proved oil and gas reserves and production volumes decrease in quantity unless we successfully replace the reserves we produce with new discoveries or acquisitions. For the foreseeable future, we expect to make substantial capital investments for the exploration and development of new oil and gas reserves to replace the reserves we produce and to increase our total proved reserves. Historically, we have paid for these types of capital expenditures with cash flow provided by our production operations. Low prices also reduce the amount of oil and gas that we can economically produce and may cause us to curtail, delay or defer certain exploration and development projects. Moreover, our ability to borrow under our bank credit facility and to raise additional debt or equity capital to fund acquisitions would also be impacted.

9

If oil and natural gas prices decrease further, we may be required to take additional write-downs of the carrying values of our oil and gas properties and/or our goodwill.

Accounting rules require that we review the carrying value of our oil and gas properties and goodwill for possible impairment at the end of each reporting period. If prices fall further, we may incur additional impairment charges in the future, which could have a material adverse effect on our results of operations in the period taken.

The global financial crisis may have impacts on our business and financial condition that we currently cannot predict.

The continued credit crisis and related turmoil in the global financial system may have an impact on our business and our financial condition, and we may face challenges if conditions in the financial markets do not improve. Our ability to access the capital markets may be restricted at a time when we would like, or need, to raise financing, which could have an impact on our flexibility to react to changing economic and business conditions. The economic situation could have an impact on our lenders or customers, causing them to fail to meet their obligations to us.

Failure of our exploration and development program to find commercial quantities of new oil and gas reserves could negatively affect our financial results and future rate of growth.

Most of our wells produce from reservoirs characterized by high initial production rates which decline rapidly and stabilize within three to five years. In order to replace the reserves depleted by production and to maintain or grow our total proved reserves and overall production levels, we must locate and develop new oil and gas reserves or acquire producing properties from others. While we may from time to time seek to acquire proved reserves, our main business strategy is to grow through drilling. Without successful exploration and development, our reserves, production and revenues could decline rapidly, which would negatively impact our results of operations.

Exploration and development involves numerous risks, including the risk that no commercially productive oil or gas reservoirs will be discovered. Exploration and development can also be unprofitable, not only from dry wells, but from productive wells that do not produce sufficient reserves to return a profit.

Our drilling operations may be curtailed, delayed or canceled as a result of several factors, including unforeseen poor drilling conditions, title problems, unexpected pressure or irregularities in formations, equipment failures, accidents, adverse weather conditions, compliance with environmental and other governmental requirements, and the cost of, or shortages or delays in the availability of, drilling rigs and related equipment.

The high-rate production characteristics of our properties subject us to high reserve replacement needs and require significant capital expenditures to replace our reserves.

Unless we conduct successful development activities or acquire properties containing proved reserves, our proved reserves will decline as they are produced. Producing natural gas and oil reservoirs are generally characterized by declining production rates that vary depending on reservoir characteristics and other factors. Because of the high-rate production profiles of our properties, replacing produced reserves is more difficult for us than for companies whose reserves have longer-life production profiles. This imposes greater reinvestment risk for our company as we may not be able to continue to economically replace our reserves.

Our proved reserve estimates may be inaccurate and future net cash flows are uncertain.

Estimates of total proved oil and gas reserves (consisting of proved developed and proved undeveloped reserves) and associated future net cash flow depend on a number of variables and assumptions. Among others, changes in any of the following factors may cause estimates to vary considerably from actual results:

·production rates, reservoir pressure, and other subsurface information;

10

·future oil and gas prices;

·assumed effects of governmental regulation;

·future operating costs;

·future property, severance, excise and other taxes incidental to oil and gas operations;

·capital expenditures;

·workover and remedial costs; and

·Federal and state income taxes.

The estimation of the category of proved undeveloped reserves can be subject to an even greater possibility of revision. At December 31, 2008, 18 percent of our total proved reserves are categorized as proved undeveloped. Of these proved undeveloped reserves, 89 percent are related to a project in Wyoming.

Our proved oil and gas reserve estimates are prepared by Cimarex engineers in accordance with guidelines established by the Securities and Exchange Commission (SEC). DeGolyer and MacNaughton, independent petroleum engineers, reviewed our reserve estimates for properties that comprised at least 80 percent of the discounted future net cash flows before income taxes, using a 10 percent discount rate, as of December 31, 2008.

The values referred to in this Report should not be construed as the current market value of our proved reserves. In accordance with SEC guidelines, the estimated discounted net cash flow from proved reserves is based on prices and costs as of the date of the estimate, whereas actual future prices and costs may be materially different.

We have been an early entrant into new or emerging plays; as a result, our drilling results in these areas are uncertain, and the value of our undeveloped acreage will decline and we may incur impairment charges if drilling results are unsuccessful.

New or emerging plays have limited or no production history. Consequently, we are unable to use past drilling results in those areas to help predict our future drilling results. Therefore, our cost of drilling, completing and operating wells in these areas may be higher than initially expected, and the value of our undeveloped acreage will decline if drilling results are unsuccessful. Furthermore, if drilling results are unsuccessful, we may be required to write down the carrying value of our undeveloped acreage in new or emerging plays.

Our business depends on oil and natural gas transportation facilities, most of which are owned by others.

The marketability of our oil and natural gas production depends in large part on the availability, proximity and capacity of pipeline systems owned by third parties. The lack of available capacity on these systems and facilities could result in the shut-in of producing wells or the delay or discontinuance of drilling plans for properties. The lack of availability of these facilities for an extended period of time could negatively affect our revenues. Federal and state regulation of oil and natural gas production and transportation, tax and energy policies, changes in supply and demand, pipeline pressures, damage to or destruction of pipelines and general economic conditions could adversely affect our ability to produce, gather and transport oil and natural gas.

The differential between the NYMEX or other benchmark price of oil and natural gas and the wellhead price we receive could have a material adverse effect on our results of operations, financial condition and cash flows.

The prices that we receive for our oil and natural gas production generally trade at a discount to the relevant benchmark prices, such as NYMEX, that are used for calculating hedge positions. The difference between the benchmark price and the price we receive is called a differential. We cannot accurately predict oil and natural gas differentials. Increases in the differential between the benchmark price for oil and natural gas and the wellhead price we receive could have a material adverse effect on our results of operations, financial condition and cash flows.

11

Competition in our industry is intense and many of our competitors have greater financial and technological resources.

We operate in the competitive area of oil and gas exploration and production. Many of our competitors are large, well-established companies that have larger operating staffs and greater capital resources than we do. These companies may be able to pay more for exploratory prospects and productive oil and gas properties and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit.

We are subject to complex laws and regulations that can adversely affect the cost, manner or feasibility of doing business.

Exploration, development, production and sale of oil and gas are subject to extensive Federal, state and local laws and regulations, including complex environmental laws. We may be required to make large expenditures to comply with environmental and other governmental regulations. Failure to comply with these laws and regulations may result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties. Matters subject to regulation include discharge permits for drilling operations, drilling bonds, spacing of wells, unitization and pooling of properties, environmental protection, and taxation. Our operations create the risk of environmental liabilities to the government or third parties for any unlawful discharge of oil, gas or other pollutants into the air, soil or water. In the event of environmental violations, we may be charged with remedial costs. Pollution and similar environmental risks generally are not fully insurable. Such liabilities and costs could have a material adverse effect on our financial condition and results of operations.

Our limited ability to influence operations and associated costs on properties not operated by us could result in economic losses that are partially beyond our control.

Other companies operate approximately 19 percent of our net production. Our success in properties operated by others depends upon a number of factors outside of our control, including timing and amount of capital expenditures, the operator’s expertise and financial resources, approval of other participants in drilling wells, selection of technology and maintenance of safety and environmental standards. Our dependence on the operator and other working interest owners for these projects could prevent the realization of our targeted returns on capital in drilling or acquisition activities.

Our business involves many operating risks that may result in substantial losses for which insurance may be unavailable or inadequate.

Our operations are subject to hazards and risks inherent in drilling for oil and gas, such as fires, natural disasters, explosions, formations with abnormal pressures, casing collapses, uncontrollable flows of underground gas, blowouts, surface cratering, pipeline ruptures or cement failures, and environmental hazards such as natural gas leaks, oil spills and discharges of toxic gases. Any of these risks can cause substantial losses resulting from injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution and other environmental damages, regulatory investigations and penalties, suspension of our operations and repair and remediation costs. In addition, our liability for environmental hazards may include conditions created by the previous owners of properties that we purchase or lease.

We maintain insurance coverage against some, but not all, potential losses. We do not believe that insurance coverage for all environmental damages that could occur is available at a reasonable cost. Losses could occur for uninsurable or uninsured risks, or in amounts in excess of existing insurance coverage. The occurrence of an event that is not fully covered by insurance could harm our financial condition and results of operation.

We may not be able to generate enough cash flow to meet our debt obligations.

At December 31, 2008, we had total long-term debt of $587.6 million, consisting of $220 million of bank debt, $350 million of unsecured 7.125% Senior Notes and $17.6 million of Convertible Notes ($19.45 million face value). Subject to the limits contained in the agreements governing our senior revolving credit facility, we would

12

have been able to incur up to $1 billion of debt as of December 31, 2008, only $500 million of which is currently committed. We have demands on our cash resources in addition to interest expense and principal on our long-term debt, including, among others, operating expenses and capital expenditures.

Our ability to pay the principal and interest on our long-term debt and to satisfy our other liabilities will depend upon our future performance and our ability to repay or refinance our debt as it becomes due. Our future operating performance and ability to refinance will be affected by economic and capital market conditions, our financial condition, results of operations and prospects and other factors, many of which are beyond our control. Our ability to meet our debt service obligations may also be affected by changes in prevailing interest rates, as borrowing under our existing senior revolving credit facility and our Convertible Notes bear interest at floating rates.

Our business may not generate sufficient cash flow from operations, nor could there be adequate future sources of capital to enable us to service our indebtedness, or to fund our other liquidity needs. If we are unable to service our indebtedness and fund our operating costs, we will be forced to adopt alternative strategies that may include:

·reducing or delaying capital expenditures;

·seeking additional debt financing or equity capital;

·selling assets; or

·restructuring or refinancing debt.

We may be unable to complete any such strategies on satisfactory terms, if at all. Our inability to generate sufficient cash flows to satisfy our debt obligations, or to refinance our indebtedness on commercially reasonable terms, would materially and adversely affect our financial condition and results of operations.

The instruments governing our indebtedness contain various covenants limiting the discretion of our management in operating our business.

The indentures governing our senior subordinated notes and credit agreement contain various restrictive covenants that may potentially limit our management’s discretion in certain respects. In particular, these agreements will limit our and our subsidiaries’ ability to, among other things:

·pay dividends on, redeem or repurchase our capital stock or redeem or repurchase our subordinated debt;

·make loans to others;

·make investments;

·incur additional indebtedness or issue preferred stock;

·create certain liens;

·sell assets;

·enter into agreements that restrict dividends or other payments from our restricted subsidiaries to us;

·consolidate, merge or transfer all or substantially all of the assets of us and our restricted subsidiaries taken as a whole;

·engage in transactions with affiliates;

13

·enter into hedging contracts;

·create unrestricted subsidiaries; and

·enter into sale and leaseback transactions.

In addition, our revolving credit agreement requires us to maintain a debt to EBITDA ratio (as defined in the credit agreement) of less than 3.0 to 1 and a working capital ratio of greater than 1 to 1. Also, the indentures under which we issued our senior unsecured notes restrict us from incurring additional indebtedness, subject to certain exceptions, unless our fixed charge coverage ratio (as defined in the indentures) is at least 2.25 to 1. If we were in violation of this covenant, then we may not incur additional indebtedness above our $1.0 billion revolving credit facility. See Note 6, Long-term Debt, in Notes to Consolidated Financial Statements for further information.

If we fail to comply with the restrictions in the indentures governing our senior notes or credit facility or any other subsequent financing agreements, a default may allow the creditors, if the agreements so provide, to accelerate the related indebtedness as well as any other indebtedness to which a cross- acceleration or cross-default provision applies. In addition, lenders may be able to terminate any commitments they had made to make available further funds.

Our acquisition activities may not be successful, which may hinder our replacement of reserves and adversely affect our results of operations.

We evaluate opportunities and engage in bidding and negotiating for acquisitions, some of which are substantial. Under certain circumstances, we may pursue acquisitions of businesses that complement or expand our current business and acquisition and development of new exploration prospects that complement or expand our prospect inventory. We may not be successful in identifying or acquiring any material property interests, which could hinder us in replacing our reserves and adversely affect our financial results and rate of growth. Even if we do identify attractive opportunities, there is no assurance that we will be able to complete the acquisition of the business or prospect on commercially acceptable terms. If we do complete an acquisition, we must anticipate difficulties in integrating its operations, systems, technology, management and other personnel with our own. These difficulties may disrupt our ongoing operations, distract our management and employees and increase our expenses.

Competition for experienced, technical personnel may negatively impact our operations.

Our exploratory and development drilling success depends, in part, on our ability to attract and retain experienced professional personnel. The loss of any key executives or other key personnel could have a material adverse effect on our operations. In particular, our Chairman and Chief Executive Officer, F.H. Merelli, has over 48 years of oil and gas experience and is well known in the industry. The loss of his services for any reason could adversely affect our business, revenues and results of operations. As we continue to grow our asset base and the scope of our operations, our future profitability will depend on our ability to attract and retain qualified personnel, particularly individuals with a strong background in geology, geophysics, engineering and operations.

There are inherent limitations in all control systems, and misstatements due to error or fraud may occur and not be detected.

While we have taken actions designed to address compliance with the internal control, disclosure control and other requirements of the Sarbanes-Oxley Act of 2002 and the rules and regulations promulgated by the SEC implementing these requirements, there are inherent limitations in its ability to control all circumstances. See Item 9A of this Report for a complete discussion of controls and procedures. Our management, including our Chief Executive Officer and Chief Financial Officer, does not expect that our internal controls and disclosure controls will prevent all error and all fraud. 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. In addition, the design of a control system must reflect the fact that there are resource constraints and the benefit of controls must be relative to their costs. Because of 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, in our company have been detected. These inherent

14

limitations include the realities that judgments in decision-making can be faulty and that breakdowns can occur because of simple errors or mistakes. Further, controls can be circumvented by individual acts of some persons, by collusion of two or more persons, or by management override of the controls. The design of any system of controls also is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Over time, a control may be inadequate because of changes in conditions, such as growth of the company or increased transaction volume, or the degree of compliance with the policies or procedures may deteriorate. Because of inherent limitations in a control system, misstatements due to error or fraud may occur and not be detected.

The Cimarex certificate of incorporation, by-laws and stockholders’ rights plan include provisions that could discourage an unsolicited corporate takeover and could prevent stockholders from realizing a premium on their investment.

The certificate of incorporation and by-laws of Cimarex provide for a classified board of directors with staggered terms, restrict the ability of stockholders to take action by written consent and prevent stockholders from calling a meeting of the stockholders. In addition, Delaware General Corporation Law imposes restrictions on business combinations with interested parties. Cimarex also has adopted a stockholders’ rights plan. The stockholders’ rights plan, the certificate of incorporation and the by-laws may have the effect of delaying, deferring or preventing a change in control of Cimarex, even if the change in control might be beneficial to Cimarex stockholders.

15

ITEM 6.  SELECTED FINANCIAL DATA

The selected financial data set forth below should be read in conjunction with the consolidated financial statements and accompanying notes thereto provided in Item 8 of this Report.

	For the Years Ended December 31,
	2008			2007		2006		2005		2004
Operating results:
Revenues	$	1,970,347		$	1,430,513	$	1,265,400	$	1,117,241	$	475,164
Net income (loss)	(915,245		)	345,262		344,481		327,603		153,592
Earnings (loss) per share to unrestricted common stockholders:
Basic
Distributed	$	0.24		$	0.18	$	0.16	$	0.00	$	0.00
Undistributed	(11.46		)	3.97		3.96		3.94		3.61
	$	(11.22	)	$	4.15	$	4.12	$	3.94	$	3.61
Diluted
Distributed	$	0.24		$	0.18	$	0.16	$	0.00	$	0.00
Undistributed	(11.46		)	3.87		3.89		3.86		3.54
	$	(11.22	)	$	4.05	$	4.05	$	3.86	$	3.54
Cash dividends declared per share	.24			.18		.16		—		—
Balance sheet data:
Total assets	4,164,933			5,362,794		4,829,750		4,180,335		1,105,446
Total debt	587,630			462,216		416,823		323,657		—
Stockholders’ equity	2,351,647			3,275,128		2,993,192		2,613,740		700,712
Other financial data:
Oil and gas sales	1,880,891			1,364,622		1,215,411		1,072,422		472,389
Oil and gas capital expenditures	1,620,778			1,023,434		1,074,673		2,462,826		296,429
Proved Reserves:
Gas (MMcf)	1,067,333			1,122,694		1,090,362		1,004,482		364,641
Oil (MBbls)	45,202			58,250		59,797		64,710		14,063
Total equivalent (MMcfe)	1,338,545			1,472,195		1,449,146		1,392,742		449,020

16

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

The following discussion and analysis should be read in conjunction with our Consolidated Financial Statements included in Item 8 of this Report. Certain amounts in prior years’ financial statements have been reclassified to conform to the 2008 financial statement presentation. This discussion also includes forward- looking statements. Please refer to “Forward- Looking Statements” above for important information about these types of statements.

OVERVIEW

We are an independent oil and gas exploration and production company with operations entirely located in the United States. We have determined that our business is comprised of only one segment because our gathering, processing and marketing activities are ancillary to our production operations and are not separately managed.

We seek to achieve profitable growth in proved reserves and production primarily through exploration and development. We generally fund our growth with cash flow provided by our operating activities. To achieve a consistent rate of growth and mitigate risk, we have historically maintained a blended portfolio of low, moderate, and higher risk exploration and development projects. To further mitigate risk, we have chosen to seek geologic and geographic diversification by operating in multiple basins. Our oil and gas reserves and operations are mainly located in Texas, Oklahoma, New Mexico, Kansas, Louisiana and Wyoming.

To supplement our growth and to provide for new drilling opportunities, we also consider mergers and acquisitions. In 2005 we acquired Magnum Hunter Resources, Inc, in a stock-for-stock merger with a total transaction value of approximately $2.1 billion. Magnum Hunter was a Dallas-based 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. During 2007 we purchased $40.9 million of assets, with the largest acquisition being in the Texas Panhandle area. In October 2008 we acquired 38,000 net acres in our western Oklahoma, Anadarko Basin Woodford shale play, at a total cost of $180.9 million. We have increased our position in the play to approximately 98,000 net acres.

From time to time we also consider selling certain assets. In 2007, we sold $177.0 million of non-core properties. The two largest sales were $87.5 million for our West Texas Spraberry oil properties and $53.5 million for our Gulf of Mexico Main Pass area operated properties. During 2008, we sold 17 Bcfe of proved reserves for $38.1 million.

Market Conditions

During the fourth quarter of 2008, severe disruptions in the credit markets and reductions in global economic activity caused significant decreases in oil and gas prices. The dramatic decrease in prices had a significant adverse impact on the amount of cash flow available to invest in exploration and development drilling, the present value of our proved reserves, our stock price and market capitalization.

The continued credit crisis and related turmoil in the global financial system may have further impact on our business and our financial position if conditions in the financial markets do not improve. Our ability to access the capital markets may be restricted, which could have an impact on our flexibility to react to changing economic and business conditions. Further, the economic situation could have an impact on our lenders or customers, causing them to fail to meet their obligations to us.

As a result of lower commodity prices we have sharply reduced our drilling activity. Our exploration and development capital investment is expected to decrease from $1.4 billion in 2008 to $400-$600 million in 2009, depending on prices and corresponding cash flow.

17

2008 Summary

During 2008 we accomplished the following positive operating and financial highlights:

·Oil and gas sales increased 38 percent to a record $1.9 billion.

·Cash flow from operating activities increased 37 percent to an all-time high of $1,367.5 million.

·Production averaged 485.8 MMcfe per day in 2008, increasing throughout the year to a fourth quarter peak of 493.7 MMcfe per day.

·Added 215 Bcfe of proved reserves from extensions, discoveries and improved recovery, replacing 121 percent of production.

·Increased our western Oklahoma, Anadarko-Woodford position to 98,000 net acres, including a $180.9 million purchase of 38,000 net acres.

·Ended the year with a debt to total capitalization ratio of 20 percent.

However, largely as a result of the collapse in oil and gas prices we also experienced the following negative consequences:

·$1.4 billion after-tax, non-cash full-cost ceiling test write-down of oil and gas properties.

·Negative price-related revisions to proved reserves of 157 Bcfe, resulting in an overall 9% decrease in our proved reserves to 1.3 Tcfe.

Oil and Gas Prices

While our revenues are a function of both production and prices, wide swings in prices have had the greatest impact on our results of operations. Our annual average realized gas price increased from $7.05 per Mcf in 2007 to $8.43 per Mcf in 2008; and oil prices increased from $69.71 per barrel in 2007 to $96.03 per barrel in 2008.

Strong global demand and overall tight commodity market conditions for oil, natural gas and natural gas liquids for the first nine months of 2008 resulted in overall higher average realized prices in 2008 compared to 2007. During the fourth quarter of 2008, reductions in global economic activity and energy demands caused significant decreases in oil and gas prices. Year-end 2008 oil and gas prices fell 50-70% from their mid-year peak. Our overall average fourth quarter equivalent price realization was approximately 50% below our average third quarter equivalent price.

In addition to supply and demand, oil and gas prices are affected by seasonal, economic and geo-political factors that we can neither control nor predict. However, we made limited use of hedging transactions during 2007 and 2008 to somewhat reduce price risk as discussed further below.

	Years Ended December 31,
	2008		2007		2006
Gas Prices:
Average Henry Hub price ($/Mcf)	$	9.04	$	6.86	$	7.23
Average realized sales price ($/Mcf)	$	8.43	$	7.05	$	6.50
Effect of hedges ($/Mcf)	$	0.09	$	0.23	$	—
Oil Prices:
Average WTI Cushing price ($/Bbl)	$	99.65	$	72.28	$	66.22
Average realized sales price ($/Bbl)	$	96.03	$	69.71	$	61.96

18

On an energy equivalent basis, 72% of our 2008 aggregate production was natural gas. A $0.10 per Mcf change in our average realized gas sales price would have resulted in approximately a $12.7 million change in our gas revenues. Similarly, 28% of our production was crude oil. A $1.00 per barrel change in our average realized crude oil sales price would have resulted in approximately an $8.4 million change in our oil revenues.

In July 2006 we entered into certain derivative contracts covering approximately 24% of our overall 2007 gas production and 11% of our 2008 gas volumes. We executed cash flow effective hedges by purchasing $7.00/MMbtu put options on a portion of our 2007 and 2008 Mid-Continent gas production. We used the proceeds from selling call options on the same volume of gas to pay for the puts, thus establishing what is commonly known as a “zero-cost collar.” We hedged 29.2 million MMbtu and 14.6 million MMbtu for 2007 and 2008, respectively. See Note 3 to the Consolidated Financial Statements for additional information regarding our derivative instruments.

Reserve replacement and Growth

Because oil and gas are non-renewable forms of energy resources, exploration and production companies face the challenge of resource depletion and natural production decline. Our operations also entail significant complexities that require the use of advanced technologies and highly trained personnel. Even when modern exploration technology is properly used, the interpreter still may not know conclusively if hydrocarbons will be present, the rate at which they will be produced, or economic viability. Future growth will continue to depend upon our ability to economically add reserves in excess of production.

Year end 2008 total proved oil and gas reserves decreased by 9% from 1.47 Tcfe to 1.34 Tcfe. This decrease includes production of 177.8 Bcfe, property sales of 16.8 Bcfe and negative price related revisions of 156.8 Bcfe. Proved natural gas reserves at year-end 2008 were 1.07 Tcf compared to 1.12 Tcf at year-end 2007. Natural gas comprised 80% and 76% of our total proved reserves at year-end 2008 and 2007, respectively. Our proved oil reserves at year-end 2008 were 45.2 MMBbls compared to 58.3 MMBbls at the end of 2007. Overall, about 46% of our proved reserves are in our Mid-Continent region and 33% are in the Permian Basin. Our onshore Gulf Coast and other onshore operations collectively make another 20% of total proved reserves. Only 1% of our total proved reserves are in the Gulf of Mexico.

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, subjective decisions and available data for our various fields make these estimates generally less precise than other estimates included in financial statement disclosures. For 2008, negative revisions resulting from lower oil and gas prices and higher lease operating expenses decreased proved reserves by 12% on December 31, 2008. See Note 16, Supplemental Oil and Gas Disclosures for more reserve information.

In most years our primary source for reserve replacement and growth is exploration and development (E&D). We invested $1,438.4 million on E&D during 2008 and $982.5 million in 2007. Approximately 45% of 2008 expenditures were in the Mid-Continent area, 38% in the Permian Basin, 15% in the Gulf Coast area, and 2% in Western/other. Cash flow from operating activities for 2008 totaled $1,367.5 million, which largely funded our drilling program.

As a result of expected lower commodity prices and corresponding cash flow we project that 2009 exploration and development expenditures will range from $400 million to $600 million.

Production and other operating expenses

The costs associated with finding and producing oil and gas are substantial. Some of these costs vary with oil and gas prices, some trend with production volume and some are a function of the number of wells we own. At the end of 2008, we owned interests in 12,980 wells.

19

Production expense generally consists of the cost of power and fuel, direct labor, third-party field services, compression, water disposal, and certain maintenance activity necessary to produce oil and gas from existing wells.

Transportation expense is comprised of costs paid to move oil and gas from the wellhead to a specified sales 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.

Depreciation, depletion and amortization (DD&A) 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 expense, while lower prices generally have the effect of decreasing reserves, which increases depletion expense. 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 expense.

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 and not directly associated with exploration, development or production activities. While we expect these costs to increase with our growth, we also expect such increases to be proportionately smaller than our production growth.

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

Significant expenses that generally do not trend with production

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, Share Based Payment. Net stock compensation expense in 2008 was $10.1 million compared to $10.8 million in 2007.

The derivative fair value (gain) loss is the net realized and unrealized gain or loss on derivative financial instruments that do not qualify for hedge accounting treatment and fluctuates based on changes in the fair value of underlying commodities. As of December 31, 2006 all contracts associated with derivative instruments that did not qualify for hedge accounting treatment had settled. The net derivative fair value gain was $23.0 million in 2006.

20

RESULTS OF OPERATIONS

2008 compared to 2007

We recognized a net loss for 2008 of $915.2 million or $11.22 per share. This compares to net income of $345.3 million, or $4.05 per diluted share for the same period in 2007. The decrease in net income is primarily the result of a non-cash full cost ceiling write-down recorded in the third and fourth quarters of 2008. The full cost ceiling impairment is discussed further in the operating costs and expenses section below.

	For the Years Ended December 31,				Percent Change Between		Price/Volume Analysis
Oil and Gas Sales	2008		2007		2008/2007		Price		Volume		Variance
(In thousands or as indicated)
Gas sales	$	1,074,705	$	845,631	27	%	$	175,873	$	53,201	$	229,074
Oil sales	806,186		518,991		55	%	220,956		66,239		287,195
Total oil and gas sales	$	1,880,891	$	1,364,622	38	%	$	396,829	$	119,440	$	516,269
Total gas volume—Mcf	127,444		119,937		6	%
Gas volume—MMcf per day	348.2		328.6
Average gas price—per Mcf	$	8.43	$	7.05	20	%
Effect of hedges—per Mcf	$	0.09	$	0.23
Total oil volume—thousand barrels	8,395		7,445		13	%
Oil volume—barrels per day	22,937		20,399
Average oil price—per barrel	$	96.03	$	69.71	38	%

Oil and gas sales during 2008 totaled $1.9 billion, compared to $1.4 billion in 2007. Of the $516.3 million increase in sales between the two periods, $396.8 million related to higher prices and $119.4 million resulted from higher production volumes.

Compared to 2007, our 2008 oil production increased by 13% to an average of 22,937 barrels per day in 2008. This increase resulted in $66.2 million of incremental revenues. Gas volumes averaged 348.2 MMcf per day in 2008 compared to 328.6 MMcf per day in 2007, resulting in an increase in revenues of $53.2 million. Total 2008 oil and gas production volumes were 485.8 MMcfe per day, up 34.8 MMcfe per day from 2007. Both our gas and oil volumes increased as 2008 unfolded. During the fourth quarter of 2008, our gas production averaged 350.3 MMcf per day up from 341.1 MMcf per day (a three percent increase) in the fourth quarter of 2007. Fourth quarter oil production increased by 10% to 23,907 barrels per day, up from 21,680 barrels per day in 2007.

Average realized gas prices increased by 20% to $8.43 per Mcf in 2008, compared to $7.05 per Mcf for 2007. This price increase boosted gas sales by $175.9 million between the two periods. Included in our 2008 realized gas price is $11.3 million of cash receipts (a positive $0.09 per Mcf effect) from settlement of cash flow hedges on 40,000 MMBtu per day of Mid-Continent gas production.

Realized oil prices averaged $96.03 per barrel during 2008, compared to $69.71 per barrel in 2007. The increase in oil sales resulting from this 38% improvement in oil prices totaled $221.0 million.

Changes in realized gas and oil prices were mostly the result of overall market conditions and our modest gas hedging program.

	For the Years Ended December 31,
	2008			2007
Gas Gathering, Processing and Marketing (in thousands):
Gas gathering, processing and other revenues	$	87,757		$	60,818
Gas gathering and processing costs	(43,838		)	(29,860		)
Gas gathering and processing margin	$	43,919		$	30,958
Gas marketing revenues, net of related costs	$	1,699		$	5,073

21

We sometimes transport, process and market third-party gas that is associated with our gas. In 2008, third-party gas gathering and processing contributed $43.9 million of pre-tax cash operating margin (revenues less direct cash expenses) versus $31 million in 2007. Our gas marketing margin (revenues less purchases) decreased to $1.7 million in 2008 from $5.1 million in 2007. Changes in net margins from gas gathering, processing and marketing activities are the direct result of changes in volumes and overall market conditions.

	For the Years Ended December 31,				Variance Between
	2008		2007		2008/2007
Operating costs and expenses (in thousands):
Impairment of oil and gas properties	$	2,242,921	$	—	$	2,242,921
Depreciation, depletion and amortization	547,404		461,791		85,613
Asset retirement obligation	8,796		8,937		(141		)
Production	218,736		201,512		17,224
Transportation	38,107		26,361		11,746
Taxes other than income	130,490		93,630		36,860
General and administrative	44,500		49,260		(4,760		)
Stock compensation	10,090		10,772		(682		)
Other operating, net	126,433		6,637		119,796
	$	3,367,477	$	858,900	$	2,508,577

Total operating costs and expenses (not including gas gathering, marketing and processing costs, or income tax expense) increased to $3,367.5 million in 2008 compared to $858.9 million in 2007.

The largest component of the increase between periods is the non-cash impairment of oil and gas properties in the amount of $2.2 billion ($1.4 billion, net of tax) that was recorded as a result of declines in natural gas and oil prices during the last half of 2008. At September 30, 2008, our ceiling limitation calculation resulted in excess capitalized costs of $657.1 million ($417.4 million, net of tax), for which we recorded a non-cash impairment of oil and gas properties. As a result of further declines in natural gas and oil prices during the fourth quarter of 2008, we recorded an additional non-cash impairment of oil and gas properties. Electing to use period end prices, at December 31, 2008, our ceiling limitation calculation resulted in excess capitalized costs of $1.6 billion ($1.0 billion after tax). Due to the volatility of oil and gas prices and because the ceiling calculation requires that prices in effect as of the last day of the period be held constant in valuing proved reserves, we may be required to record a ceiling test write-down in future periods. The full cost method of accounting is discussed in detail under “Critical Accounting Policies and Estimates”.

DD&A increased $85.6 million between periods from $461.8 million in 2007 to $547.4 million in 2008. On a unit of production basis, DD&A was $3.08 per Mcfe in 2008 compared to $2.81 per Mcfe for 2007. The increase stems from replacement costs for reserves added being higher than costs of reserves produced. Service costs to drill and complete wells have been increasing and we are drilling deeper and more complex wells. Additionally, the significant decrease in oil and gas prices over the last half of 2008 reduced the amount of our estimated reserve quantities (future production), causing an increase in our depletion rate. Due to the reduction to the carrying value of oil and gas properties recorded at year end we expect the DD&A rate to be lower in the first quarter of 2009 in comparison to the full year 2008.

Production costs rose $17.2 million, or nine percent, from $201.5 million ($1.22 per Mcfe) in 2007 to $218.7 million ($1.23 per Mcfe) in 2008. This increase resulted from an eight percent increase in production volumes and a $7.4 million increase in workover expense between periods.

Transportation costs increased from $26.4 million in 2007 to $38.1 million in 2008. The increase is the result of higher sales volumes, increased market rates and a higher fuel cost component due to higher natural gas prices during the year.

22

Taxes other than income were $36.9 million greater, rising from $93.6 million in 2007 to $130.5 million in 2008. The increase between periods resulted from increases in oil and gas sales stemming from higher production volumes and commodity prices.

General and administrative (G&A) expenses decreased $4.8 million from $49.3 million in 2007 to $44.5 million in 2008. The decrease between periods is due to lower employee-benefit costs due to a decrease in bonus and profit sharing expenses resulting from significant decreases in commodity prices during the last quarter of 2008.

In 2008, the increase in Other operating, net to $126.4 million from $6.6 million was primarily related to the Tulsa County District Court issuing a judgment in the H.B. Krug case. The total accrued litigation expense for the year ended December 31, 2008 for this lawsuit is $119.6 million. We have appealed the District Court’s judgments. For further information on this lawsuit and other litigation please see Contingencies under “Critical Accounting Policies and Estimates”.

Other income and expense

Interest expense decreased by $6.0 million, or 15%, primarily because of a decrease in our average bank debt outstanding during the year. In addition, in comparison to prior year, we experienced a decrease in our average interest rate on both our bank borrowings and convertible notes. Capitalized interest increased by $2.4 million mainly because we had more costs incurred to develop our unproved properties than we had in 2007. We also had a loss on the repurchase of convertible notes of $10.1 million compared to a $5.1 million gain in 2007 on the early extinguishment of debt arising from redemption of our $195 million face value of 9.6% senior unsecured notes.

Other, net decreased from $14.2 million of income in 2007 to $10.3 million of income in 2008. Components consist of miscellaneous income and expense items that will vary from period to period, including income and loss in equity investees, gain or loss on sale of inventory, impairments and interest income. Included in our 2008 Other, net is $16.0 million of impairment expense on our equity investments and $0.8 million of impairment on our short-term investments. These additional expenses were offset by a $17.2 million increase in gain on sale of inventory in comparison to 2007. Another element of the decrease between periods is lower income of $4.2 million from equity investees.

Income tax

During 2008, a net deferred income tax benefit of $536.4 million was recognized (the year end deferred tax benefit included $66.2 million of income tax expense). This compares with 2007 current taxes of $30.6 million and deferred income tax expense of $166.8 million. The combined Federal and state effective income tax rates were 37.0% and 36.4% in the years of 2008 and 2007, respectively. The effective tax rate of 37.0% for 2008 differs from the statutory rate due to effects of the domestic production activities deduction and percentage depletion.

23

RESULTS OF OPERATIONS

2007 compared to 2006

Net income for 2007 was $345.3 million, or $4.05 per diluted share. This compares to net income of $344.5 million, or $4.05 per diluted share in 2006. The small change in year-over-year net income is generally the result of higher oil and gas sales being offset by higher costs and expenses.

	For the Years Ended December 31,				Percent Change Between		Price/Volume Analysis
Oil and Gas Sales	2007		2006		2007/2006		Price		Volume			Variance
(In thousands or as indicated)
Gas sales	$	845,631	$	810,894	4	%	$	65,965	$	(31,228	)	$	34,737
Oil sales	518,991		404,517		28	%	57,699		56,775			114,474
Total oil and gas sales	$	1,364,622	$	1,215,411	12	%	$	123,664	$	25,547		$	149,211
Total gas volume—Mcf	119,937		124,733		(4	)%
Gas volume—MMcf per day	328.6		341.7
Average gas price—per Mcf	$	7.05	$	6.50	8	%
Effect of hedges—per Mcf	$	0.23	$	—
Total oil volume—thousand barrels	7,445		6,529		14	%
Oil volume—barrels per day	20,399		17,887
Average oil price—per barrel	$	69.71	$	61.96	13	%

Oil and gas sales during 2007 totaled $1.4 billion, compared to $1.2 billion in 2006. Of the $149.2 million increase in sales between the two periods, $25.6 million related to higher production volumes and $123.7 million resulted from higher prices.

Compared to 2006, our 2007 oil production increased by 14% to an average of 20,399 barrels per day in 2007. This increase resulted in $56.8 million of incremental revenues. Gas volumes averaged 328.6 MMcf per day in 2007 compared to 341.7 MMcf per day in 2006, resulting in a decrease in revenues of $31.2 million. Total 2007 oil and gas production volumes were 451 MMcfe per day, up 2 MMcfe per day from 2006. Both our gas and oil volumes increased as 2007 unfolded. During the fourth quarter of 2007, our gas production averaged 341.1 MMcf per day up from 329.4 MMcf per day (a 4% increase) in the fourth quarter of 2006. Fourth quarter oil production increased by 17% to 21,680 barrels per day, up from 18,587 barrels per day in 2006.

Average realized gas prices increased by 8% to $7.05 per Mcf in 2007, compared to $6.50 per Mcf for 2006. This price increase boosted gas sales by $65.9 million between the two periods. Included in our 2007 realized gas price is $27.8 million of cash receipts (a positive $0.23 per Mcf effect) from settlement of cash flow hedges on 80,000 MMBtu per day of Mid-Continent gas production. We currently have 40,000 MMBtu per day of our Mid-Continent gas production hedged for 2008 at a floor price of $7.00/MMBtu.

Realized oil prices averaged $69.71 per barrel during 2007, compared to $61.96 per barrel in 2006. The increase in oil sales resulting from this 13% improvement in oil prices totaled $57.7 million.

Changes in realized gas and oil prices were mostly the result of overall market conditions and our modest gas hedging program. We did not have any cash flow effective hedges in place for 2006 volumes.

	For the Years Ended December 31,
	2007			2006
Gas Gathering, Processing and Marketing (in thousands):
Gas gathering and processing revenues	$	60,818		$	46,135
Gas gathering and processing costs	(29,860		)	(25,666		)
Gas gathering and processing margin	$	30,958		$	20,469
Gas marketing revenues, net of related costs	$	5,073		$	3,854

24

We sometimes transport, process and market third-party gas that is associated with our gas. In 2007, third-party gas gathering and processing contributed $31 million of pre-tax cash operating margin (revenues less direct cash expenses) versus $20.5 million in 2006. Our gas marketing margin (revenues less purchases) increased to $5.1 million in 2007 from $3.9 million in 2006. Increases in net margins from gas gathering, processing and marketing activities are the direct result of increased volumes and overall market conditions.

	For the Years Ended December 31,					Variance Between
	2007		2006			2007/2006
Operating costs and expenses (in thousands):
Depreciation, depletion and amortization	$	461,791	$	396,394		$	65,397
Asset retirement obligation	8,937		7,018			1,919
Production	201,512		176,833			24,679
Transportation	26,361		21,157			5,204
Taxes other than income	93,630		91,066			2,564
General and administrative	49,260		42,288			6,972
Stock compensation	10,772		8,243			2,529
Other operating, net	6,637		2,064			4,573
Gain on derivative instruments	—		(22,970		)	22,970
	$	858,900	$	722,093		$	136,807

Total operating costs and expenses (not including gas gathering, marketing and processing costs, or income tax expense) increased to $858.9 million in 2007 compared to $722.1 million in 2006.

DD&A was the largest component of the increase between periods. DD&A totaled $461.8 million in 2007 compared to $396.4 million in 2006. On a unit of production basis, DD&A was $2.81 per Mcfe in 2007 compared to $2.42 per Mcfe for 2006. The increase stems from replacement costs for reserves added being higher than costs of reserves produced. Service costs to drill and complete wells have been increasing and we are drilling deeper and more complex wells.

Production costs rose $24.7 million from $176.8 million ($1.08 per Mcfe) in 2006 to $201.5 million ($1.22 per Mcfe) in 2007. We have experienced higher direct labor cost, higher third-party field service costs, increased electricity rates and greater water disposal costs.

Transportation costs increased from $21.2 million in 2006 to $26.4 million in 2007. The increase is the result of higher sales volumes and that expiring contracts are being renewed with increased current market rates.

General and administrative (G&A) expenses increased $7.0 million from $42.3 million in 2006 to $49.3 million in 2007. The increase between periods is due to an expansion of staff, higher average salaries, higher employee-benefit costs, and increased legal representation costs.

In 2007, the increase in Other operating, net to $6.6 million from $2.1 million was primarily related to resolution of and accruals related to title and royalty issues.

Another component of change in total operating costs and expenses between 2007 and 2006 stems from the $23 million derivative fair value gain we recognized in 2006. This gain was associated with price risk management contracts that were not designated for hedge accounting. These contracts all expired on December 31, 2006.

Other income and expense

Interest expense increased by $8 million, or 26%, primarily because of a 10% increase in our total debt outstanding at an average interest rate of 7.1%. Capitalized interest decreased by $4.6 million mainly because we are carrying less value associated with unproved properties than we were in 2006. We also had a gain in 2007 on the early extinguishment of debt arising from redemption of our $195 million face value of old 9.6% senior unsecured notes. We replaced the old notes with new ten-year, 7.125% senior unsecured notes.

25

Other, net decreased from $28.6 million of income in 2006 to $14.2 million of income in 2007. Components consist of miscellaneous income and expense items that will vary from period to period, including income and loss in equity investees, gain or loss on sale of inventory and interest income. The decrease from 2006 to 2007 is due primarily to the 2006 liquidation of the Company’s investment in the Company’s limited partnership affiliates, Teal Hunter L.P. and Mallard Hunter L.P. Excess distributions of $19.8 million from this liquidation were recorded during 2006. In 2007, we received an additional distribution from this liquidation in the amount of $3.0 million.

Income tax expense

Income tax expense totaled $197.5 million for 2007 versus $197.9 million for 2006. The combined federal and state effective income tax rate was 36.4% and 36.5% in 2007 and 2006, respectively. Included in the 2007 income tax expense of $197.5 million was a current tax expense of $30.6 million.

LIQUIDITY AND CAPITAL RESOURCES

Overview

The world’s economy is being driven by the economic downturn and continuing credit crisis. These constraints, in turn, have pulled down energy prices because of slowing demand. If the capital and credit markets continue to experience volatility or prices continue to decline, and the availability of funds remains limited, we, and third parties with whom we do business, will continue to be negatively impacted. This could lead to losses associated with uncollectible receivables as well as affect our ability to advance our strategic plans as currently anticipated.

To adapt to current conditions and to prepare for an eventual economic upswing, we have focused on maintaining liquidity, promoting operational efficiency, and expanding long-term reserves through focused drilling projects and potential acquisitions. Historically our exploration and development expenditures and dividend payments have generally been funded by cash flow provided by operating activities (“operating cash flow”). With the intent to continue to operate within our operating cash flows, we have significantly scaled back our planned 2009 drilling program, focusing on our highest rate of return projects which are primarily in our Woodford Shale position in the Anadarko Basin of Western Oklahoma and our south Texas Yegua and Cook Mountain play. With this reduced capital program, we believe that our operating cash flow and other capital resources will be adequate to fund our planned 2009 capital expenditures. Because our 2009 exploration program has been reduced, we may not be able to replace the reserves in 2009.

Sources and Uses of Cash

Our primary sources of liquidity and capital resources are cash flow from operating activities, occasional property sales, borrowings under our bank credit facility and public offerings of debt securities. Our primary uses of funds are exploration and development, property acquisitions, common stock dividends and occasional share repurchases.

26

The following table presents the sources and uses of our cash and cash equivalents from 2006 to 2008. The table presents capital expenditures on a cash basis; these amounts differ from the amounts of capital expenditures (including accruals) that are referred to elsewhere in this Report.

	For the Years Ended December 31.
	2008			2007			2006
	(in thousands)
Sources of cash and cash equivalents:
Operating cash flow	$	1,367,488		$	994,680		$	878,419
Proceeds from sale of assets	39,096			177,195			10,705
Net increase in bank debt	220,000			—			95,000
Distributions from equity investees	39			3,015			59,823
Sales of short term investments	10,679			1,424			—
Increase in other long-term debt	—			350,000			—
Proceeds from issuance of common stock and other	13,141			9,886			4,311
Total sources of cash and cash equivalents	1,650,443			1,536,200			1,048,258
Uses of cash and cash equivalents:
Oil and gas expenditures	(1,594,775		)	(1,021,456		)	(1,054,581		)
Merger related costs	—			—			(439		)
Purchase of short-term investments	—			(16,000		)	—
Other expenditures	(51,757		)	(19,574		)	(25,310		)
Net decrease in bank debt	—			(95,000		)	—
Decrease in other long-term debt	(105,550		)	(204,360		)	—
Financing costs incurred	(158		)	(6,113		)	(153		)
Treasury stock acquired and retired	—			(42,266		)	(11,016		)
Dividends paid	(20,040		)	(13,429		)	(13,358		)
Total uses of cash and cash equivalents	(1,772,280		)	(1,418,198		)	(1,104,857		)
Net increase (decrease) in cash and cash equivalents	$	(121,837	)	$	118,002		$	(56,599	)
Cash and cash equivalents at end of year	$	1,213		$	123,050		$	5,048

Analysis of Cash Flow Changes (See the Consolidated Statements of Cash Flows)

Cash flow provided by operating activities for 2008 was $1,367.5 million, compared to $994.7 million for 2007 and $878.4 million for 2006. The increase from 2007 to 2008 resulted primarily from higher gas prices, higher oil prices and increased production. The increase from 2006 to 2007 resulted primarily from higher gas prices, high oil prices and increased oil production.

Cash flow used in investing activities for 2008 was $1.6 billion, compared to $875.4 million for 2007 and $1.0 billion for 2006. Changes in the cash flow used in investing activities are generally the result of changes in our exploration and development programs, acquisitions and property sales. The increase from 2007 to 2008 was mostly caused by increased oil and gas expenditures resulting from a more active drilling program. In addition, we had $138.1 million less proceeds from sales of assets in 2008 when compared to 2007. The decrease from 2006 to 2007 was mostly caused by increased proceeds from property sales. We sold $177 million of oil and gas properties in 2007 versus $4.5 million in 2006.

Net cash flow provided from financing activities in 2008 was $107.4 million versus $1.3 million used in 2007. In 2008 we had borrowings under our credit facility of $220.0 million and $13.1 million in proceeds from issuance of common stock and other. We used $105.6 million of the borrowings under our credit facility to repurchase a portion of our convertible notes in December and we made $20.0 million in dividend payments during the year.

Net cash flow used in financing activities in 2007 was $1.3 million versus $74.8 million provided in 2006. Two significant uses were for share repurchases of $42.3 million and $13.4 million for dividends. Proceeds from our May 2007 issuance of $350 million of ten-year, 7.125% senior unsecured notes were used to redeem our old 9.6% notes and reduce outstanding borrowings under our credit facility.

27

Capital Expenditures

The following table sets forth certain historical information regarding capitalized expenditures by us in our oil and gas acquisition, exploration, and development activities (in thousands):

	For Years Ended December 31,
	2008			2007			2006
Acquisitions:
Proved	$	6,618		$	17,334		$	25,970
Unproved	175,777			23,580			513
	182,395			40,914			26,483
Exploration and development:
Land & Seismic	157,403			98,162			104,527
Exploration	245,538			217,696			251,717
Development	1,035,442			666,662			691,946
	1,438,383			982,520			1,048,190
Property sales	(38,093		)	(176,659		)	(4,459		)
	$	1,582,685		$	846,775		$	1,070,214

2008 property acquisitions primarily relate to various producing properties and exploratory nonproducing leases that we purchased in October. This $180.9 million acquisition expanded our Woodford Shale position in the Anadarko Basin of western Oklahoma by 38,000 net acres.

We make significant expenditures to find, acquire, and develop oil and natural gas reserves. Our exploration and development expenditures increased 46% in 2008 compared to 2007. The increase in 2008 resulted primarily from increases in exploration activity in our Mid-continent and Permian regions.

We have reduced our planned capital program for 2009 to approximately $500 million due to the expectation of continued low oil and gas prices. If these prices drop even further, or if operating difficulties are encountered that result in cash flow from operations being less than expected, we may have to reduce our capital expenditures even more.

We have made, and will continue to make, expenditures to comply with environmental and safety regulations and requirements. These costs are considered a normal recurring cost of our ongoing operations and not an extraordinary cost of compliance. We do not anticipate that we will be required to expend amounts that will have a material adverse effect on our financial position or operations, nor are we aware of any pending regulatory changes that would have a material impact.

Our 2008 exploration and development drilling program is discussed in Exploration and Development Activity Overview under Item 1 of this Report.

Financial Condition

Future cash flows and the availability of financing will be subject to a number of variables, such as our success in locating and producing new reserves, the level of production from existing wells and prices of oil and natural gas. To meet our capital and liquidity requirements, we rely on certain resources, including cash flows from operating activities, access to capital markets, and bank borrowings. While we attempt to operate within forecasted cash flows from operations, we do periodically access our credit facility to finance our working capital needs and growth. Recent adverse developments in financial and credit markets have made it more difficult and more expensive to access the short-term capital market to meet our liquidity needs. Due to the tightened credit markets and significantly lower commodity prices we have planned to scale back our 2009 capital program by approximately 60% in comparison to 2008. With these planned reductions and amounts available to us under our existing credit facility we believe we will be able to continue to meet our needs for working capital, construction expenditures, debt servicing and dividend payments.

28

During the year our total assets, net oil and gas assets, net income and stockholders’ equity were reduced by a non-cash impairment of oil and gas properties in the amount of $2.2 billion ($1.4 billion after tax). Total assets decreased by $1.2 billion in 2008 from $5.4 billion at the beginning of the year to $4.2 billion by year end. Our net oil and gas assets decreased by $1.2 billion. Our cash position decreased by $121.8 million primarily as a result of our Woodford Shale acquisition in October and a decrease in commodity prices during the fourth quarter. As of December 31, 2008, stockholders’ equity totaled $2.4 billion, down from $3.3 billion at December 31, 2007. The decrease resulted primarily from a 2008 net loss of $915.3 million.

Dividends

In December 2005, the Board of Directors declared the Company’s first quarterly cash dividend of $.04 per share payable to shareholders. A dividend has been authorized in every quarter since then. On December 12, 2007 the Board of Directors increased the regular cash dividend on our common stock from $0.04 to $0.06 per common share.

Common Stock Repurchase Program

In December 2005, the Board of Directors authorized the repurchase of up to four million shares of common stock. During 2007 we repurchased a total of 1,114,200 shares at an average purchase price of $37.93. Cumulative purchases through December 31, 2007 total 1,364,300 shares at an average price of $39.05. No purchases were made in 2008.

Working Capital

Working capital decreased $94.7 million from year-end 2007 to $45.4 million at year-end 2008. Working capital decreased primarily because of the following:

·Our cash position decreased by $121.8 million compared to year end 2007 primarily as a result of our Woodford Shale acquisition in October and a decrease in commodity prices during the fourth quarter.

·Oil and gas receivables decreased by $107.7 million due to a significant decrease in commodity prices from the prior year.

·Trade payables increased by $48.0 million due to timing of payments.

These working capital decreases were mostly offset by:

·Revenue payable decreased by $27.1 million due to a significant decrease in commodity prices from the prior year.

·Inventories increased by $156.4 million due to increased steel prices and a planned increase in the amount of pipe inventory in our yards.

Our receivables are a major component of our working capital and are made up of 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.

29

Financing

Debt at December 31, 2008 and 2007 consisted of the following (in thousands):

	2008		2007
Bank debt	$	220,000	$	—
7.125% Notes due 2017	350,000		350,000
Floating rate convertible notes due 2023 (face value $19,450 and $125,000, respectively)	17,630		112,216		(1)
Total long-term debt	$	587,630	$	462,216

(1)  Fair market value at June 7, 2005 was $109.2 million. The subsequent noted balances represent the fair market value at date of acquisition plus amortization of the discount of the difference between the fair market value and the face value of the notes. The 2008 balance also reflects our repurchase of $105.6 million of face value of the notes in December, 2008.

Bank Debt

We have a $1.0 billion senior secured revolving credit facility (“credit facility”) with a syndicate of banks that had a borrowing base of $1.0 billion as of December 31, 2008. At our option we set the banks’ lending commitment under the credit facility at $500 million. The borrowing base is determined at the discretion of the lenders, based on the collateral value of our proved reserves and is subject to potential special and regular semi-annual redeterminations.

The credit facility matures on July 1, 2010 and is secured by mortgages on certain oil and gas properties and the stock of certain wholly-owned operating subsidiaries. Amounts outstanding bear interest at our election at either a floating London Interbank Offered Rate (LIBOR) plus 1%-1.75% or at the JP Morgan Chase Bank prime rate plus 0%-0.5%. At December 31, 2008, there was $220 million of borrowings outstanding under the credit facility at a weighted average interest rate of approximately 1.66%. We also had letters of credit outstanding of $2.8 million leaving an unused borrowing availability of $277.2 million at December 31, 2008.

The credit facility contains various covenants and restrictive provisions which may limit our ability to incur additional indebtedness, make investments or loans and create liens. The credit agreement requires us to maintain a current ratio (current assets to current liabilities, as defined) greater than 1 to 1 and a leverage ratio (indebtedness to EBITDA, as defined) not to exceed 3.0 to 1. The current ratio, as defined by the credit agreement, at December 31, 2008, was 1.69 to 1 and our leverage ratio was 0.42 to 1. As of December 31, 2008, we were in compliance with all of the financial and non-financial covenants.

We have initiated discussions with our syndicate of banks regarding a new three-year senior secured revolving credit facility with the intent to increase the banks’ lending commitment from $500 million to $800 million. In addition, we may consider a high-yield bond offering in the future, if appropriate.

7.125% Notes due 2017

In May, 2007, we issued $350 million of 7.125% senior unsecured notes that mature May 1, 2017 at par. Interest on the notes is payable May 1 and November 1 of each year. The notes are governed by an indenture containing covenants that could limit our ability to incur additional indebtedness; pay dividends or repurchase our common stock; make investments and other restricted payments; incur liens; enter into sale/leaseback transactions; engage in transactions with affiliates; sell assets; and consolidate, merge or transfer assets.

30

The notes are redeemable at our option, in whole or in part, at any time on and after May 1, 2012 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
2012	103.6	%
2013	102.4	%
2014	101.2	%
2015 and thereafter	100.0	%

At any time prior to May 1, 2010, we may redeem up to 35% of the original principal amount of the notes with the proceeds of certain equity offerings of our shares of common stock at a redemption price of 107.125% of the principal amount of the notes, together with accrued and unpaid interest, if any, to the date of redemption.

At any time prior to May 1, 2012, we may also redeem all, but not part, of the notes at a price of 100% of the principal amount of the notes plus accrued and unpaid interest plus a “make-whole” premium.

If a specified change of control occurs, subject to certain conditions, we must make an offer to purchase the notes at a purchase price of 101% of the principal amount of the notes, plus accrued and unpaid interest to the date of the purchase.

Floating rate convertible notes due 2023

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 of three month LIBOR, reset quarterly. On December 31, 2008, the interest rate was 2.0%.

The holders as of December 15, 2008, had the right to require us to repurchase all or a portion of the notes at a price of 100% of the principal amount (plus accrued interest). As of December 15, 2008, holders with principal of $105.550 million submitted their notes for repurchase leaving $19.450 million still outstanding. We repurchased the $105.550 million in notes with borrowings under our credit facility. The remaining notes have future repurchase dates as of December 15, 2013, and 2018. We have the right at any time to redeem some or all of the notes still outstanding at a redemption price of 100% of the principal amount (plus accrued interest).

In addition to the repurchase rights, 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 conversion price of $28.59 per share. On December 31, 2008, the closing price of our common stock traded on the New York Stock Exchange was $26.78.

If a specified change of control occurs, subject to certain conditions, we must make an offer to purchase the notes at a purchase price of 101% of the principal amount of the notes, plus accrued and unpaid interest to the date of the purchase.

31

Contractual Obligations and Material Commitments

At December 31, 2008, we had contractual obligations and material commitments as follows:

	Payments Due by Period
Contractual obligations	Total		Less than 1 Year		1-3 Years			4-5 Years			More than 5 Years
	(In thousands)
Long-term debt(1)	$	589,450	$	220,000	$	—		$	—		$	369,450
Fixed-Rate interest payments(1)	211,969		24,938		49,875			49,875			87,281
Operating leases	28,233		5,681		10,814			9,632			2,106
Drilling commitments(2)	187,412		187,412		—			—			—
Inventory commitments(3)	81,929		81,929		—			—			—
Gas processing facility(4)	108,611		38,887		42,348			27,376			—
Asset retirement obligation	139,948		14,610		—		(5)	—		(5)	—		(5)
Other liabilities(6)	51,216		8,823		17,636			17,636			7,121

(1)	These amounts do not include interest on the $220 million of bank debt outstanding at December 31, 2008. The weighted average interest rate at December 31, 2008 was approximately 1.66%. See item 7A: Interest Rate Risk for more information regarding fixed and variable rate debt.
(2)	We have drilling commitments of approximately $101.7 million consisting of obligations to complete drilling wells in progress at December 31, 2008. We also have minimum expenditure commitments of $85.7 million to secure the use of drilling rigs. Hurricanes Gustav and Ike occurred during the third quarter of 2008. We are continuing to evaluate damages to our wells and platforms. It is not presently determinable what our share of the total damages will be after insurance proceeds.
(3)	At December 31, 2008, we had outstanding purchase order commitments of $81.9 million for tubular inventory. Subsequent to year-end we have been able to cancel approximately $17.1 million of those commitments, and efforts continue to further reduce our inventory commitments.
(4)	We have a large development project in Sublette County, Wyoming where we are developing the deep Madison gas formation and constructing a gas processing plant. At December 31, 2008, we had commitments of $176.8 million relating to construction of the gas processing plant of which $108.6 million is subject to a construction contract. The total cost of the project will approximate $362 million. Pursuant to the terms of our operating agreement with our partners in this project, we will be reimbursed by them for 421/2% of the costs.
(5)	We have excluded the long term asset retirement obligations because we are not able to precisely predict the timing of these amounts.
(6)	Other liabilities include the fair value of our liabilities associated with our benefit obligations and other miscellaneous commitments.

At December 31, 2008, we had firm sales contracts to deliver approximately 8.5 Bcf of natural gas over the next twelve months. If this gas is not delivered, our financial commitment would be approximately $40 million. This commitment may fluctuate due to either price volatility or volumes delivered. However, we do not anticipate that a financial commitment will be due.

In connection with a gas gathering and processing agreement, we have commitments to deliver 59.4 Bcf of gas over the next five years. If no gas was delivered, the maximum amount that would be payable under these commitments would be approximately $45.1 million.

32

We have 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 $5.9 million.

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 bank credit facility will be adequate to meet future liquidity needs, including satisfying our financial obligations and funding our operations and planned exploration and development activities.

2009 Outlook

Our exploration and development expenditures program for 2009 are projected to range from $400 million to $600 million. Though there are a variety of factors that could curtail, delay or even cancel some of our planned operations, we believe our projected program is likely to occur. The majority of projects are in hand, drilling rigs are being scheduled, and the historical results of our drilling efforts warrant pursuit of the projects.

Production estimates for 2009 range from 440 to 460 MMcfe per day. Revenues from production will be dependent not only on the level of oil and gas actually produced, but also the prices that will be realized. During 2008, our realized prices averaged $8.43 per Mcf of gas and $96.03 per barrel of oil. Prices can be very volatile and the possibility of 2009 realized prices being different than they were in 2008 is high.

Certain expenses for 2009 on a per Mcfe basis are currently estimated as follows:

	2009
Production expense	$1.20 - $1.30
Transportation expense	0.17 - 0.22
DD&A and Asset retirement obligation	1.85 - 2.10
General and Administrative	0.27 - 0.30
Production taxes (% of oil and gas revenue)	7.0% - 8.0%

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. A complete list of our significant accounting policies are described in Note 3 to our Consolidated Financial Statements included in this Report. 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 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 to be our most critical accounting policies and estimates that involve significant judgments and discuss the selection and development of these policies and estimates with our Audit Committee.

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

33

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. Estimations of proved undeveloped reserves can be subject to an even greater possibility of revision. At year-end, 18 percent of our total proved reserves are categorized as proved undeveloped. Of these proved undeveloped reserves, 89 percent are related to a project in Wyoming. Our reserve engineers review and revise our reserve estimates annually. Additionally, we annually engage an independent petroleum engineering firm to review our proved reserve estimates associated with at least 80% of the discounted future net cash flows before income taxes.

We use the units-of-production method to amortize our oil and gas properties. For depletion purposes, reserve quantities are adjusted at interim quarterly periods for the estimated impact of additions, dispositions and price changes. Changes in reserve quantities cause corresponding changes in depletion expense in periods subsequent to the quantity revision. It is also possible that a full cost ceiling limitation charge could occur in the period of the revision.

The following table presents information regarding reserve revisions largely resulting from items we do not control, such as revisions due to price, and other revisions resulting from better information due to production history, well performance and changes in production costs.

	Years Ended December 31,
	2008				2007			2006
			Percent			Percent				Percent
	Bcfe		of total		Bcfe	of total		Bcfe		of total
	Change		Reserves		Change	Reserves		Change		Reserves
Revisions resulting from price changes	(145.2	)	(9.86	)%	35.5	2.45	%	(40.1	)	(2.88	)%
Other changes in estimates	(11.6	)	(0.79	)%	22.0	1.52	%	3.5		0.25	%
Total	(156.8	)	(10.65	)%	57.5	3.97	%	(36.6	)	(2.63	)%

Non-price related revisions added 13.9 Bcfe over the three-year period 2006-2008. Over the same period we have seen a 149.8 Bcfe decrease resulting from lower prices. See Note 16, Supplemental Oil and Gas Disclosures for additional reserve data.

Full Cost Accounting

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. In addition, gains or losses on the sale or other disposition of oil and gas properties are not recognized in earnings unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas attributable to our full cost pool.

At the end of each quarter, we make a full cost ceiling limitation calculation, whereby net capitalized costs related to proved properties less associated deferred income taxes may not exceed the amount of 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. Changes in proved reserve estimates (whether based upon quantity revisions or oil and gas prices) will cause corresponding changes to the full cost ceiling limitation. If net capitalized costs subject to amortization exceed this limit, the excess would be charged to expense. However, if commodity prices increase after period end and before issuance of the financial statements, these higher commodity prices may be used to determine if the capital costs are in fact impaired as of the end of the period. Any recorded impairment of oil and gas properties is not reversible at a later date.

34

Due to a significant decrease in period end commodity prices, at September 30, 2008, our ceiling limitation calculation resulted in excess capitalized costs of $657.1 million ($417.4 million, net of tax), for which we recorded a non-cash impairment of oil and gas properties. As a result of further declines in natural gas and oil prices during the fourth quarter of 2008, we recorded an additional non-cash impairment of oil and gas properties. Based on prices at December 31, 2008, our ceiling limitation calculation resulted in excess capitalized costs of $1.6 billion ($1.0 billion after tax). The Company’s quarterly and annual ceiling test is primarily impacted by period end commodity prices, reserve quantities added and produced, overall exploration and development costs and depletion expense. Holding all factors constant other than commodity prices, a 10% decline in prices as of December 31, 2008 would have resulted in an additional ceiling test impairment of approximately 12% of our full cost pool. Also, goodwill could be potentially impaired. Changes in actual reserve quantities added and produced along with our actual overall exploration and development costs will impact the Company’s actual ceiling test calculation and impairment analyses.

Goodwill

At December 31, 2008, we had $691.4 million of goodwill recorded in conjunction with past business combinations. Goodwill is subject to annual reviews for impairment based on a two step accounting test. The first step is to compare the estimated fair value of the Company with the recorded net book value (including the goodwill), after giving effect to all other period impairments, including the impairment of oil and gas properties from the full cost pool ceiling limitation calculation. If the estimated fair value is higher than the recorded net book value, no impairment is deemed to exist and no further testing is required. If, however, the estimated fair value is below the recorded net book value, then a second step must be performed to determine the goodwill impairment required, if any. In this second step, a hypothetical acquisition value of the Company is computed utilizing purchase business combination accounting rules.

We perform our annual goodwill impairment review in the fourth quarter of each year. During the fourth quarter of 2008, there were severe disruptions in the credit markets and reductions in global economic activity which had significant adverse impacts on stock markets and oil-and-gas-related commodity prices. Management must apply judgment in determining the estimated fair value of the Company for purposes of performing the annual goodwill impairment test. As of December 31, 2008, the book value per share of our common stock exceeded the market price by less than $2 per share. Management does not consider the market value of our shares to be an accurate reflection of our net assets, for impairment purposes. To estimate the fair value of the Company, we used all available information, including the present values of expected future cash flows using discount rates commensurate with the risks involved in the assets. This estimated fair value differs significantly from the valuation used in the ceiling limitation calculation, which requires the use of prices and costs in effect at year end, discounted at 10 percent. The ceiling calculation is not intended to be indicative of fair value.

In estimating the fair value of our oil and gas properties, we used projected future prices based on the NYMEX strip index at December 31, 2008 (adjusted for estimated delivery point price differentials). Based on our current exploration plans, we included estimated future cash flows from development of our unproved properties and applied a discount rate of 15% to 20%, depending on the reserve category. This resulted in a slight excess of fair value over the carrying value of our net assets at year end. Should lower prices or quantities result in the future, or higher discount rates be necessary, the carrying value of our net assets may exceed the estimated fair value, resulting in an impairment of goodwill.

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.

In January 2009, the Tulsa County District Court issued a judgment in the H.B. Krug, et al versus Helmerich & Payne, Inc. (“H&P”) case. This lawsuit was originally filed in 1998 and addressed H&P’s conduct

35

pertaining to a 1989 take-or-pay settlement, along with potential drainage issues and other related matters. Damages of $6.9 million plus $119.5 million for disgorgement of H&P’s estimated potential compounded profit since 1989, resulting from the noted damages, were awarded to plaintiff royalty owners, for a total of $126.4 million. This amount was subsequently adjusted by the court to a total of $119.6 million. Pursuant to the 2002 spin-off transaction to shareholders of H&P by which Cimarex became a publicly-traded entity, Cimarex assumed the assets and liabilities of H&P’s exploration and production business. We periodically assess the probability of estimable amounts related to litigation matters, as required by Financial Accounting Standard No. 5 (Accounting for Contingencies) and adjust our accruals accordingly. In September 2008, based on the available information at the time, we accrued an estimated litigation expense of $12 million for both damages and probable disgorgement. The higher disgorgement award could not be reasonably estimated until the final judgment in January 2009. We therefore accrued an additional $107.6 million, bringing the total accrued litigation expense for the year ended December 31, 2008 to $119.6 million for this lawsuit. We have appealed the District Court’s judgments.

In the normal course of business, we have other various litigation related matters and associated accruals. Though some of the related claims may be significant, the resolution of them we believe, individually or in the aggregate, would not have a material adverse effect on our financial condition or results of operations.

Asset Retirement Obligation

Our asset retirement obligation primarily represents the estimated present value of the amount we will incur to plug, abandon and remediate our producing properties at the end of their productive lives, in accordance with applicable state laws. We determine our asset retirement obligation by calculating the present value of estimated cash flows related to the liability. The retirement obligation is recorded as a liability at its estimated present value as of the asset’s inception, with an offsetting increase to producing properties. Periodic accretion of discount of the estimated liability is recorded as an expense in the income statement.

Our liability is determined using significant assumptions, including current estimates of plugging and abandonment costs, annual inflation of these costs, the productive lives of wells and our risk-adjusted interest rate. Changes in any of these assumptions can result in significant revisions to the estimated asset retirement obligation. For example, as we analyze actual plugging and abandonment information, we may revise our estimates of current costs, the assumed annual inflation of these costs and/or the assumed productive lives of our wells. During 2008, we revised our existing estimated asset retirement obligation by $23.0 million, or approximately 16.4 percent of the asset retirement obligation at December 31, 2008, due to changes in the various related attributes. Over the past three years, revisions to the estimated asset retirement obligation averaged approximately 9.3 percent. Revisions to the asset retirement obligation are recorded with an offsetting change to producing properties, resulting in prospective changes to depreciation, depletion and amortization expense and accretion of discount. Because of the subjectivity of assumptions and the relatively long lives of most of our wells, the costs to ultimately retire our wells may vary significantly from prior estimates.

Recently Issued Accounting Standards

In May, 2008, the Financial Accounting Standards Board (“FASB”) issued a new Staff Position No. APB 14-1, Accounting for Convertible Debt Instruments That May Be Settled in Cash upon Conversion (Including Partial Cash Settlement), that will impact the accounting for the components of convertible debt that can be settled wholly or partly in cash upon conversion. The new requirements apply not only to new instruments, but also would be applied retrospectively to previously issued convertible instruments. The debt and equity components of the instruments are to be accounted for separately. The value assigned to the debt component is the estimated value of similar debt without a conversion feature as of the issuance date, with the remaining proceeds allocated to the equity component and recorded as additional paid-in capital. The debt component is recorded at a discount and is subsequently accreted to its par value, thereby reflecting an overall market rate of interest in the income statement. This Staff Position is effective for both new and previously issued instruments for current and comparative periods in fiscal years beginning after December 15, 2008, and interim periods within those years. We adopted this in the first quarter of 2009 and accordingly, data herein has been recast to reflect such adoption.

In June, 2008, the FASB issued a new Staff Position EITF 03-6-1, Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities, which holds that unvested share-based

36

payment awards that contain non forfeitable rights to dividends or dividend equivalents are “participating securities” (as defined by EITF 03-6 as securities that may participate in undistributed earnings with common stock, whether that participation is conditioned upon the occurrence of a specified event or not, regardless of the form of participation),and therefore should be included in computing earnings per share using the two-class earnings allocation method. The two-class method is an earnings allocation formula that determines earnings per share for each class of common stock and participating security according to dividends declared (or accumulated) and participation rights in undistributed earnings. The requirements of this Staff Position are to be applied by restating previously reported earnings per share data. Under this staff position, our unvested share based payment awards, consisting of restricted stock and restricted stock units, qualify as participating securities. We adopted this in the first quarter of 2009 and earnings per share data herein have been recast to present such data using the two-class method.

ITEM 7A.  QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT MARKET RISK

The term “market risk” refers to the risk of loss arising from adverse changes in oil and gas prices, interest rates and value of our short-term investments. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses.

Price Fluctuations

Our major market risk is pricing applicable to our oil and gas production. The prices we receive for our production are based on prevailing market conditions and are influenced by many factors that are beyond our control. Pricing for oil and gas production has been volatile and unpredictable (See risk factors in Item 1).

Currently, we are largely accepting the volatility risk that the change in prices presents. None of our future oil and gas production is subject to hedging. At December 31, 2008, our derivative contracts were completed. See Note 3 to the Consolidated Financial Statements in Item 8 of this Report for additional information regarding our derivative instruments.

Interest Rate Risk

At December 31, 2008, we had total debt outstanding of $587.6 million. Of this amount, $220 million is outstanding under our senior secured revolving credit facility and $350 million is senior unsecured notes that bear interest at a fixed rate of 7.125% and will mature on May 1, 2017. The credit facility matures on July 1, 2010 and amounts outstanding bear interest at our election at either a floating LIBOR rate plus 1%-1.75% or the prime rate plus 0%-0.5%. The remaining debt of our unsecured convertible senior notes is $19.45 million (face value) which matures on December 15, 2023. These convertible notes bear interest at an annual rate of three-month LIBOR, reset quarterly. The book value of our revolving credit facility and the convertible notes approximates the current fair value. The fair value of our 7.125% notes was approximately $267.8 million at December 31, 2008.

We consider our interest rate exposure to be minimal because as of December 31, 2008 about 59% of our long-term debt obligations were at fixed rates. A 1% increase in the three-month LIBOR rate would increase annual interest expense by $2.4 million. This sensitivity analysis for interest rate risk excludes accounts receivable, accounts payable and accrued liabilities because of the short-term maturity of such instruments. See Note 4 and Note 6 to the Consolidated Financial Statements in Item 8 of this Report for additional information regarding debt.

Market Value of Investments

We currently have $2.5 million invested in an asset-backed securities fund. We expect to liquidate our investment in this fund within the next 12 months. A five percent change in these investments’ market value would have a $125 thousand impact on our investments.

37

ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

CIMAREX ENERGY CO.

INDEX TO FINANCIAL STATEMENTS AND SUPPLEMENTAL SCHEDULES

	Page
Report of Independent Registered Public Accounting Firm for the years ended December 31, 2008, 2007 and 2006	39
Consolidated balance sheets as of December 31, 2008 and 2007	40
Consolidated statements of operations for the years ended December 31, 2008, 2007 and 2006	41
Consolidated statements of cash flows for the years ended December 31, 2008, 2007 and 2006	42
Consolidated statements of stockholders’ equity and comprehensive income (loss) for the years ended December 31, 2008, 2007 and 2006	43
Notes to consolidated financial statements	45

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

38

Report of Independent Registered Public Accounting Firm

The Board of Directors

Cimarex Energy Co.:

We have audited the accompanying consolidated balance sheets of Cimarex Energy Co. and subsidiaries (the Company) as of December 31, 2008 and 2007, and the related consolidated statements of operations, stockholders’ equity and comprehensive income, and cash flows for each of the years in the three-year period ended December 31, 2008. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

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

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Cimarex Energy Co. and subsidiaries as of December 31, 2008 and 2007, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2008, in conformity with U.S. generally accepted accounting principles.

As discussed in note 3 to the consolidated financial statements, Cimarex Energy Co. adopted Financial Accounting Standards Board (FASB) Staff Position APB 14-1, Accounting for Convertible Debt Instruments That May Be Settled in Cash Upon Conversion (Including Partial Cash Settlement) and FASB Staff Position EITF 03-6-1, Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities, effective January 1, 2009, which have been applied retrospectively in the consolidated financial statements referred to above.

KPMG LLP

Denver

February 27, 2009, except for the last two paragraphs of note 3 and notes 4, 6, 7, 9, and 17, which are as of July 17, 2009

39

CIMAREX ENERGY CO.

CONSOLIDATED BALANCE SHEETS

(In thousands, except share and per share information)

	December 31,
	2008			2007
Assets
Current assets:
Cash and cash equivalents	$	1,213		$	123,050
Restricted cash	502			—
Short-term investments	2,502			14,391
Accounts receivable:
Trade, net of allowance	73,676			64,600
Oil and gas sales, net of allowance	136,606			244,299
Gas gathering, processing, and marketing, net of allowance	6,974			6,428
Other	41,826			—
Inventories	186,062			29,642
Deferred income taxes	2,435			5,697
Derivative instruments	—			12,124
Other current assets	63,148			64,346
Total current assets	514,944			564,577
Oil and gas properties at cost, using the full cost method of accounting:
Proved properties	7,052,464			5,545,977
Unproved properties and properties under development, not being amortized	465,638			364,618
	7,518,102			5,910,595
Less – accumulated depreciation, depletion and amortization	(4,709,597		)	(1,938,863		)
Net oil and gas properties	2,808,505			3,971,732
Fixed assets, less accumulated depreciation of $67,020 and $49,629	119,616			90,584
Goodwill	691,432			691,432
Other assets, net	30,436			44,469
	$	4,164,933		$	5,362,794
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable:
Trade	$	89,221		$	41,213
Gas gathering, processing, and marketing	11,936			11,458
Accrued liabilities:
Exploration and development	111,511			92,640
Taxes other than income	26,473			26,109
Other	126,010			121,638
Revenue payable	104,438			131,513
Total current liabilities	469,589			424,571
Long-term debt	587,630			462,216
Deferred income taxes	500,945			1,085,325
Asset retirement obligation	125,338			105,784
Other liabilities	129,784			9,770
Total liabilities	1,813,286			2,087,666
Commitments and contingencies
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, 84,144,024 and 83,620,480 shares issued, respectively	841			836
Treasury stock, at cost, 885,392 and 1,078,822 shares held, respectively	(33,344		)	(40,628		)
Paid-in capital	1,874,834			1,861,699
Retained earnings	510,271			1,445,595
Accumulated other comprehensive (loss) income	(955		)	7,626
	2,351,647			3,275,128
	$	4,164,933		$	5,362,794

The accompanying notes are an integral part of these consolidated financial statements.

40

CIMAREX ENERGY CO.

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per share data)

	For the Years Ended
	December 31,
	2008			2007			2006
Revenues:
Gas sales	$	1,074,705		$	845,631		$	810,894
Oil sales	806,186			518,991			404,517
Gas gathering, processing and other	87,757			60,818			46,135
Gas marketing, net of related costs of $141,668, $107,678 and $144,702, respectively	1,699			5,073			3,854
	1,970,347			1,430,513			1,265,400
Costs and expenses:
Impairment of oil and gas properties	2,242,921			—			—
Depreciation, depletion and amortization	547,404			461,791			396,394
Asset retirement obligation	8,796			8,937			7,018
Production	218,736			201,512			176,833
Transportation	38,107			26,361			21,157
Gas gathering and processing	43,838			29,860			25,666
Taxes other than income	130,490			93,630			91,066
General and administrative	44,500			49,260			42,288
Stock compensation, net	10,090			10,772			8,243
(Gain) loss on derivative instruments	—			—			(22,970		)
Other operating, net	126,433			6,637			2,064
	3,411,315			888,760			747,759
Operating income (loss)	(1,440,968		)	541,753			517,641
Other (income) and expense:
Interest expense	33,079			39,105			31,130
Capitalized interest	(22,108		)	(19,680		)	(24,248		)
Amortization of fair value of debt	—			(1,146		)	(3,024		)
(Gain) loss on early extinguishment of debt	10,058			(5,099		)	—
Other, net	(10,348		)	(14,151		)	(28,591		)
Income (loss) before income tax expense	(1,451,649		)	542,724			542,374
Income tax expense (benefit)	(536,404		)	197,462			197,893
Net income (loss)	$	(915,245	)	$	345,262		$	344,481
Earnings (loss) per share to common shareholders:
Basic
Distributed	$	0.24		$	0.18		$	0.16
Undistributed	(11.46		)	3.97			3.96
	$	(11.22	)	$	4.15		$	4.12
Diluted
Distributed	$	0.24		$	0.18		$	0.16
Undistributed	(11.46		)	3.87			3.89
	$	(11.22	)	$	4.05		$	4.05

The accompanying notes are an integral part of these consolidated financial statements.

41

CIMAREX ENERGY CO.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

	Years Ended
	December 31,
	2008			2007			2006
Cash flows from operating activities:
Net income (loss)	$	(915,245	)	$	345,262		$	344,481
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Impairment of oil and gas properties	2,242,921			—			—
Depreciation, depletion and amortization	547,404			461,791			396,394
Asset retirement obligation	8,796			8,937			7,018
Deferred income taxes	(602,593		)	166,813			219,827
Stock compensation, net	10,090			10,772			8,243
Derivative instruments	—			—			(41,926		)
Gain on liquidation of equity investees	(39		)	(3,015		)	(19,785		)
Changes in non-current assets and liabilities	136,328			354			593
Other	15,557			509			3,490
Changes in operating assets and liabilities
(Increase) decrease in receivables, net	56,245			(7,777		)	(9,811		)
(Increase) in inventory and other current assets	(155,222		)	(32,180		)	(11,812		)
Increase (decrease) in accounts payable and accrued liabilities	23,246			43,214			(18,293		)
Net cash provided by operating activities	1,367,488			994,680			878,419
Cash flows from investing activities:
Oil and gas expenditures	(1,594,775		)	(1,021,456		)	(1,054,581		)
Merger related costs	—			—			(439		)
Proceeds from sale of assets	39,096			177,195			10,705
Distributions received from equity investees	39			3,015			59,823
Purchases of short-term investments	—			(16,000		)	—
Sales of short-term investments	10,679			1,424			—
Other expenditures	(51,757		)	(19,574		)	(25,310		)
Net cash used by investing activities	(1,596,718		)	(875,396		)	(1,009,802		)
Cash flows from financing activities:
Net Increase (decrease) in bank debt	220,000			(95,000		)	95,000
Increase in other long-term debt	—			350,000			—
Decrease in other long-term debt	(105,550		)	(204,360		)	—
Financing costs incurred	(158		)	(6,113		)	(153		)
Treasury stock acquired and retired	—			(42,266		)	(11,016		)
Dividends paid	(20,040		)	(13,429		)	(13,358		)
Proceeds from issuance of common stock and other	13,141			9,886			4,311
Net cash provided by (used in) financing activities	107,393			(1,282		)	74,784
Net change in cash and cash equivalents	(121,837		)	118,002			(56,599		)
Cash and cash equivalents at beginning of period	123,050			5,048			61,647
Cash and cash equivalents at end of period	$	1,213		$	123,050		$	5,048

The accompanying notes are an integral part of these consolidated financial statements.

42

CIMAREX ENERGY CO.

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY AND COMPREHENSIVE INCOME (LOSS)

(In thousands)

	Common Stock					Paid-in			Unearned			Retained			Accumulated Other Comprehensive			Treasury			Total Stockholders’
	Shares		Amount			Capital			Compensation			Earnings			Income			Stock			Equity
Balance, December 31, 2005	83,524		$	835		$	1,865,597		$	(15,862	)	$	788,356		$	81		$	(43,554	)	$	2,595,453
Cumulative effect of accounting change, net of tax						19,009						(722		)							18,287
Dividends	—		—			—			—			(16,673		)	—			—			(16,673		)
Issuance of restricted stock awards	601		6			13,682			(13,688		)	—			—			—			—
Treasury Stock	—		—			—			—			—			—			(8,090		)	(8,090		)
Common stock reacquired and retired	(278	)	(3		)	(12,039		)	—			—			—			11,016			(1,026		)
Restricted stock forfeited and retired	(55	)				(361		)	314			—			—			—			(47		)
Amortization of unearned compensation	—		—			7,019			2,262			—			—			—			9,281
Reclass restricted unit liability to unearned compensation	—		—			—			13,881			—			—			—			13,881
Reclass remaining unearned compensation to paid-in capital	—		—			(13,093		)	13,093			—			—			—			—
Exercise of stock options, net of tax benefit of $1,618 recorded in paid-in capital	170		2			4,313			—			—			—			—			4,315
Stock Option Compensation Expense	—		—			2,330			—			—			—			—			2,330
Comprehensive income:
Net income	—		—			—			—			344,481			—			—			344,481
Unrealized gain on derivatives, net of tax	—		—			—			—			—			30,954			—			30,954
Unrealized gain on marketable securities of investments, net of tax	—		—			—			—			—			46			—			46
Total comprehensive income																					375,481
Balance, December 31, 2006	83,962		$	840		$	1,886,457		$	—		$	1,115,442		$	31,081		$	(40,628	)	$	2,993,192
Dividends	—		—			—			—			(15,109		)	—			—			(15,109		)
Issuance of restricted stock awards	572		5			(5		)	—			—			—			—			—
Treasury Stock	—		—			—			—			—			—			(42,266		)	(42,266		)
Common stock reacquired and retired	(1,306	)	(13		)	(49,270		)	—			—			—			42,266			(7,017		)
Restricted stock forfeited and retired	(61	)	(1		)	1			—			—			—			—			—
Amortization of unearned compensation	—		—			12,738			—			—			—			—			12,738
Exercise of stock options, net of tax benefit of $4,026 recorded in paid-in capital	454		5			9,881			—			—			—			—			9,886
Stock Option Compensation Expense	—		—			1,897			—			—			—			—			1,897
Comprehensive income:
Net income	—		—			—			—			345,262			—			—			345,262
Net change from hedging activity	—		—			—			—			—			(23,302		)	—			(23,302		)
Unrealized loss on short-term investments and other, net of tax	—		—			—			—			—			(153		)	—			(153		)
Total comprehensive income																					321,807
Balance, December 31, 2007	83,621		$	836		$	1,861,699		$	—		$	1,445,595		$	7,626		$	(40,628	)	$	3,275,128

43

CIMAREX ENERGY CO.

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY AND COMPREHENSIVE INCOME (LOSS)

(In thousands)

	Common Stock					Paid-in			Unearned		Retained			Accumulated Other Comprehensive			Treasury			Total Stockholders’
	Shares		Amount			Capital			Compensation		Earnings			Income			Stock			Equity
Dividends	—		—			—			—		(20,079		)	—			—			(20,079		)
Issuance of restricted stock awards	465		5			(5		)	—		—			—			—			—
Retirement of treasury stock	(193	)	(2		)	(7,282		)	—		—			—			7,284			—
Common stock reacquired and retired	(154	)	(1		)	(9,938		)	—		—			—			—			(9,939		)
Restricted stock forfeited and retired	(54	)	(1		)	1			—		—			—			—			—
Amortization of unearned compensation	—		—			15,491			—		—			—			—			15,491
Exercise of stock options, net of tax benefit of $6,712 recorded in paid-in capital	414		4			13,137			—		—			—			—			13,141
Stock Option Compensation Expense	—		—			1,731			—		—			—			—			1,731
Vesting of restricted stock units	45		—			—			—		—			—			—			—
Comprehensive (loss):
Net (loss)	—		—			—			—		(915,245		)	—			—			(915,245		)
Net change from hedging activity	—		—			—			—		—			(7,652		)	—			(7,652		)
Unrealized loss on short-term investments and other, net of tax	—		—			—			—		—			(929)			—			(929		)
Total comprehensive (loss)																				(923,826		)
Balance, December 31, 2008	84,144		$	841		$	1,874,834		$	—	$	510,271		$	(955	)	$	(33,344	)	$	2,351,647

The accompanying notes are an integral part of these consolidated financial statements.

44

CIMAREX ENERGY CO.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. BASIS OF PRESENTATION

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

In June of 2005, we acquired Magnum Hunter Resources, Inc. in a stock-for-stock merger. Magnum Hunter’s results of operations are included in our consolidated statements of operations beginning June 7, 2005.

The accounts of Cimarex and its subsidiaries are presented in the accompanying Consolidated Financial Statements. All intercompany accounts and transactions were eliminated in consolidation.

Our Consolidated Financial Statements 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 3 to our Consolidated Financial Statements. 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.

Certain amounts in prior years’ financial statements have been reclassified to conform to the 2008 financial statement presentation.

2. DESCRIPTION OF BUSINESS

Cimarex Energy Co. is an independent oil and gas exploration and production company with operations entirely located in the United States. Our oil and gas reserves and operations are mainly located in Texas, Oklahoma, New Mexico, Kansas, Louisiana, and Wyoming. We operate wells that account for a substantial portion of our total proved reserves and production.

3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Cash, Cash Equivalents and Restricted Cash

Cash and cash equivalents consist of cash in banks and investments readily convertible into cash, which have original maturities within three months at the date of acquisition. Cash equivalents are stated at cost, which approximates market value. Restricted cash consists of monies of third parties being held by Cimarex as operator of a property in Oklahoma, until ownership disputes among the third parties are resolved.

Short-term Investments

Our short-term investments consist of investments in an asset-backed securities fund. The investments are classified as available-for-sale and are carried at fair value in our balance sheet. Unrealized holding gains and losses are reported in other comprehensive income (loss).

Inventories

Inventories, primarily materials and supplies, are valued at the lower of cost or market using weighted average cost.

45

CIMAREX ENERGY CO.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Oil and Gas Properties

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. Under the full cost method of accounting, no gain or loss is recognized upon the disposition of oil and gas properties unless such disposition would significantly alter the relationship between capitalized costs and proved reserves.

At the end of each quarter, we make a full cost ceiling limitation calculation, whereby net capitalized costs related to proved properties less associated deferred income taxes may not exceed the amount of 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 any. Changes in proved reserve estimates (whether based upon quantity revisions or oil and gas prices) will cause corresponding changes to the full cost ceiling limitation. If net capitalized costs subject to amortization exceed this limit, the excess would be charged to expense. However, if commodity prices increase after period end and before issuance of the financial statements, these higher commodity prices may be used to determine if the capital costs are in fact impaired as of the end of the period. Any recorded impairment of oil and gas properties is not reversible at a later date.

Due to a significant decrease in period end commodity prices, at September 30, 2008, our ceiling limitation calculation resulted in excess capitalized costs of $657.1 million ($417.4 million, net of tax), for which we recorded a non-cash impairment of oil and gas properties. As a result of further declines in commodity prices during the fourth quarter of 2008, we recorded an additional non-cash impairment of oil and gas properties. Based on prices at December 31, 2008, our ceiling limitation calculation resulted in excess capitalized costs of $1.6 billion ($1.0 billion after tax), for which we recorded a non-cash impairment of oil and gas properties. The Company’s quarterly and annual ceiling test is primarily impacted by period end commodity prices, reserve quantities added and produced, overall exploration and development costs and depletion expense. Holding all factors constant other than commodity prices, a 10% decline in prices as of December 31, 2008 would have resulted in an additional ceiling test impairment of approximately 12% of our full cost pool. Also, goodwill could be potentially impaired. Changes in actual reserve quantities added and produced along with our actual overall exploration and development costs will impact the Company’s actual ceiling test calculation and impairment analyses.

Depletion of proved oil and gas properties is computed on the units-of-production method, whereby capitalized costs, as adjusted for future development costs and asset retirement obligations, are amortized over the total estimated proved reserves. The costs of wells in progress and certain unevaluated properties are not being amortized. On a quarterly basis, we evaluate such costs for inclusion in the costs to be amortized resulting from the determination of proved reserves, impairments, or reductions in value. To the extent that the evaluation indicates these properties are impaired, the amount of the impairment is added to the capitalized costs to be amortized. Expenditures for maintenance and repairs are charged to production expense in the period incurred.

Goodwill

At December 31, 2008, we had $691.4 million of goodwill recorded in conjunction with past business combinations. Goodwill is subject to annual reviews for impairment based on a two-step accounting test. The first step is to compare the estimated fair value of the Company with the recorded net book value (including goodwill), after giving effect to any period impairment of oil and gas properties resulting from the ceiling limitation calculation. If the estimated fair value is higher than the recorded net book value, no impairment is deemed to exist and no further testing is required. If, however, the estimated fair value is below the recorded net book value, then a second step must be performed to determine the goodwill impairment required, if any. In this second step, the estimated fair value from the first step is used as the purchase price in a hypothetical acquisition of the Company. Purchase business combination accounting rules are followed to determine a hypothetical purchase price allocation

46

CIMAREX ENERGY CO.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

to the Company’s assets and liabilities. The residual amount of goodwill that results from this hypothetical purchase price allocation is compared to the recorded amount of goodwill and the recorded amount is written down to the hypothetical amount, if lower. We perform our annual goodwill impairment review in the fourth quarter of each year.

During the fourth quarter of 2008, there were severe disruptions in the credit markets and reductions in global economic activity which had significant adverse impacts on stock markets and oil-and-gas-related commodity prices. Management must apply judgment in determining the estimated fair value of the Company for purposes of performing the annual goodwill impairment test. As of December 31, 2008, the book value per share of our common stock exceeded the market price by less than $2 per share. Management does not consider the market value of our shares to be an accurate reflection of our net assets, for impairment purposes. To estimate the fair value of the Company, we used all available information to make these fair value determinations, including the present values of expected future cash flows using discount rates commensurate with the risks involved in the assets.

In estimating the fair value of our oil and gas properties, we used projected future prices based on the NYMEX strip index at December 31, 2008 (adjusted for estimated delivery point price differentials). Based on our current exploration plans, we included estimated future cash flows from development of our unproved properties and applied a discount rate of 15% to 20%, depending on the reserve category. This resulted in a slight excess of fair value over the carrying value of our net assets at year end. Should lower prices or quantities result in the future, or higher discount rates be necessary, the carrying value of our net assets may exceed the estimated fair value, resulting in an impairment of goodwill.

Revenue Recognition

Oil and Gas Sales

Revenues from oil and gas sales are 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.

Marketing Sales

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 consolidated statement of operations.

Gas Imbalances

We use the sales method of accounting for gas imbalances. Under this method, revenue is recorded on the basis of gas actually sold. Oil and gas reserves are adjusted to the extent there are sufficient quantities of natural gas to make up an imbalance. In situations where there are insufficient reserves available to make-up an overproduced imbalance, then a liability is established. The natural gas imbalance liability at December 31, 2008 and 2007 was $3.5 million and $3.6 million, respectively. At December 31, 2008 and 2007, we were also in an under-produced position relative to certain other third parties.

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, subjective decisions and available data for our various fields make these estimates generally less precise than other estimates included in financial statement disclosures. For 2008, revisions of previous estimates decreased proved reserves by 156.7 Bcfe or 12% of total proved reserves on December 31, 2008. Our

47

CIMAREX ENERGY CO.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

negative revisions resulted from lower oil and gas prices and increased lease operating expenses. See Note 16, Supplemental Oil and Gas Disclosures for more reserve information. At year-end, 18% of our total proved reserves are categorized as proved undeveloped. Of these proved undeveloped reserves, 89% are related to a project in Wyoming.

We use the units-of-production method to amortize the cost of our oil and gas properties. Changes in reserve quantities and commodity prices will cause corresponding changes in depletion expense in periods subsequent to these changes, or in some cases, a full cost ceiling limitation charge in the period of the revision.

Transportation Costs

We account for transportation costs under Emerging Issues Task Force (“EITF”) 00-10 Accounting for Shipping and Handling Fees and Costs. Amounts paid for transportation are classified as an operating expense and are not netted against gas sales.

Derivatives

SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, requires that all derivatives be recorded on the balance sheet at fair value. 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 (loss) 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 are recognized in gas revenues in the period the contracts are settled.

Existing commodity derivatives acquired in the Magnum Hunter merger did not qualify for hedge accounting treatment. During 2006, Cimarex recognized a net gain of $23.0 million. Activity included non-cash mark-to-market derivative gains and losses as well as cash settlements. Cash payments related to these contracts for 2006 totaled $19.0 million. All of the contracts assumed with the merger had expired at December 31, 2006.

In 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 with Mid-Continent weighted average floor and ceiling prices of $7.00 to $10.17 for 2007 and $7.00 to $9.90 for 2008, we hedged 29.2 million MMBtu and 14.6 million MMBtu of our anticipated Mid-Continent gas production for 2007 and 2008, respectively. At December 31, 2008, there were no remaining contracts outstanding.

Under the collar agreements, we received the difference between an agreed upon index price and a floor price if the index price was below the floor price. We paid the difference between the agreed upon contracted ceiling price and the index price only if the index price was above the contracted ceiling price. No amounts are paid or received if the index price is between the contracted floor and ceiling prices. These contracts were designated for hedge accounting treatment as cash flow hedges.

Settlements received during the year ended December 31, 2008 and 2007 totaled $11.3 million and $27.8 million, which were recorded in gas sales and increased the average realized price for the year by $0.09 per Mcf and $0.23 per Mcf, respectively. During the periods ended December 31, 2008 and 2007, we recognized a loss of $35 thousand and a gain of $49 thousand, respectively, related to the ineffective portion of the derivative contracts.

At December 31, 2007, the fair value of the remaining contracts was approximately $12.1 million and was recorded as a current asset, and an unrealized gain (net of deferred income taxes) of $7.7 million was recorded in other comprehensive income (loss). At December 31, 2008, all of the contracts were completed.

48

CIMAREX ENERGY CO.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Income Taxes

Deferred income taxes are computed using the liability method. Deferred income taxes are provided on all temporary differences between the financial basis and the tax basis of assets and liabilities. Valuation allowances are established to reduce deferred tax assets to an amount that more likely than not will be realized.

We adopted the provisions of Financial Accounting Standards Board Interpretation No. 48 “Accounting for Uncertainty in Income Taxes” (“FIN 48”) an interpretation of FASB Statement No. 109 “Accounting for Income Taxes”, on January 1, 2007. The interpretation clarifies the accounting for uncertainty in income taxes recognized in our financial statements and provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition. The adoption of FIN 48 resulted in no impact to our consolidated financial statements and we have no unrecognized tax benefits that would impact our effective rate.

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.

In January 2009, the Tulsa County District Court issued a judgment in the H.B. Krug, et al versus Helmerich & Payne, Inc. (“H&P”) case. This lawsuit was originally filed in 1998 and addressed H&P’s conduct pertaining to a 1989 take-or-pay settlement, along with potential drainage issues and other related matters. Damages of $6.9 million plus $119.5 million for disgorgement of H&P’s estimated potential compounded profit since 1989, resulting from the noted damages, were awarded to plaintiff royalty owners, to a total of $126.4 million. This amount was subsequently adjusted by the court to a total of $119.6 million. Pursuant to the 2002 spin-off transaction to shareholders of H&P by which Cimarex became a publicly-traded entity, Cimarex assumed the assets and liabilities of H&P’s exploration and production business. In September 2008, based on the available information at the time, we accrued an estimated litigation expense of $12 million for both damages and probable disgorgement. The higher disgorgement award could not be reasonably estimated until the final judgment in January 2009. We therefore accrued an additional $107.6 million, bringing the total accrued litigation expense for the year ended December 31, 2008 to $119.6 million for this lawsuit. We have appealed the District Court’s judgments.

As of December 31, 2008, in the normal course of business, we have other various litigation related matters and associated accruals. Though some of the related claims may be significant, the resolution of them we believe, individually or in the aggregate, would not have a material adverse effect on our financial condition or results of operations.

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. Subsequent to initial measurement, the asset retirement liability is required to be accreted each period. Capitalized costs are depleted as a component of the full cost pool.

Stock Options

Effective January 1, 2005, we adopted the provisions of Statement of Financial Accounting Standards (“SFAS”) No. 123R, Share Based Payment on a modified 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.

49

CIMAREX ENERGY CO.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Earnings per Share

See discussion below under Recently Issued Accounting Standards.

Comprehensive Income (Loss)

Comprehensive income is a term used to refer to net income plus other comprehensive income (loss). Other comprehensive income (loss) 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 other comprehensive income (loss) are as follows (in 000’s):

	Net Unrealized Gain on Derivative Instruments(1)			Net Unrealized Gain (or Loss) On Short-Term Investments and Other(1)			Accumulated Other Comprehensive Income (Loss)
Balance at January 1, 2006	$	—		$	81		$	81
2006 activity	30,954			46			31,000
Balance at December 31, 2006	30,954			127			31,081
2007 activity	(23,302		)	(153		)	(23,455		)
Balance at December 31, 2007	$	7,652		$	(26	)	$	7,626
2008 activity	(7,652		)	(929		)	(8,581		)
Balance at December 31, 2008	$	—		$	(955	)	$	(955	)

(1)Net of tax

The table below sets forth the changes in the Company’s unrealized gains on derivative instruments included as a component of comprehensive income (loss) for the years ended December 31, 2008 and 2007 (in 000’s):

	2008			2007
Unrealized derivative gain in comprehensive income, at January 1	$	12,088		$	49,009
Change in fair value	(851		)	(9,043		)
Reclassification of net gains to income	(11,272		)	(27,829		)
Net ineffectiveness	35			(49		)
	—			12,088
Related income tax effect	—			(4,436		)
Unrealized derivative gain in comprehensive income (loss) at December 31	$	—		$	7,652

Segment Information

Cimarex has one reportable segment (exploration and production).

Recently Issued Accounting Standards

In May, 2008, the Financial Accounting Standards Board (“FASB”) issued a new Staff Position APB 14-1, Accounting for Convertible Debt Instruments That May Be Settled in Cash upon Conversion (Including Partial Cash Settlement), that will impact the accounting for the components of convertible debt that can be settled wholly or partly in cash upon conversion. The new requirements apply not only to new instruments, but also would be applied retrospectively to previously issued convertible instruments. The debt and equity components of the instruments are to be accounted for separately. The value assigned to the debt component is the estimated value of similar debt without a conversion feature as of the issuance date, with the remaining proceeds allocated to the equity component and recorded as additional paid-in capital. The debt component is recorded at a discount and is

50

CIMAREX ENERGY CO.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

subsequently accreted to its par value, thereby reflecting an overall market rate of interest in the income statement. This Staff Position is effective for both new and previously issued instruments for current and comparative periods in fiscal years beginning after December 15, 2008, and interim periods within those years. We adopted this in the first quarter of 2009 and accordingly, data herein has been recast to reflect such adoption.

In June, 2008, the FASB issued a new Staff Position EITF 03-6-1, Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities, which holds that unvested share-based payment awards that contain non forfeitable rights to dividends or dividend equivalents are “participating securities” (as defined by EITF 03-6 as securities that may participate in undistributed earnings with common stock, whether that participation is conditioned upon the occurrence of a specified event or not, regardless of the form of participation), and therefore should be included in computing earnings per share using the two-class earnings allocation method. The two-class method is an earnings allocation formula that determines earnings per share for each class of common stock and participating security according to dividends declared (or accumulated) and participation rights in undistributed earnings. The requirements of this Staff Position are to be applied by restating previously reported earnings per share data. Under this staff position, our unvested share based payment awards, consisting of restricted stock and restricted stock units, qualify as participating securities. We adopted this in the first quarter of 2009 and earnings per share data herein have been recast to present such data using the two-class method.

4. FAIR VALUE MEASUREMENTS

Our short-term investments are reported at fair value in the accompanying balance sheets. SFAS No. 157, Fair Value Measurements establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. This hierarchy consists of three broad levels. Level 1 inputs are the highest priority and consist of unadjusted quoted prices in active markets for identical assets and liabilities. Level 2 inputs are inputs other than quoted prices that are observable for the asset or liability, either directly or indirectly. Level 3 inputs are unobservable inputs for an asset or liability. The following tables provide fair value measurement information for certain assets and liabilities as of December 31, 2008 and 2007.

	Carrying Amount			Fair Value
	(In thousands)
December 31, 2008:
Financial Assets (Liabilities):
Short-term investments	$	2,502		$	2,502
7.125% Notes due 2017	$	(350,000	)	$	(267,750	)
Bank debt	$	(220,000	)	$	(220,000	)
Floating rate convertible notes due 2023	$	(17,630	)	$	(19,450	)

	Carrying Amount			Fair Value
	(In thousands)
December 31, 2007:
Financial Assets (Liabilities):
Short-term investments	$	14,391		$	14,391
Derivative instruments	$	12,124		$	12,124
7.125% Notes due 2017	$	(350,000	)	$	(346,504	)
Floating rate convertible notes due 2023	$	(112,216	)	$	(183,395	)

Assessing the significance of a particular input to the fair value measurement requires judgment, considering factors specific to the asset or liability. The following methods and assumptions were used to estimate the fair values of the assets and liabilities in the table above.

Short-term Investments (Level 2)

In the fourth quarter of 2007, we invested $16 million in an asset-backed securities fund, which we expect to be liquidated in 2009. The investments are classified as available-for-sale, and at the end of each period, changes

51

CIMAREX ENERGY CO.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

in the fair value of the investments are recorded in other comprehensive income (loss). The fair values of these investments are based on a net asset valuation provided by the fund manager. During 2008, we liquidated $10.4 million of the investments, with a realized loss of $395 thousand and an impairment charge of $801 thousand, both of which were included in earnings for the period. We also reflected an unrealized loss of $664 thousand in other comprehensive income (loss) as of December 31, 2008.

As of December 31, 2007, we had liquidated $1.4 million of the investments with a realized loss of $17 thousand, included in earnings for the period, and an unrealized loss of $184 thousand, recorded in other comprehensive income (loss).

Bank Debt and Notes

Debt

The fair value of our bank debt is estimated to approximate the carrying amount as the interest is a floating rate based on either the London Interbank Offered Rate (“LIBOR”) or the JP Morgan Chase Bank prime rate and resets periodically.

Notes

The fair values for our 7.125% fixed rate notes were based on their last traded value before year end.

There is not an observable market for our convertible notes. At December 31, 2008, the fair value of the notes was estimated to approximate the face value of the notes, because the notes bear interest at LIBOR, and reset quarterly. The conversion rate of $28.59 attributable to the conversion feature at December 31, 2008 exceeded the $26.78 per share closing price of our common stock; therefore, no value was attributed to the conversion feature. At December 31, 2007, the closing price of our common stock was $42.53 per share and exceeded the $28.99 conversion ratio. Therefore, the fair value of the convertible notes at December 31, 2007 included value attributable to both the face amount of the notes and the conversion feature.

Derivative Instruments

At December 31, 2008, we had no derivative instruments outstanding. The fair value of our derivative instruments at December 31, 2007 was estimated using internal discounted cash flow calculations based on the stated contract prices and current and projected market prices at December 31, 2007.

Other Financial Instruments

The carrying amounts of our cash, cash equivalents, restricted cash, accounts receivable, accounts payable, and accrued liabilities approximate fair value because of the short-term maturities of these assets and liabilities. At December 31, 2008, the allowance for doubtful accounts for trade, oil and gas sales, and gas gathering, processing, and marketing receivables was $5.1 million, $0.7 million, and zero, respectively. At December 31, 2007, the allowance for doubtful accounts for trade, oil and gas sales, and gas gathering, processing, and marketing receivables was $5.6 million, $0.2 million, and zero, respectively.

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

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

52

CIMAREX ENERGY CO.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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. Subsequent to initial measurement, the asset retirement liability is required to be accreted each period. If the fair value of a recorded asset retirement obligation changes, a revision is recorded to both the asset retirement obligation and the asset retirement capitalized cost. Capitalized costs are depleted as a component of the full cost pool.

The following table reflects the components of the change in the carrying amount of the asset retirement obligation for the years ended December 31, 2008 and 2007 (in thousands):

	2008			2007
Asset retirement obligation at January 1	$	113,054		$	129,141
Liabilities incurred	6,095			5,063
Liability settlements and disposals	(8,882		)	(25,880		)
Accretion expense	6,663			6,628
Revisions of estimated liabilities	23,018			(1,898		)
Asset retirement obligation at December 31	139,948			113,054
Less current obligation	14,610			7,270
Long-term asset retirement obligation	$	125,338		$	105,784

During 2008 we recognized a revision of $23 million to our asset retirement obligation. The net increase resulted primarily from an overall increase in abandonment cost estimates and changes in the productive lives of our wells.

6. LONG TERM DEBT

Debt at December 31, 2008 and 2007 consisted of the following (in thousands):

	2008		2007
Bank debt	$	220,000	$	—
7.125% Notes due 2017	350,000		350,000
Floating rate convertible notes due 2023 (face value $19,450 and $125,000, respectively)	17,630		112,216		(1)
Total long-term debt	$	587,630	$	462,216

(1)Fair market value at June 7, 2005 was $109.2 million. The subsequent noted balances represent the fair market value at date of acquisition plus amortization of the discount of the difference between the fair market value and the face value of the notes. The 2008 balance also reflects our repurchase of $105.6 million of face value of the notes in December, 2008.

Bank Debt

We have a $1.0 billion senior secured revolving credit facility (“credit facility”) with a syndicate of banks that had a borrowing base of $1.0 billion as of December 31, 2008. At our option we set the banks’ lending commitment under the credit facility at $500 million. The borrowing base is determined at the discretion of the lenders, based on the collateral value of our proved reserves and is subject to potential special and regular semi-annual redeterminations.

The credit facility matures on July 1, 2010 and is secured by mortgages on certain oil and gas properties and the stock of certain wholly-owned operating subsidiaries. Amounts outstanding bear interest at our election at either a floating LIBOR plus 1%-1.75% or at the JP Morgan Chase Bank prime rate plus 0%-0.5%. At December 31, 2008, there was $220 million of borrowings outstanding under the credit facility at a weighted average interest rate of approximately 1.66%. We also had letters of credit outstanding of $2.8 million leaving an unused borrowing availability of $277.2 million at December 31, 2008.

53

CIMAREX ENERGY CO.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The credit facility contains various covenants and restrictive provisions which may limit our ability to incur additional indebtedness, make investments or loans and create liens. The credit agreement requires us to maintain a current ratio (current assets to current liabilities, as defined) greater than 1 to 1 and a leverage ratio (indebtedness to EBITDA, as defined) not to exceed 3.0 to 1. The current ratio, as defined by the credit agreement, at December 31, 2008, was 1.69 to 1 and our leverage ratio was 0.42 to 1. As of December 31, 2008 we were in compliance with all of the financial and non-financial covenants.

7.125% Notes due 2017

In May, 2007 we issued $350 million of 7.125% senior unsecured notes that mature May 1, 2017 at par. Interest on the notes is payable May 1 and November 1 of each year. The notes are governed by an indenture containing covenants that could limit our ability to incur additional indebtedness; pay dividends or repurchase our common stock; make investments and other restricted payments; incur liens; enter into sale/leaseback transactions; engage in transactions with affiliates; sell assets; and consolidate, merge or transfer assets.

The notes are redeemable at our option, in whole or in part, at any time on and after May 1, 2012 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
2012	103.6	%
2013	102.4	%
2014	101.2	%
2015 and thereafter	100.0	%

At any time prior to May 1, 2010, we may redeem up to 35% of the original principal amount of the notes with the proceeds of certain equity offerings of our shares of common stock at a redemption price of 107.125% of the principal amount of the notes, together with accrued and unpaid interest, if any, to the date of redemption. At any time prior to May 1, 2012, we may also redeem all, but not part, of the notes at a price of 100% of the principal amount of the notes plus accrued and unpaid interest plus a “make-whole” premium.

If a specified change of control occurs, subject to certain conditions, we must make an offer to purchase the notes at a purchase price of 101% of the principal amount of the notes, plus accrued and unpaid interest to the date of the purchase.

Floating rate convertible notes due 2023

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 of three month LIBOR, reset quarterly. On December 31, 2008, the interest rate was 2.0%.

The holders as of December 15, 2008, had the right to require us to repurchase all or a portion of the notes at 100% of the principal amount (plus accrued interest). As of December 15, 2008, holders with principal of $105.550 million submitted their notes for repurchase leaving $19.450 million still outstanding. We repurchased the $105.550 million in notes with borrowings under our credit facility. The remaining notes have future repurchase dates as of December 15, 2013, and 2018. We have the right at any time to redeem some or all of the notes still outstanding at a redemption price of 100% of the principal amount (plus accrued interest).

In addition to the repurchase rights, 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 conversion price of $28.59 per share. On December 31, 2008, the closing price of our common stock traded on the New York Stock Exchange was $26.78. If a specified change of control occurs, subject to certain conditions, we must make an offer to purchase the notes at a purchase price of 101% of the principal amount of the notes, plus accrued and unpaid interest to the date of the purchase.

54

CIMAREX ENERGY CO.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

In May, 2008, the Financial Accounting Standards Board (“FASB”) issued a new Staff Position APB 14-1, Accounting for Convertible Debt Instruments That May Be Settled in Cash upon Conversion (Including Partial Cash Settlement), that changed the accounting for the components of convertible debt that can be settled wholly or partly in cash upon conversion. The new requirements are required to be applied to both new instruments and retrospectively to previously issued convertible instruments. The debt and equity components of the instruments are accounted for separately. The value assigned to the debt component is the estimated value of similar debt without a conversion feature as of the issuance date, with the remaining proceeds allocated to the equity component and recorded as additional paid-in capital. The debt component is recorded at a discount and is subsequently accreted to its par value, thereby reflecting an overall market rate of interest in the income statement. We adopted this Staff Position on January 1, 2009. Upon adoption we retrospectively recorded a $30 million decrease in the book value of our Floating Rate Convertible Notes to $109.2 million, as of June 7, 2005, with a corresponding increase in additional paid-in-capital which results in a total of $79.6 million attributable to the equity component. We also recorded additional non-cash interest expense of approximately $1.9 million ($1.2 million after tax) per year for 2008, 2007 and 2006, which resulted in an effective annual interest rate of 4.4%, 7.1% and 6.8%, respectively. Prior to the adoption, for the year ended December 31, 2008, we had recorded a $9.6 million ($6.0 million net of tax) gain on the repurchase of $105.6 million of the notes. Upon adoption, we retrospectively recorded a loss on the repurchase of $10.1 million ($6.4 million after tax).

7. INCOME TAXES

Federal income tax expense (benefit) for the years ended December 31, 2008, 2007, and 2006 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 the Domestic Production Activities deduction. The components of the provision for income taxes are as follows (in thousands):

	Years Ended December 31,
	2008			2007		2006
Current taxes:
Federal	$	65,323		$	26,993	$	(20,672	)
State	866			3,656		(1,262		)
	66,189			30,649		(21,934		)
Deferred taxes:
Federal	(576,699		)	161,477		210,871
State	(25,894		)	5,336		8,956
	(602,593		)	166,813		219,827
	$	(536,404	)	$	197,462	$	197,893

Reconciliations of the income tax (benefit) expense calculated at the federal statutory rate of 35% to the total income tax (benefit) expense are as follows (in thousands):

	Years Ended December 31,
	2008			2007			2006
Provision at statutory rate	$	(508,044	)	$	189,974		$	189,851
Effect of state taxes	(26,453		)	8,992			7,514
Domestic Production Activities deduction	(2,208		)	(1,723		)	—
Other	301			219			528
Income tax (benefit) expense	$	(536,404	)	$	197,462		$	197,893

55

CIMAREX ENERGY CO.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The components of Cimarex’s net deferred tax liabilities are as follows (in thousands):

	December 31,
	2008			2007
Long-term:
Assets:
Credit carryforwards	$	—		$	3,587
Other	37,411
	37,411			3,587
Liabilities:
Property, plant and equipment	(538,356		)	(1,088,912		)
Net, long-term deferred tax liability	(500,945		)	(1,085,325		)
Current:
Assets:
Derivative instruments	—			4,445
Other	2,435			1,252
	2,435			5,697
Net deferred tax liabilities	$	(498,510	)	$	(1,079,628	)

We have recorded deferred tax assets of $39.8 million the realization of which is dependent on generating sufficient taxable income in the future.

We adopted the provisions of Financial Accounting Standards Board Interpretation No. 48 “Accounting for Uncertainty in Income Taxes” (“FIN 48”) an interpretation of FASB Statement No. 109 “Accounting for Income Taxes”, on January 1, 2007. The interpretation clarifies the accounting for uncertainty in income taxes recognized in our financial statements and provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition. The adoption of FIN 48 resulted in no impact to our consolidated financial statements and we have no unrecognized tax benefits that would impact our effective rate.

As of December 31, 2008, we made no provisions for interest or penalties related to uncertain tax positions. The tax years 2005 - 2007 remain open to examination by the Internal Revenue Service of the United States. We file tax returns with various state taxing authorities which remain open for tax years 2004 - 2007 for examination.

8. CAPITAL STOCK

Stock-based Compensation

Our 2002 Stock Incentive Plan was approved by stockholders in May 2003 and is effective until October 1, 2012. The plan provides for grants of stock options, restricted stock and restricted stock units to non-employee directors, officers and other eligible employees. A total of 12.7 million shares of common stock may be issued under the Plan.

Restricted Stock and Units

During 2008 we issued a total of 464,620 restricted shares and 3,790 restricted units to non-employee directors, officers, and other employees. Included in that amount are 244,000 shares issued to certain executives that are subject to market condition-based vesting determined by our stock price performance relative to a defined peer group’s stock price performance. After three years of continued service, an executive will be entitled to vest in 50% to 100% of the award. The material terms of performance goals applicable to these awards were approved by stockholders in May 2006. The remaining shares and units granted in 2008 have service-based vesting schedules of three to five years.

56

CIMAREX ENERGY CO.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The following table presents restricted stock activity during the last three years:

	Years Ended December 31,
	2008		2007		2006
Outstanding beginning of period	1,289,695		792,779		249,905
Vested	(28,470	)	(13,693	)	(7,915	)
Granted	464,620		572,009		600,589
Canceled	(53,600	)	(61,400	)	(49,800	)
Outstanding end of period	1,672,245		1,289,695		792,779

The following table presents restricted unit activity during the last three years:

	Years Ended December 31,
	2008		2007	2006
Outstanding beginning of period	701,915		696,641	697,937
Converted to Stock	(45,500	)	—	—
Granted	3,790		5,274	4,954
Canceled	(5,000	)	—	(6,250	)
Outstanding end of period	655,205		701,915	696,641
Vested included in outstanding	596,247		559,839	172,617

Vesting of restricted stock and units granted in years before 2006 is exclusively related to continued service of the grantee for one to five years. In certain cases, a three year required holding period following vesting also applies. A restricted unit represents a right to an unrestricted share of common stock upon completion of defined vesting and holding periods. The restricted stock and stock unit agreements provide that grantees are entitled to receive dividends on unvested shares.

Compensation expense for service-based vesting restricted shares or units is based upon amortization of the grant-date market value of the award. The fair value of the market condition-based restricted stock is based on the grant-date market value of the award utilizing a Monte Carlo simulation model to estimate the percentage of awards that will vest at the end of the three-year period. Compensation expense related to the restricted stock and unit awards is recognized ratably over the applicable vesting period. We recorded compensation costs related to the restricted stock and units as follows (in thousands):

	Years Ended December 31,
	2008		2007		2006
Compensation costs:
Recorded as expense	$	9,363	$	8,875	$	5,913
Capitalized to oil and gas properties	$	6,128	$	3,863	$	3,320

Unamortized compensation costs related to unvested restricted shares and units at December 31, 2008, 2007, and 2006 was $33.6 million, $31.7 million, and $30.6 million, respectively.

Stock Options

Options granted under our plan expire ten years from the grant date and have service-based vesting schedules of three to five years. The plan provides that all grants have an exercise price of the average of the high and low prices of our common stock as reported by the New York Stock Exchange on the date of grant. Upon the exercise of certain stock options granted after October 1, 2002, grantees are required to hold at least 50% of the profit shares, as defined in the plan, until the eighth anniversary of the grant date.

57

CIMAREX ENERGY CO.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

There were 483,500 stock options granted during 2008. Information about outstanding stock options is summarized below:

	Shares		Weighted Average Exercise Price		Weighted Average Remaining Term	Aggregate Intrinsic Value (000)
Outstanding as of January 1, 2008	1,489,565		$	17.73
Exercised	(414,449	)	15.51
Granted	483,500		56.70
Canceled	(26,600	)	56.74
Outstanding as of December 31, 2008	1,532,016		$	29.95	5.6 Years	$	10,219
Exercisable as of December 31, 2008	1,002,396		$	17.17	3.6 Years	$	10,219

The total intrinsic value of stock options exercised during 2008, 2007 and 2006 was $18.9 million, $11.0 million and $4.4 million, respectively.

Compensation cost for stock options is determined pursuant to SFAS No. 123R. Historical amounts may not be representative of future amounts as additional options may be granted. We recognize compensation cost ratably over the vesting period. During 2008, 2007 and 2006, compensation cost (including capitalized amounts) were $1.7 million, $1.9 million and $2.3 million, respectively.

The weighted-average grant-date fair value of stock options granted during the years ended December 31, 2008, 2007 and 2006 was $19.44, $15.62 and $15.75, respectively. The fair value of options 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 the probability of option exercise, expected years until exercise and potential forfeitures. The risk-free interest rate used is the five-year U.S. Treasury bond in effect at the date of the grant.

The following summarizes the assumptions used to determine the fair market value of options issued during the last three years:

	Years Ended December 31,
	2008		2007		2006
Expected years until exercise	5.5		7.5		7.5
Expected stock volatility	32.4	%	32.3	%	32.2	%
Dividend yield	0.6	%	0.6	%	0.1	%
Risk-free interest rate	3.5	%	3.3	%	4.8	%

Cash received from option exercises during the years ended December 31, 2008, 2007, and 2006 was approximately $6.4 million, $5.9 million, and $2.7 million, respectively. The related tax benefits realized from option exercises totaled approximately $6.7 million, $4.0 million, and $1.6 million, respectively, and were recorded to paid-in capital.

58

CIMAREX ENERGY CO.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The following summary reflects the status of non-vested stock options granted to employees and directors as of December 31, 2008 and changes during the year:

	Shares		Weighted Average Grant Date Fair Value
Non-vested as of January 1, 2008	101,760		$	15.59
Vested	(29,040	)	14.68
Granted	483,500		19.44
Forfeited	(26,600	)	19.43
Non-vested as of December 31, 2008	529,620		$	18.96

As of December 31, 2008 there was $8.7 million of unrecognized compensation cost related to non-vested stock options granted under our stock incentive plan. We expect to recognize that cost pro rata over a weighted-average period of 2.6 years. The weighted average exercise price of the non-vested stock options is $54.15.

The total grant-date fair value of options that vested during 2008, 2007 and 2006 was $0.4 million, $2.0 million and $1.8 million, respectively.

Stockholder Rights Plan

We have a stockholder rights plan. The plan is designed to improve the ability of our board to protect the interests of our stockholders in the event of an unsolicited takeover attempt. For every outstanding share of Cimarex common stock, there exists one purchase right (the Right). Each Right represents a right to purchase one one-hundredth of a share of Series A Junior Participating Preferred Stock, at a purchase price of $60.00 per share, subject to adjustment in certain cases, to prevent dilution. The Rights will become exercisable only in the event a person or group acquires beneficial ownership of 15% or more of our common stock, or a person or group commences a tender offer or exchange offer that, if successfully consummated, would result in such person or group beneficially owning 15% or more of our common stock. In general, in either of these events, each holder of a right, other than the person or group initiating the acquisition or tender offer, will have the right to receive Cimarex common stock with a value equal to two times the exercise price of the right.

We generally will be entitled to redeem the Rights under certain circumstances at $0.01 per Right at any time before the close of business on the tenth business day after there has been a public announcement of the acquisition of beneficial ownership by any person or group of 15% or more of our common stock. The Rights may not be exercised until our Board’s right to redeem the stock has expired. Unless redeemed earlier, the Rights expire on February 23, 2012.

Dividends and Stock Repurchases

In December 2005, the Board of Directors declared our first quarterly cash dividend of $0.04 per share. A dividend has been authorized every quarter since then. In December 2007, the dividend was increased to $0.06 per share. Future dividend payments will depend on the Company’s level of earnings, financial requirements and other factors considered relevant by the Board of Directors.

In December 2005, the Board of Directors authorized the repurchase of up to four million shares of our common stock. The authorization is currently set to expire on December 31, 2009. Through December 31, 2007, we had repurchased and cancelled a total of 1,364,300 shares at an overall average price of $39.05. Purchases may be made in both the open market and through negotiated transactions, and purchases may be increased, decreased or discontinued at any time without prior notice. There were no shares repurchased in the fourth quarter of 2008, or since the quarter ended September 30, 2007.

59

CIMAREX ENERGY CO.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Issuer Purchases of Equity Securities for the Quarter Ended December 31, 2008

	Total Number of Shares purchased	Average Price Paid per Share	Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Maximum Number of shares that may yet be Purchased Under the Plans or Programs
October, 2008	None	NA	None	2,635,700
November, 2008	None	NA	None	2,635,700
December, 2008	None	NA	None	2,635,700

A summary of the Company’s Common Stock activity follows:

	Number of Shares (in thousands)
	Issued		Treasury		Outstanding
December 31, 2005	83,524		(1,147	)	82,377
Shares issued under compensation plans, net of cancellations	546		—		546
Option exercises, net of cancellations	142		—		142
Treasury shares purchased	—		(182	)	(182	)
Treasury shares cancelled	(250	)	250		—
December 31, 2006	83,962		(1,079	)	82,883
Shares issued under compensation plans, net of cancellations	511		—		511
Option exercises, net of cancellations	262		—		262
Treasury shares purchased	—		(1,114	)	(1,114	)
Treasury shares cancelled	(1,114	)	1,114		—
December 31, 2007	83,621		(1,079	)	82,542
Shares issued under compensation plans, net of cancellations	441		—		441
Option exercises, net of cancellations	276		—		276
Treasury shares purchased	—		—		—
Treasury shares cancelled	(194	)	194		—
December 31, 2008	84,144		(885	)	83,259

9. EARNINGS (LOSS) PER SHARE

We adopted FASB Staff Position (EITF 03-6-1), Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities, effective January 1, 2009. The Staff Position holds that unvested share-based payment awards that contain non-forfeitable rights to dividends or dividend equivalents are “participating securities” (as defined by EITF 03-6 as securities that may participate in undistributed earnings with common stock, whether that participation is conditioned upon the occurrence of a specified event or not, regardless of the form of participation), and therefore should be included in computing earnings per share using the two-class earnings allocation method. The two-class method is an earnings allocation formula that determines earnings per share for each class of common stock and participating security according to dividends declared (or accumulated) and participation rights in undistributed earnings. Under this staff position, our unvested share based payment awards, consisting of restricted stock and restricted stock units, qualify as participating securities. The requirements of this Staff Position were applied by recasting previously reported earnings per share data.

60

CIMAREX ENERGY CO.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The calculations of basic and diluted net earnings (loss) per common share under the two-class method are presented below (in thousands, except per share data):

	Years Ended December 31,
	2008			2007			2006
Net income (loss)	$	(915,245	)	$	345,262		$	344,481
Less distributed earnings (dividends declared during the period)	(20,108		)	(14,991		)	(13,299		)
Undistributed earnings (loss) for the period	$	(935,353	)	$	330,271		$	331,182
Allocation of undistributed earnings (loss):
Basic allocation to unrestricted common stockholders	$	(935,353	)	$	322,369		$	325,280
Basic allocation to participating securities	$	—	(2)	$	7,902		$	5,902
Diluted allocation to unrestricted common stockholders	$	(935,353	)	$	322,553		$	325,386
Diluted allocation to participating securities	$	—	(2)	$	7,718		$	5,796
Basic Shares Outstanding
Unrestricted outstanding common shares	81,587			81,252			82,091
Add participating securities:
Restricted stock outstanding	1,672			1,290			793
Restricted stock units outstanding	655			702			696
Total participating securities	2,327			1,992			1,489
Total basic shares outstanding	83,914			83,244			83,580
Fully Diluted Shares
Unrestricted outstanding common shares	81,587			81,252			82,091
Incremental shares from assumed exercise of stock options	—		(1)	611			775
Incremental shares from assumed conversion of the convertible senior notes	—		(1)	1,375			750
Fully diluted common stock	81,587			83,238			83,616
Participating securities	2,327		(2)	1,992			1,489
Total Fully Diluted Shares	83,914			85,230			85,105
Basic earnings (loss) per share
Unrestricted common stockholders:
Distributed earnings	$	0.24		$	0.18		$	0.16
Undistributed earnings (loss)	(11.46		)	3.97			3.96
	$	(11.22	)	$	4.15		$	4.12
Participating securities:
Distributed earnings	$	0.24		$	0.18		$	0.16
Undistributed earnings (loss)	—			3.97			3.96
	$	0.24		$	4.15		$	4.12
Fully diluted earnings (loss) per share
Unrestricted common stockholders:
Distributed earnings	$	0.24		$	0.18		$	0.16
Undistributed earnings (loss)	(11.46		)	3.87			3.89
	$	(11.22	)	$	4.05		$	4.05
Participating securities:
Distributed earnings	$	0.24		$	0.18		$	0.16
Undistributed earnings (loss)	—			3.87			3.89
	$	0.24		$	4.05		$	4.05

(1)No potential common shares or securities are included in the diluted share computation when a loss from continuing operations exists.

(2)Participating securities are included in distributed earnings and not in undistributed earnings when a loss from continuing operations exists.

61

CIMAREX ENERGY CO.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

All stock options and restricted units and shares and the convertible notes were considered potentially dilutive securities for each of the periods presented except for those determined to be anti-dilutive as follows:

	2008	2007	2006
Stock options	1,532,016	90,900	43,582
Restricted stock	1,672,245	—	—
Restricted stock units	655,205	—	—
Convertible notes	—	—	—
	3,859,466	90,900	43,582

10. EMPLOYEE BENEFIT PLANS

We maintain and sponsor a contributory 401(k) plan for our employees. Costs related to the plan were $5.2 million, $5.2 million, and $3.2 million in the years ended December 31, 2008, 2007, and 2006, respectively.

11. RELATED PARTY TRANSACTIONS

Helmerich & Payne, Inc. provides contract drilling services to Cimarex. Drilling costs of approximately $40.2 million, $21.5 million, and $20.5 million were incurred by Cimarex related to such services for the years ended December 31, 2008, 2007, and 2006, respectively. At December 31, 2008, we have minimum expenditure commitments of $26.2 million to secure the use of Helmerich & Payne, Inc.’s drilling rigs. We had no such commitments at December 31, 2007 or 2006. Hans Helmerich, a director of Cimarex, is President and Chief Executive Officer of Helmerich & Payne, Inc. Certain subsidiaries of Newpark Resources, Inc. have provided various drilling services to Cimarex. Costs of such services were $24.3 million, $15.6 million, and $19.0 million for the years ended December 31, 2008, 2007, and 2006, respectively. Jerry Box, a director of Cimarex is a director and Chairman of the Board of Newpark Resources, Inc.

12. MAJOR CUSTOMERS

No individual purchasers represented more than 10% of our revenues for the years ended December 31, 2008 and 2007. During 2006, sales to one purchaser represented approximately 11% of our revenues.

13. SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION (in thousands)

	For the Years Ended December 31,
	2008		2007		2006
Cash paid during the period for:
Interest (net of amounts capitalized)	$	8,902	$	19,006	$	5,268
Interest capitalized	$	2,108	$	19,680	$	24,248
Income taxes	$	128,86	$	2,408	$	1,007
Cash received for income taxes	$	4,251	$	46,518	$	37,774

14. COMMITMENTS AND CONTINGENCIES

Shown below are the five year debt maturities and five year lease commitments as of December 31, 2008:

	Payments Due by Period
	Total		Less than 1 Year		1-3 Years		4-5 Years		More than 5 Years
	(In thousands)
Long term debt (face value)	$	589,450	$	220,000	$	—	$	—	$	369,450
Operating leases	$	28,233	$	5,681	$	10,814	$	9,632	$	2,106

62

CIMAREX ENERGY CO.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Litigation

In January 2009, the Tulsa County District Court issued a judgment in the H.B. Krug, et al versus Helmerich & Payne, Inc. (“H&P”) case. This lawsuit was originally filed in 1998 and addressed H&P’s conduct pertaining to a 1989 take-or-pay settlement, along with potential drainage issues and other related matters. Damages of $6.9 million plus $119.5 million for disgorgement of H&P’s estimated potential compounded profit since 1989, resulting from the noted damages, were awarded to plaintiff royalty owners, for a total of $126.4 million. This amount was subsequently adjusted by the court to a total of $119.6 million. Pursuant to the 2002 spin-off transaction to shareholders of H&P by which Cimarex became a publicly-traded entity, Cimarex assumed the assets and liabilities of H&P’s exploration and production business. We periodically assess the probability of estimable amounts related to litigation matters, as required by Financial Accounting Standard No. 5 (Accounting for Contingencies) and adjust our accruals accordingly. In September 2008, based on the available information at the time, we accrued an estimated litigation expense of $12 million for both damages and probable disgorgement. The higher disgorgement award could not be reasonably estimated until the final judgment in January 2009. We therefore accrued an additional $107.6 million, bringing the total accrued litigation expense for the year ended December 31, 2008 to $119.6 million for this lawsuit. We have appealed the District Court’s judgments.

In the normal course of business, we have other various litigation related matters and associated accruals. Though some of the related claims may be significant, the resolution of them we believe, individually or in the aggregate, would not have a material adverse effect on our financial condition or results of operations.

Other

We have a large development project in Sublette County, Wyoming where we are developing the deep Madison gas formation and constructing a gas processing plant. At December 31, 2008, we had commitments of $176.8 million relating to construction of the gas processing plant of which $108.6 million is subject to a construction contract. The total cost of the project will approximate $362 million. Pursuant to the terms of our operating agreement with our partners in this project, we will be reimbursed by them for 421/2% of the costs.

We have drilling commitments of approximately $101.7 million consisting of obligations to complete drilling wells in progress at December 31, 2008. We also have minimum expenditure commitments of $85.7 million to secure the use of drilling rigs. Hurricanes Gustav and Ike occurred during the third quarter of 2008. We are currently evaluating damages to our wells and platforms. It is not presently determinable what our share of the total damages will be after insurance proceeds.

At December 31, 2008, we had outstanding purchase order commitments of $81.9 million for tubular inventory. Subsequent to year-end we have been able to cancel approximately $17.1 million of those commitments, and efforts continue to further reduce our inventory commitments.

At December 31, 2008, we had firm sales contracts to deliver approximately 8.5 Bcf of natural gas over the next twelve months. If this gas is not delivered, our financial commitment would be approximately $40 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.

In connection with a gas gathering and processing agreement, we have commitments to deliver 59.4 Bcf of gas over the next five years. If no gas was delivered, the maximum amount that would be payable under these commitments would be approximately $45.1 million.

We have 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 $5.9 million.

We have non-cancelable operating leases for office and parking space in Denver, Tulsa, Dallas, and for small district and field offices. Rental expense for the operating leases totaled $6.4 million, $5.9 million, and $5.2 million for the years ended December 31, 2008, 2007, and 2006, respectively.

63

CIMAREX ENERGY CO.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

15. PROPERTY SALES

Various interests in oil and gas properties were sold during 2008 and 2007, with net consideration totaling $38.1 million and $176.7 million, respectively. Proceeds from the sales were recorded as a reduction to oil and gas properties, as prescribed under the full cost method of accounting.

In September 2006, our limited partnership affiliates, Teal Hunter L.P. and Mallard Hunter L.P., sold all of their interests in oil and gas properties. Our investments in these partnerships had been reflected in other assets, net. The net consideration received to date via distributions from the partnerships is $62.9 million. Distributions in excess of the carrying amount of our investments of $3 million in 2007 and $19.8 million in 2006 have been recorded in other income.

16. UNAUDITED SUPPLEMENTAL OIL AND GAS DISCLOSURES

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

	Years Ended December 31
	2008			2007		2006
Oil and gas revenues from production	$	1,880,891		$	1,364,622	$	1,215,411
Less operating costs and income taxes:
Impairment of oil and gas properties	2,242,921			—		—
Depletion	527,813			444,546		379,640
Asset retirement obligation	8,796			8,937		7,018
Production	218,736			201,512		176,833
Transportation	38,107			26,361		21,157
Taxes other than income	130,490			93,630		91,066
Income tax expense (benefit)	(475,295		)	214,510		196,935
	2,691,568			989,496		872,649
Results of operations from oil and gas producing activities	$	(810,677	)	$	375,126	$	342,762
Amortization rate per Mcfe	$	2.97		$	2.70	$	2.32

64

CIMAREX ENERGY CO.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Costs Incurred—The following table sets forth the capitalized costs incurred in our oil and gas production, exploration, and development activities (in thousands):

	Years Ended December 31,
	2008			2007			2006
Costs incurred during the year:
Acquisition of properties
Proved	$	6,618		$	17,334		$	25,970
Unproved	310,666			102,572			64,421
Exploration	268,052			236,866			292,336
Development	1,035,442			666,662			691,946
Oil and gas expenditures	1,620,778			1,023,434			1,074,673
Property sales	(38,093		)	(176,659		)	(4,459		)
	1,582,685			846,775			1,070,214
Asset retirement obligation, net	24,822			(18,207		)	20,177
	$	1,607,507		$	828,568		$	1,090,391

Aggregate Capitalized Costs—The table below reflects the aggregate capitalized costs relating to our oil and gas producing activities at December 31, 2008 (in thousands):

Proved properties	$	7,052,464
Unproved properties and properties under development, not being amortized	465,638
	7,518,102
Less-accumulated depreciation, depletion and amortization	(4,709,597		)
Net oil and gas properties	$	2,808,505

Costs Not Being Amortized—The following table summarizes oil and gas property costs not being amortized at December 31, 2008, by year that the costs were incurred (in thousands):

2008	$	425,317
2007	36,855
2006	3,453
2005 and prior	13
	$	465,638

Costs not being amortized include the costs of wells in progress and certain unevaluated properties. On a quarterly basis, such costs are evaluated for inclusion in the costs to be amortized resulting from the determination of proved reserves, impairments, or reductions in value. To the extent that the evaluation indicates these properties are impaired, the amount of the impairment is added to the capitalized costs to be amortized. Abandonments of unproved properties are accounted for as an adjustment to capitalized costs related to proved oil and gas properties, with no losses recognized.

Oil and Gas Reserve Information—Proved oil and gas reserve quantities are based on estimates prepared by Cimarex in accordance with guidelines established by the Securities and Exchange Commission (SEC). DeGolyer and MacNaughton, independent petroleum engineers, reviewed the proved reserve estimates associated with at least 80% of the discounted future net cash flows before income taxes for the years ended December 31, 2008, 2007 and 2006.

Proved reserves are estimated quantities of crude oil, natural gas, and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are those that are expected to be

65

CIMAREX ENERGY CO.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

recovered through existing wells with existing equipment and operating methods. There are numerous uncertainties inherent in estimating quantities of proved reserves and projecting future rates of production and the timing of development expenditures. The following reserve data at December 31, 2008, 2007 and 2006 represents estimates only with relevant prices in effect at year end, and should not be construed as being exact. All of our reserves are located in the continental United States or the Gulf of Mexico.

	December 31, 2008				December 31, 2007				December 31, 2006
	Gas		Oil		Gas		Oil		Gas		Oil
	(MMcf)		(MBbl)		(MMcf)		(MBbl)		(MMcf)		(MBbl)
Total proved reserves
Beginning of year	1,122,694		58,250		1,090,362		59,797		1,004,482		64,710
Revisions of previous estimates	(57,989	)	(16,465	)	50,027		1,251		(14,498	)	(3,684	)
Extensions, discoveries & improved recovery	143,570		11,884		162,136		13,361		170,933		5,018
Purchases of reserves	2,483		55		10,571		99		55,046		551
Production	(127,444	)	(8,395	)	(119,937	)	(7,446	)	(124,733	)	(6,529	)
Sales of properties	(15,981	)	(127	)	(70,465	)	(8,812	)	(868	)	(269	)
End of year	1,067,333		45,202		1,122,694		58,250		1,090,362		59,797
Proved developed reserves	834,517		44,520		848,001		51,497		851,213		50,202

Standardized Measure of Future Net Cash Flows—The “Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves” (Standardized Measure) is a disclosure requirement under FASB Statement No. 69, Disclosures About Oil and Gas Producing Activities. The Standardized Measure does not purport, nor should it be interpreted, to present the fair value of a company’s proved oil and gas reserves. Fair value would require, among other things, consideration of expected future economic and operating conditions, a discount factor more representative of the time value of money, and risks inherent in reserve estimates.

Under the Standardized Measure, future cash inflows are estimated by applying year-end prices to the forecast of future production of year-end proved reserves. Future cash inflows are then reduced by estimated future production and development costs to determine net pre-tax cash flow. Future income taxes are computed by applying the statutory tax rate to the excess of pre-tax cash flow over our tax basis in the associated oil and gas properties. Tax credits and permanent differences are also considered in the future income tax calculation. Future net cash flow after income taxes is discounted using a ten percent annual discount rate to arrive at the Standardized Measure.

The following summary sets forth the Company’s Standardized Measure (in thousands):

	December 31,
	2008			2007			2006
Cash inflows	$	7,314,200		$	12,674,941		$	9,397,265
Production costs	(2,681,510		)	(3,673,259		)	(2,760,771		)
Development costs	(229,546		)	(540,555		)	(581,855		)
Income tax expense	(1,173,658		)	(2,689,836		)	(1,943,773		)
Net cash flow	3,229,486			5,771,291			4,110,866
10% annual discount rate	(1,505,233		)	(2,873,660		)	(1,909,977		)
Standardized measure of discounted future net cash flow	$	1,724,253		$	2,897,631		$	2,200,889

66

CIMAREX ENERGY CO.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The following are the principal sources of change in the Standardized Measure (in thousands):

	December 31,
	2008			2007			2006
Standardized measure, beginning of period	$	2,897,631		$	2,200,889		$	3,028,100
Sales, net of production costs	(1,493,558		)	(1,043,121		)	(929,638		)
Net change in sales prices, net of production costs	(1,683,984		)	976,912			(1,168,787		)
Extensions, discoveries and improved recovery, net of future production and development costs	742,889			858,632			468,854
Net change in future development costs	334,565			136,413			193,280
Revision of quantity estimates	(243,985		)	168,877			(88,023		)
Accretion of discount	424,312			308,660			435,888
Change in income taxes	741,834			(459,777		)	445,073
Purchases of reserves in place	6,956			31,278			64,538
Sales of properties	(29,986		)	(123,268		)	(7,216		)
Change in production rates and other	27,579			(157,864		)	(241,180		)
Standardized measure, end of period	$	1,724,253		$	2,897,631		$	2,200,889

Impact of Pricing—The estimates of cash flows and reserve quantities shown above are based on year-end oil and gas prices, except in those cases where future gas sales are covered by contracts at specified prices. Fluctuations in prices are due to supply and demand and are beyond our control.

The following average prices were used in determining the Standardized Measure as of:

	December 31,
	2008		2007		2006
Price per Mcf	$	5.33	$	6.51	$	5.54
Price per Bbl	$	36.34	$	93.66	$	56.91

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

67

CIMAREX ENERGY CO.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

17. UNAUDITED SUPPLEMENTAL QUARTERLY FINANCIAL DATA

2008	First		Second		Third			Fourth
	(In thousands, except for per share data)
Revenues	$	477,210	$	617,043	$	577,258		$	298,836
Expenses, net	327,672		388,030		809,681			1,360,209
Net income (loss)	$	149,538	$	229,013	$	(232,423	)	$	(1,061,373	)
Earnings (loss) per share to common stockholders:
Basic
Distributed	0.06		$	0.06	$	0.06		$	0.06
Undistributed	1.73		2.67		(2.91		)	(13.07		)
	$	1.79	$	2.73	$	(2.85	)	$	(13.01	)
Diluted
Distributed	$	0.06	$	0.06	$	0.06		$	0.06
Undistributed	$	1.67	2.59		(2.91		)	(13.07		)
	$	1.73	$	2.65	$	(2.85	)	$	(13.01	)
2007	First		Second		Third			Fourth
	(In thousands, except for per share data)
Revenues	$	306,627	$	341,771	$	343,432		$	438,683
Expenses, net	242,304		327,672		327,672			327,672
Net income	$	64,323	$	78,404	$	72,855		$	129,680
Earnings (loss) per share to common stockholders:
Basic
Distributed	$	0.04	$	0.04	$	0.04		$	0.06
Undistributed	0.73		0.90		0.84			1.50
	$	0.77	$	0.94	$	0.88		$	1.56
Diluted
Distributed	$	0.04	$	0.04	$	0.04		$	0.06
Undistributed	0.71		0.88		0.82			1.46
	$	0.75	$	0.92	$	0.86		$	1.52

The sum of the individual quarterly net income per common share amounts may not agree with year-to-date net income per common share.

68