Edgar Filing: Cimarex Energy Co. of Colorado

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Table of contents
Index to financial statements and supplemental schedules

Filed pursuant to Rule 424(b)(5)
Registration Nos. 333-142016
and 333-142168

Prospectus

Cimarex Energy Co.

$350,000,000

7¹/8% Senior Notes due 2017
Interest payable May 1 and November 1

The notes will mature on May 1, 2017. Interest will accrue from May 1, 2007, and the first interest payment will be due November 1, 2007.

We may redeem the notes, in whole or in part, on and after May 1, 2012 at the redemption prices described in this prospectus. In addition, at any time prior to May 1, 2012, we may redeem all, but not part, of the notes at a price equal to 100% of the principal amount plus accrued and unpaid interest plus a "make-whole" premium. Prior to May 1, 2010, we may, at our option, also redeem up to 35% of the notes using the proceeds of certain equity offerings. The redemption provisions are more fully described in this prospectus under "Description of notes—Optional redemption." If we sell certain of our assets or experience specific kinds of change of control, we may be required to offer to purchase the notes.

The notes will be our general unsecured, senior obligations, will be equal in right of payment with any of our existing and future unsecured senior indebtedness that is not by its terms subordinated to the notes, and will be effectively junior to our existing and future secured indebtedness to the extent of collateral securing that debt. The notes will initially be guaranteed on a senior unsecured basis by all of our current and future subsidiaries that guarantee our senior revolving credit facility. The notes will be effectively junior to the indebtedness and other liabilities of any non-guarantor subsidiaries.

Investing in the notes involves risks. See "Risk factors" beginning on page 12.

	Public offering price(1)		Underwriting discounts and commissions		Proceeds to Cimarex Energy Co.


Per note		100.0%		1.5%		98.5%
Total	$	350,000,000	$	5,250,000	$	344,750,000

(1): Plus accrued interest, if any, from May 1, 2007.

The notes will not be listed on any securities exchange. Currently, there is no public market for the notes. Delivery of the notes, in book-entry form, will be made on or about May 1, 2007 through The Depository Trust Company.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or passed on the adequacy or accuracy of this prospectus. Any representation to the contrary is a criminal offense.

Joint book-running managers

JPMorgan

Lehman Brothers

Co-managers

Deutsche Bank Securities				Merrill Lynch & Co.
Calyon Securities (USA)		Raymond James		UBS Investment Bank

April 17, 2007

You should rely only on the information included or incorporated by reference in this prospectus or to which this prospectus refers or that is contained in any free writing prospectus relating to the notes. We have not, and the underwriters have not, authorized any other person to provide you with different information. If anyone else provides you with different or inconsistent information, you should not rely on it.

We and the underwriters are not making an offer to sell the notes in any jurisdiction where the offer or sale is not permitted.

You should assume that the information contained in this prospectus and the documents incorporated by reference is accurate only as of their respective dates. Our business, results of operations, financial condition and prospects may have changed since those dates.

It is expected that delivery of the notes will be made against payment thereof on or about the date specified in the penultimate paragraph of the cover page hereof, which will be the tenth business day in the United States following the date hereof. Pursuant to Rule 15c6-1 under the Securities Exchange Act of 1934, or the "Exchange Act," trades in the secondary market generally are required to settle in three business days, unless the parties to any such trade expressly agree otherwise. Accordingly, purchasers who wish to trade notes on the date of pricing or the next six succeeding business days will be required to specify an alternative settlement cycle at the time of any such trade to prevent a failed settlement. Purchasers of notes who wish to trade notes on the date of pricing or the next six succeeding business days should consult their own advisors.

Table of contents



Glossary of oil and gas terms
Summary
Risk factors
Disclosure regarding forward-looking statements
Use of proceeds
Capitalization
Ratio of earnings to fixed charges
Selected historical consolidated financial data
Management's discussion and analysis of financial condition and results of operations
Business
Management
Stock ownership of directors, management and certain beneficial owners
Transactions with related persons
Description of other indebtedness
Description of notes
United States federal income and estate tax considerations
Underwriting
Legal matters
Experts
Where you can find more information
Incorporation by reference
Index to financial statements and supplemental schedules

Glossary of oil and gas terms

In this prospectus, the following terms have the meanings specified below.


Bbl/d		Barrels (of oil) per day
Bbls		Barrels (of oil)
Bcf		Billion cubic feet
Bcfe		Billion cubic feet equivalent
MBbls		Thousand barrels
Mcf		Thousand cubic feet (of natural gas)
Mcfe		Thousand cubic feet equivalent
MMBbls		Million barrels
MMBtu		Million British Thermal Units
MMcf		Million cubic feet
MMcf/d		Million cubic feet per day
MMcfe		Million cubic feet equivalent
MMcfe/d		Million cubic feet equivalent per day
Net acres		Gross acreage multiplied by working interest percentage
Net production		Gross production multiplied by net revenue interest
NGL		Natural gas liquids
Tcf		Trillion cubic feet
Tcfe		Trillion cubic feet equivalent

One barrel of oil is the energy equivalent of six Mcf of natural gas.

Summary

This summary highlights selected information contained elsewhere in this prospectus and in the documents we incorporate by reference. This summary is not complete and does not contain all of the information that you should consider before deciding whether or not to invest in the notes. For a more complete understanding of our company and this offering, we encourage you to read this entire document, including "Risk factors," the financial and other information included and incorporated by reference in this prospectus and the other documents to which we have referred you. Unless otherwise indicated or required by the context, as used in this prospectus, the terms "the Company," "we," "our" and "us" refer to Cimarex Energy Co. and its subsidiaries. The term "Magnum Hunter" refers to Magnum Hunter Resources, Inc., which we acquired on June 7, 2005. Some of the oil and gas terms we use are defined under "Glossary of oil and gas terms" on page ii. Our fiscal year ends on December 31 of each year.

Our company

We are an independent oil and gas exploration and production company. Our core areas of operation are in the Mid-Continent, Permian Basin and onshore Gulf Coast regions of the United States. We also have a small presence in the Gulf of Mexico and are expanding our operations in Wyoming. As of December 31, 2006, our estimated proved reserves were 1,449 Bcfe, of which 80% were proved developed and 75% were gas. During 2006, our net production averaged 449 MMcfe per day, which implies a reserve life of approximately 8.8 years. For the year ended December 31, 2006, we generated revenues and EBITDA of $1,267 million and $943 million, respectively. See "—Summary historical consolidated financial data" for a reconciliation of EBITDA to net income.

On June 7, 2005, we acquired Magnum Hunter Resources, Inc., which significantly increased our presence in the Permian Basin and enhanced our Mid-Continent operations in the Texas Panhandle. Magnum Hunter also had a small presence in the Gulf of Mexico and a large acreage position in several western states. The acquisition increased our proved reserves by 887 Bcfe (60% gas and 73% proved developed), which effectively tripled our proved reserves and doubled our production.

The following table summarizes our estimated proved oil and gas reserves by region as of December 31, 2006 and our average daily production by region for 2006.

					2006 average daily production

				Percent of proved reserves	2006 average daily production
	Oil (MBbl)	Gas (MMcf)	Equivalent (MMcfe)	Percent of proved reserves	Oil (MBbl/d)	Gas (MMcf/d)	Total (MMcfe/d)

Mid-Continent	8,709	542,447	594,701	41%	4.7	152.5	180.7
Permian Basin	44,351	296,969	563,076	39%	8.1	83.8	132.4
Gulf Coast	4,671	76,640	104,663	7%	3.2	61.8	80.7
Gulf of Mexico	964	38,111	43,895	3%	1.6	36.2	45.9
Western/Other	1,102	136,195	142,811	10%	0.3	7.4	9.4

	59,797	1,090,362	1,449,146	100%	17.9	341.7	449.1

Business strengths

Solid base of onshore proved reserves and production. At year-end 2006, we had nearly 1.45 Tcfe of proved oil and gas reserves, 80% of which were classified as proved developed. Approximately 80% of our total proved reserves are concentrated in the Mid-Continent and Permian Basin regions. Wells in these areas generally have stable production, reliable reserve estimates and low production decline rates. The Mid-Continent and Permian Basin regions also accounted for 70% of our total 2006 production.

Blended portfolio of low-risk development and potentially high-return exploration projects. We maintain a geographically and geologically diverse portfolio of low-to-moderate risk development and higher risk exploration projects. The low-risk, repeatable results we achieve in our Mid-Continent and Permian Basin regions provide moderate and predictable production and reserve growth. Our higher-risk drilling locations along the Gulf Coast and in the Gulf of Mexico are characterized by higher reserves per well and potentially higher economic returns. We believe that this blend of low-risk Mid-Continent and Permian Basin drilling combined with higher-potential Gulf Coast exploration allows us to achieve consistent, profitable results while also enabling us to pursue larger growth opportunities.

Large undeveloped acreage position with an active drilling program. As of December 31, 2006, we owned leases covering more than 4.4 million net acres, of which 80% were undeveloped. In 2006, we drilled more than 550 gross wells completing 91% as producers. More than 80% of this drilling occurred in the Mid-Continent and Permian Basin, where we achieved drilling success rates of 97% and 96%, respectively. Our technical teams and operating managers continue to generate projects on our existing acreage inventory and also seek to identify new areas for exploration and development.

Proven track record of reserve and production growth. We have increased our proved reserves and production each year since 2002 at average annual growth rates of 37% and 36%, respectively. We have achieved these results from a combination of organic growth through drilling and opportunistic mergers that have enhanced our competitive position.

Experienced management and operational teams. Our financial and operations executives, led by F.H. Merelli, each have over 25 years of experience in the oil and gas industry. Mr. Merelli has over 47 years of oil and gas industry experience. Our executive management team is supported by technical and operating managers who also have substantial industry experience and expertise within the basins in which we operate.

Business strategy

Consistently grow proved reserves and production. We seek to reinvest the cash flow generated by our producing properties into drilling new wells that have the potential to profitably grow our production and proved reserves. From time to time, we also consider supplementing our drill-bit driven growth through selective mergers and acquisitions.

Focus on blended portfolio. We seek to maintain a diverse portfolio of prospects that is underpinned by approximately 70%-80% low-to-moderate risk projects combined with a smaller percentage of higher risk/higher potential prospects. Our objective is to achieve consistent, profitable growth, while still preserving opportunities for potentially meaningful

new discoveries. We also seek to maintain geographic diversification so as to mitigate certain operational and market risks and to position us to benefit from emerging plays.

Employ a disciplined approach to capital investment decision making. Each drilling decision is based on a detailed evaluation of its risk-adjusted, discounted cash flow rate of return on investment. Our comprehensive analysis includes estimates and assessments of potential reserve size, geologic and mechanical risks, expected costs and future production profiles. Our integrated teams of geoscientists, landmen and petroleum engineers seek to continually generate new prospects to maintain a rolling inventory of drilling opportunities. We have a centralized management system that measures actual results and provides feedback to the originating teams in order to help them improve and refine future investment decisions.

Control our drilling inventory. We will continue to seek to exercise control over the majority of our properties and investment decisions. At December 31, 2006, we operated the wells that accounted for approximately 73% of our total proved reserves and approximately 70% of our production. We believe our ability to control our drilling inventory will allow us to more effectively control operating costs, timing of development activities and technological enhancements, marketing of production and allocation of our capital budget.

Maintain financial flexibility and a conservative capital structure. We believe that maintaining a conservative capital structure will provide us with the flexibility needed to capitalize on future growth opportunities, while limiting our financial risk. We have historically used leverage conservatively, funding our development and growth activity through a combination of internally generated cash flow, bank borrowings and stock-for-stock mergers. Prior to our 2005 acquisition of Magnum Hunter and the assumption of its debt, we had no debt outstanding at year-end 2003 and 2004, and our 2006 year-end debt-to-capitalization ratio was 13%. Based on expected cash flow provided by operating activities and available liquidity under our senior revolving credit facility, we believe we are well positioned to fund our identified drilling opportunities for the foreseeable future.

Corporate information

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. Our website address is www.cimarex.com. The information on our website is not incorporated into this prospectus, and you should rely only on the information contained in this prospectus and in the documents we incorporate by reference when making a decision whether to invest in the notes.

The offering

The following summary contains basic information about the notes and is not intended to be complete. For a more complete understanding of the notes, please refer to the section entitled "Description of notes" in this prospectus. For purposes of the description of notes included in this prospectus, references to "the Company," "issuer," "us," "we" and "our" refer only to Cimarex Energy Co. and do not include our subsidiaries.

Issuer		Cimarex Energy Co.
Securities offered		$350,000,000 aggregate principal amount of 7¹/8% Senior Notes due 2017.
Maturity		May 1, 2017.
Interest payment dates		Interest is payable on the notes on May 1 and November 1 of each year, commencing November 1, 2007. Interest will accrue from May 1, 2007.
Optional redemption		The notes will be redeemable at our option, in whole or in part, at any time on and after May 1, 2012 at the redemption prices described in this prospectus, together with accrued and unpaid interest, if any, to the date of redemption.
		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 equal to 100% of the principal amount of the notes plus accrued and unpaid interest plus a "make-whole" premium.
Mandatory offers to repurchase		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. See "Description of notes—Change of control."
		Certain asset dispositions will be triggering events that may require us to use the net proceeds from those asset dispositions to make an offer to purchase the notes at 100% of their principal amount, together with accrued and unpaid interest, if any, to the date of purchase if such proceeds are not otherwise used within 365 days to repay indebtedness (with a corresponding permanent reduction in commitment, if applicable) or to invest in capital assets related to our business or capital stock of a restricted subsidiary (as defined under the heading "Description of notes"). See "Description of notes—Covenants—Limitation on sales of assets and subsidiary stock."

Ranking	The notes will be our unsecured senior obligations and will rank:
	•	equal in right of payment to all of our existing and future senior indebtedness including our senior revolving credit facility without giving effect to collateral arrangements;
	•	senior in right of payment with any of our existing and future senior subordinated indebtedness; and
	•	senior in right of payment to any of our existing and future subordinated obligations.
	As of December 31, 2006, after giving pro forma effect to this offering and the application of the net proceeds from this offering, as more fully described in "Use of proceeds":
	•	we would have had approximately $487.9 million of total indebtedness (including the notes), all of which would have ranked equally in right of payment with the notes;
	•	we would have had no secured indebtedness under our senior revolving credit facility excluding $5.0 million represented by letters of credit under the senior revolving credit facility, to which the notes would have been effectively subordinated, and would have had additional commitments under our senior revolving credit facility available to us of $495.0 million, all of which would be secured if borrowed; and
	•	our non-guarantor subsidiaries would not have had any obligations or liabilities (other than inter-company obligations).
Subsidiary guarantees	The notes will be guaranteed on a senior basis by all of our current and future subsidiaries that guarantee our obligations under our senior revolving credit facility. The guarantees will be released when the guarantees of our indebtedness, including indebtedness under our senior revolving credit facility, and the guarantees of indebtedness of our restricted subsidiaries are released.
	The guarantees will be unsecured senior indebtedness of our subsidiary guarantors and will rank:
	•	equal in right of payment to all of the subsidiary guarantors' existing and future senior indebtedness;
	•	senior in right of payment with any of the subsidiary guarantors' existing and future senior subordinated indebtedness; and
	•	senior in right of payment to any of the subsidiary guarantors' existing and future subordinated obligations.
	For the twelve months ended December 31, 2006, on a pro forma basis, our non-guarantor subsidiaries had no net sales, operating income, EBITDA, and cash flows from operating activities.

Covenants	We will issue the notes under an indenture with U.S. Bank National Association, as trustee. The indenture will, among other things, limit our ability and the ability of our restricted subsidiaries to:
	•	incur, assume or guarantee additional indebtedness;
	•	issue redeemable stock and preferred stock;
	•	pay dividends or distributions or redeem or repurchase capital stock;
	•	prepay, redeem or repurchase debt that is junior in right of payment to the notes;
	•	make loans, investments and capital expenditures;
	•	incur liens;
	•	engage in sale/leaseback transactions;
	•	restrict dividends, loans or asset transfers from our subsidiaries;
	•	sell or otherwise dispose of assets, including capital stock of subsidiaries;
	•	consolidate or merge with or into, or sell substantially all of our assets to, another person;
	•	enter into transactions with affiliates; and
	•	enter into new lines of business.
	These covenants are subject to important exceptions and qualifications, which are described under the caption "Description of notes—Certain covenants." In addition, if and for as long as the notes have an investment grade rating from both Standard & Poor's Ratings Group, Inc. and Moody's Investors Service, Inc., and no default exists under the indenture, we will not be subject to certain of the covenants listed above.
Use of proceeds	We intend to use approximately $204 million of the net proceeds from this offering to redeem the outstanding 9.6% senior notes due 2012 assumed in the acquisition of Magnum Hunter. Certain of the underwriters and their affiliates are lenders to us under our senior revolving credit facility. We intend to use the remainder of the proceeds to reduce outstanding borrowings under our senior revolving credit facility. See "Use of proceeds."

Risk factors

Investing in the notes involves substantial risk. You should carefully consider the risk factors set forth under "Risk factors" and the other information contained and incorporated in this prospectus prior to making an investment in the notes. See "Risk factors" beginning on page 12.

Summary historical consolidated financial data

The following table shows our summary consolidated historical financial data as of and for the periods indicated. Our summary historical financial data as of and for the fiscal years ended December 31, 2006, 2005 and 2004 have been derived from our audited financial statements. Certain historical amounts have been reclassified to conform to the current presentation.

You should read the summary consolidated historical financial data below in conjunction with our consolidated financial statements and the accompanying notes which are contained elsewhere in this prospectus. You should also read the sections entitled "Selected historical consolidated financial information" and "Management's discussion and analysis of financial condition and results of operations."

		Year ended December 31,

(Dollars in thousands)		2006			2005			2004

Statement of operations data:
Revenues:
	Gas sales	$	810,894		$	807,007		$	366,260
	Oil sales		404,517			265,415			106,129
	Gas gathering and processing		47,879			44,238			101
	Gas marketing, net of related costs		3,854			1,962			2,674

Total revenues		$	1,267,144		$	1,118,622		$	475,164
Expenses:
	Depreciation, depletion and amortization	$	396,394		$	258,287		$	124,251
	Asset retirement obligation accretion		7,018			3,819			1,241
	Production		176,833			104,067			37,476
	Transportation		21,157			15,338			10,003
	Gas gathering and processing		27,410			31,890			284
	Taxes other than income		91,066			73,360			37,761
	General and administrative		42,288			33,497			22,483
	Stock compensation		8,243			4,959			1,957
	(Gain)/Loss on derivative instruments		(22,970	)		67,800			—
	Other operating, net		2,064			15,897			(3,394	)

Total expenses		$	749,503		$	608,914		$	232,062

Income from operations		$	517,641		$	509,708		$	243,102
Interest expense net of capitalized interest			5,692			7,921			1,075
Amortization of fair value of debt			(3,784	)		(2,132	)		—
Other, net			(28,591	)		(12,536	)		(4,291	)

Income before income tax expense		$	544,324		$	516,455		$	246,318
Income tax expense			198,605			188,130			92,726

Net income		$	345,719		$	328,325		$	153,592

Balance sheet data (as of period end):
Cash and cash equivalents		$	5,048		$	61,647		$	115,746
Net oil and gas properties			3,587,710			2,876,959			802,293
Total assets			4,829,750			4,180,335			1,105,446
Total debt			443,667			352,451			—
Stockholders' equity			2,976,143			2,595,453			700,712
Cash flows data:
Net cash flow provided by (used in):
	Operating activities	$	878,419		$	704,734		$	355,853
	Investing activities		(1,009,802	)		(497,453	)		(293,101	)
	Financing activities		74,784			(261,380	)		12,574
Other financial data:
EBITDA(1)		$	942,626		$	780,531		$	371,644
Total interest(2)			29,940			19,607			1,075
Oil and gas expenditures(3)			1,030,791			631,549			281,407
Ratio of total debt to EBITDA			0.5x			0.5x			—
Ratio of EBITDA to total interest(4)			31.5x			39.8x			345.7x
Ratio of earnings to fixed charges(5)			19.8x			27.2x			130.6x

(1): EBITDA represents net earnings before income taxes, interest expense and depreciation, depletion and amortization. EBITDA is not a measure calculated in accordance with generally accepted accounting principles (GAAP). EBITDA should not be considered as an alternative to net income, income before taxes, net cash flow from operating activities or any other measure of financial performance presented in accordance with GAAP. We believe that EBITDA is a widely accepted financial indicator of a company's ability to incur and service debt and to fund capital expenditures. Because EBITDA is commonly used in the oil and gas industry, we believe it is useful in evaluating our ability to meet our interest obligations in connection with this offering. EBITDA calculations may vary among entities, so our computation of EBITDA may not be comparable to EBITDA or similar measures of other entities. In evaluating EBITDA, we believe that investors should consider, among other things, the amount by which EBITDA exceeds interest costs, how EBITDA compares to principal payments on debt and how EBITDA compares to capital expenditures for each period.

The following table provides a reconciliation of net income to EBITDA:

	Year ended December 31,

(in thousands)	2006			2005			2004

Net income	$	345,719		$	328,325		$	153,592
Income tax expense		198,605			188,130			92,726
Interest expense		5,692			7,921			1,075
Amortization of fair value of debt		(3,784	)		(2,132	)		—
Depreciation, depletion and amortization		396,394			258,287			124,251

EBITDA	$	942,626		$	780,531		$	371,644

(2): Includes capitalized interest of $24,248, $11,686 and $0 for the years ended December 31, 2006, 2005 and 2004, respectively.
(3): From Statements of Cash Flows.
(4): Represents EBITDA divided by total interest. The ratio of net income to total interest for the years ended December 31, 2006, 2005 and 2004 were 11.5x, 16.7x and 142.9x, respectively.
(5): The ratio of earnings to fixed charges was computed by dividing earnings by fixed charges. Earnings consist of income from continuing operations before income taxes and cumulative change in accounting principle plus distributions received from equity investments, and fixed charges, minus income from equity investees and capitalized interest. Fixed charges consist of interest expensed, which includes amortization of the premium of fair market value over the face value of debt, an estimated interest component in net rental expense, and interest capitalized.

Summary reserve, production and operating data

Our engineers estimate our proved oil and gas reserve quantities in accordance with guidelines established by the SEC. DeGolyer and MacNaughton, independent petroleum engineers, reviewed the proved reserve estimates associated with at least 80 percent of the discounted future net cash flows before income taxes for the year ended December 31, 2006. Ryder Scott Company, L.P., independent petroleum engineers, and DeGolyer and MacNaughton collectively reviewed the proved reserve estimates associated with at least 80 percent of the discounted future net cash flows before income taxes for the year ended December 31, 2005. Ryder Scott Company, L.P. reviewed the proved reserve estimates associated with at least 80 percent of the discounted future net cash flows before income taxes for the year ended December 31, 2004. All information in this prospectus relating to oil and gas reserves is net to our interest unless stated otherwise. The following table sets forth the present value and estimated volume of our oil and gas proved reserves:

		As of December 31,

		2006		2005		2004

Total proved reserves:
Gas (MMcf)			1,090,362		1,004,482		364,641
Oil, condensate and NGLs (MBbls)			59,797		64,710		14,063
	Equivalent (MMcfe)		1,449,146		1,392,742		449,020
	% gas		75%		72%		81%
	% proved developed		80%		81%		99%
Standardized measure of discounted future net cash flows relating to proved oil and gas reserves (in thousands)		$	2,200,889	$	3,028,100	$	798,033
Average price used in calculation of future net cash flow:
	Gas ($/Mcf)	$	5.54	$	7.89	$	5.58
	Oil ($/Bbl)	$	56.91	$	57.65	$	40.76

The following table sets forth certain information regarding our production volumes and the average oil and gas prices received and operating expenses per Mcfe of production:

		Years ending December 31,

		2006		2005		2004

Production volumes:
Gas (MMcf)			124,733		100,272		63,611
Oil (MBbls)			6,529		4,804		2,641
	Equivalent (MMcfe)		163,907		129,096		79,457
Average sales price(1):
Gas ($/Mcf)		$	6.50	$	8.05	$	5.76
Oil ($/Bbl)		$	61.96	$	55.25	$	40.19
Operating expenses per Mcfe:
Production		$	1.08	$	0.81	$	0.47
Transportation			0.13		0.12		0.13
Gas gathering and processing			0.17		0.25		—
Taxes other than income			0.56		0.57		0.48
DD&A			2.42		2.00		1.56
G&A			0.26		0.26		0.28
Interest expense net of capitalized interest			0.03		0.06		0.01

	Total	$	4.65	$	4.07	$	2.93

(1): We assumed Magnum Hunter's oil and gas commodity swap and collar contracts as part of the merger. These instruments did not qualify for hedge accounting treatment and, as such, they are not included in the above average sales prices.

The following table summarizes daily production by region for 2006 and the second-half of 2005. The second-half 2005 volumes reflect the production increases as a result of the Magnum Hunter acquisition.

		Average daily production

		Year ended 2006 (MMcfe/d)	Second-half 2005 (MMcfe/d)

Mid-Continent		180.7	175.3
Permian Basin		132.4	130.1
Gulf Coast		80.7	84.4
Gulf of Mexico		45.9	37.9
Other		9.4	10.5

	Total	449.1	438.2

Risk factors

You should carefully consider the risks described below before making an investment decision. The risks and uncertainties described below are not the only ones we face. Additional risks and uncertainties not presently known to us or that we currently deem immaterial may also impair our business operations. If any of the following risks actually occurs, our business, financial condition or results of operations could be materially adversely affected.

This prospectus and the documents incorporated by reference also contain forward-looking statements that involve risks and uncertainties. Our actual results could differ materially from those anticipated in the forward-looking statements as a result of a number of factors, including the risks described below and elsewhere in this prospectus.

Risks relating to our business

Low oil and gas prices could adversely affect our financial results and future rate of growth in proved reserves and production.

Our revenues and results of operations are highly dependent on oil and gas prices. The prices we receive for our production are based on prevailing market conditions and are influenced by many factors that are beyond our control. Historically, oil and gas prices have fluctuated widely. For example, in 2006 we sold our gas at an average price of $6.50 per Mcf, which was 19 percent lower than our 2005 average sales price of $8.05 per Mcf. Conversely, our average 2006 oil price of $61.96 per barrel was 12 percent higher than the price we received in 2005 of $55.25 per barrel.

In recent years, oil prices have responded to changes in supply and demand stemming from actions taken by the Organization of Petroleum Exporting Countries, worldwide economic conditions, growing transportation and power generation needs, and other events. Factors affecting gas prices have included domestic supplies; the level and price of natural gas imports into the U.S.; weather conditions; the economy and the price and level of alternative sources of energy such as nuclear power, hydroelectric power, coal, and other petroleum products.

Our proved oil and gas reserves and production volumes will 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. Because low oil and gas prices would negatively affect the amount of cash flow available to fund these capital investments, they could also affect our future rate of growth. Low prices may 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. We may be required under accounting rules to write down the carrying value of our properties or impair goodwill when gas and oil prices are low. 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.

Our use of hedging arrangements could result in financial losses or reduce our income.

To reduce our exposure to fluctuations in natural gas prices, we have entered into hedging arrangements for a portion of our natural gas production. These hedging arrangements expose us to risk of financial loss in some circumstances, including when:

•: production is less than expected;
•: the counterparty to the hedging contract defaults on its contract obligations; or
•: there is a change in the expected differential between the underlying price in the hedging agreement and actual prices received.

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 levels of initial production. Production from these wells declines and stabilizes 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 and reduce our ability to raise capital.

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.

We often are uncertain as to the future cost or timing of drilling, completing and producing wells. 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 us 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 proved oil and gas reserves and their associated future net cash flow necessarily 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;
•: 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.

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, 2006.

The values referred to in this prospectus 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.

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 unavailability of or 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.

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 30 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 operations.

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 45 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. 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 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.

Risks relating to our indebtedness and the notes

The level of our indebtedness could adversely affect our financial condition and prevent us from fulfilling our obligations on the notes.

At December 31, 2006, after giving pro forma effect to this offering and the application of the net proceeds from the sale of the notes as set forth under "Use of proceeds," we would have had total consolidated debt of $487.9 million, plus $355 million in current liabilities. Subject to the limits contained in the agreements governing our senior revolving credit facility, we would have been able to incur up to $1 billion of debt as of December 31, 2006, only $500 million of which is currently committed. We have demands on our cash resources in addition to interest expense and principal on the notes, including, among others, operating expenses, capital expenditures and interest and principal payments under our senior revolving credit facility and our floating rate convertible senior notes due 2023. Our level of indebtedness could have important effects on our business and on your investment in the notes, including:

•: making it more difficult for us to satisfy our obligations with respect to the notes and our other debt;
•: requiring us to dedicate a substantial portion of our cash flow from operations to payments on our debt, thereby reducing the amount of our cash flow available for working capital, capital expenditures, acquisitions and other general corporate purposes;
•: limiting our flexibility in planning for, or reacting to, changes in the oil and gas industry;
•: placing us at a competitive disadvantage compared to our competitors that have lower debt service obligations and significantly greater operating and financing flexibility than we do;
•: limiting our financial flexibility, including our ability to borrow additional funds;
•: increasing our interest expense if interest rates increase, because approximately $125 million of our borrowings as of December 31, 2006, pro forma for this offering, are at variable rates of interest;
•: increasing our vulnerability to general adverse economic and industry conditions; and
•: resulting in an event of default upon a failure to comply with financial covenants contained in our senior revolving credit facility which, if not cured or waived, could have a material adverse effect on our business, financial condition or results of operations.

We may not be able to generate enough cash flow to meet our debt obligations, including the notes.

Our ability to pay the principal and interest on our long-term debt, including the notes, 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 markets 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 borrowings under our existing senior revolving credit facility bear interest at floating rates. See "Capitalization."

We also have outstanding $125 million of convertible notes (face value) that mature on December 15, 2023, and that are currently convertible into a combination of cash and our common stock. If the holders of our convertible notes choose to convert them, we might be required to borrow additional funds under our senior revolving credit facility in order to repay the required cash amount.

Our business may not generate sufficient cash flow from operations. Future sources of capital may not be available to us in an amount sufficient to enable us to service our indebtedness, including the notes, 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 and our ability to satisfy our obligations under the notes.

Our senior revolving credit facility restricts and the indenture will restrict us from engaging in some business activities.

The credit agreement governing our senior revolving credit facility restricts and the indenture governing the notes will restrict our ability to, among other things:

•: incur additional debt and guarantees;
•: pay dividends on or redeem or repurchase capital stock;
•: make certain investments;
•: incur or permit to exist certain liens;
•: enter into transactions with affiliates;
•: merge, consolidate or amalgamate with another company; and
•: transfer or otherwise dispose of assets, including capital stock of subsidiaries.

The credit agreement for our senior revolving credit facility contains both financial and non-financial covenants, including limitations on share repurchases, dividends and other restricted payments. The financial covenants require us to maintain a minimum ratio of funded indebtedness to trailing twelve-month EBITDA (earnings before interest, taxes and depreciation, depletion and amortization (DD&A) adjusted for non-cash items associated with mark-to-market accounting, stock-based compensation and impairment of goodwill) of less than three times and a ratio of current assets plus unused commitments for borrowing to current liabilities of greater than one. Our ability to meet these covenants or requirements may

be affected by events beyond our control, and we may be unable to satisfy such covenants and requirements.

The covenants contained in the agreements governing our debt may affect our flexibility in planning for, and reacting to, changes in business conditions. In addition, a breach of the restrictive covenants in our credit agreement, the indenture or any instrument governing future indebtedness or our inability to maintain the financial ratios described above could result in an event of default under the applicable instrument or inability to borrow additional funds. Upon the occurrence of such an event of default, the applicable creditors could, subject to the terms and conditions of the applicable instrument, elect to declare the outstanding principal of that debt, together with accrued interest, to be immediately due and payable. Moreover, any of our other debt agreements that contain a cross-default or cross-acceleration provision that would be triggered by such default or acceleration would also be subject to acceleration upon the occurrence of such default or acceleration. The accelerated debt would become immediately due and payable. If that should occur, we may not be able to make all of the required payments or borrow sufficient funds to refinance it. Even if new financing were then available, it may not be on terms that are acceptable to us. See "Description of other indebtedness" and "Description of notes—Events of default." If we were unable to repay amounts due under our senior revolving credit facility, the lenders could proceed against the collateral granted to them to secure such indebtedness. If the payment of our indebtedness is accelerated, our assets may not be sufficient to repay in full that indebtedness and our other indebtedness that would become due as a result of any acceleration. The above restrictions could limit our ability to obtain future financing and may prevent us from taking advantage of attractive business opportunities.

The notes and the guarantees will be unsecured and effectively subordinated to our and our subsidiary guarantors' existing and future secured indebtedness and other liabilities of our non-guarantor subsidiaries.

The notes will be our general unsecured obligations and will be effectively subordinated to claims of our secured creditors and the subsidiary guarantees will be effectively subordinated to the claims of our secured creditors as well as the secured creditors of our subsidiary guarantors. Holders of our secured obligations, including obligations under our existing senior revolving credit facility, will have claims that are prior to claims of the holders of the notes with respect to the assets securing those obligations. In the event of a liquidation, dissolution, reorganization, bankruptcy or any similar proceeding, our assets and those of our current subsidiaries will be available to pay obligations on the notes and the guarantees only after holders of our senior secured debt have been paid the value of the assets securing such debt. At December 31, 2006, after giving pro forma effect to this offering and the application of the net proceeds from the sale of the notes as set forth under "Use of proceeds," we would not have had any secured indebtedness, and approximately $495.0 million would have been available for additional borrowing under our senior revolving credit facility, all of which would rank senior to your claims as holders of the notes.

Although all of our current and future subsidiaries that guarantee our senior revolving credit facility will initially provide guarantees of the notes, under certain circumstances, the guarantees are subject to release. In that case, the notes would be effectively subordinated to the claims of all creditors, including trade creditors and tort claimants, of our subsidiaries that are not guarantors. In the event of the liquidation, dissolution, reorganization, bankruptcy or

similar proceeding of the business of a subsidiary that is not a guarantor, creditors of that subsidiary would generally have the right to be paid in full before any distribution is made to us or the holders of the notes. Accordingly, there may not be sufficient funds remaining to pay amounts due on all or any of the notes.

We may be able to incur substantially more debt, which could increase the risks associated with our indebtedness.

We and our subsidiaries may be able to incur substantial additional indebtedness in the future. The terms of our new indenture do not prohibit us or our subsidiaries from doing so. As of December 31, 2006, on a pro forma basis after giving effect to this offering and the application of the net proceeds from the sale of the notes as set forth under "Use of proceeds," our senior revolving credit facility provided commitments of up to $500 million, of which no borrowings were outstanding, approximately $5.0 million of letters of credit were outstanding and approximately $495.0 million was immediately available for future borrowings. These borrowings would be secured, and as a result, effectively senior to the notes and the guarantees of the notes by our subsidiary guarantors, to the extent of the value of the collateral securing that indebtedness. In addition, our senior revolving credit facility and the indenture governing the notes would permit us to borrow up to $1 billion of debt, only $500 million of which is currently committed. If we incur any additional indebtedness that ranks equally with the notes, the holders of that debt will be entitled to share ratably with the holders of these notes in any proceeds distributed in connection with any insolvency, liquidation, reorganization, dissolution or other winding-up of us. This may have the effect of reducing the amount of proceeds paid to you.

If new debt is added to our current debt levels, the related risks that we and our subsidiaries now face could intensify. At December 31, 2006, on a pro forma basis after giving effect to this offering, and the application of the net proceeds from the sale of the notes as set forth under "Use of proceeds," we would have had total consolidated long-term debt of approximately $487.9 million, excluding approximately $5.0 million in outstanding letters of credit. Our level of indebtedness may prevent us from engaging in certain transactions that might otherwise be beneficial to us by limiting our ability to obtain additional financing, limiting our flexibility in operating our business or otherwise. In addition, we could be at a competitive disadvantage against other less leveraged competitors that have more cash flow to devote to their business. Any of these factors could result in a material adverse effect on our business, financial condition, results of operations, business prospects and ability to satisfy our obligations under the notes.

If we undergo a change of control, we may not have the ability to raise the funds necessary to finance the change of control offer required by the indenture governing the notes, which would violate the terms of the notes.

Upon the occurrence of a change of control, holders of the notes will have the right to require us to purchase all or any part of such holders' notes at a price equal to 101% of the principal amount thereof, plus accrued and unpaid interest, if any, to the date of purchase. A change of control also would constitute a default under our senior revolving credit facility, which would allow the lenders to require us to repay our indebtedness under the senior revolving credit facility in full. We and our subsidiary guarantors may not have sufficient financial resources available to satisfy all of our or their obligations under our senior revolving credit facility and

the notes in the event of a change in control, or our senior revolving credit facility or other future debt agreements may prohibit us from fulfilling our repurchase obligations. Our failure to purchase the notes as required under the indenture governing the notes would result in a default under the indenture and under our senior revolving credit facility, each of which could have material adverse consequences for us and the holders of the notes. See "Description of notes—Change of control."

A subsidiary guarantee could be voided if it constitutes a fraudulent transfer under U.S. bankruptcy or similar state law, which would prevent the holders of the notes from relying on that subsidiary to satisfy claims.

Under U.S. bankruptcy law and comparable provisions of state fraudulent transfer laws, a guarantee can be voided, or claims under the guarantee may be subordinated to all other debts of that guarantor if, among other things, the guarantor, at the time it incurred the indebtedness evidenced by its guarantee or, in some states, when payments become due under the guarantee, received less than reasonably equivalent value or fair consideration for the incurrence of the guarantee and:

•: was insolvent or rendered insolvent by reason of such incurrence;
•: was engaged in a business or transaction for which the guarantor's remaining assets constituted unreasonably small capital; or
•: intended to incur, or believed that it would incur, debts beyond its ability to pay those debts as they mature.

A guarantee may also be voided, without regard to the above factors, if a court found that the guarantor entered into the guarantee with the actual intent to hinder, delay or defraud its creditors. A court would likely find that a guarantor did not receive reasonably equivalent value or fair consideration for its guarantee if the guarantor did not substantially benefit directly or indirectly from the issuance of the notes. If a court were to void a guarantee, you would no longer have a claim against the guarantor. Sufficient funds to repay the notes may not be available from other sources, including the remaining guarantors, if any. In addition, the court might direct you to repay any amounts that you already received from the subsidiary guarantor.

The measures of insolvency for purposes of fraudulent transfer laws vary depending upon the governing law. Generally, a guarantor would be considered insolvent if:

•: the sum of its debts, including contingent liabilities, was greater than the fair saleable value of all its assets;
•: the present fair saleable value of its assets was less than the amount that would be required to pay its probable liability on its existing debts, including contingent liabilities, as they became absolute and mature; or
•: it could not pay its debts as they became due.

Each subsidiary guarantee will contain a provision intended to limit the guarantor's liability to the maximum amount that it could incur without causing the incurrence of obligations under

its subsidiary guarantee to be a fraudulent transfer. This provision may not be effective to protect the subsidiary guarantees from being voided under fraudulent transfer law.

Your ability to transfer the notes may be limited by the absence of an active trading market, and an active trading market may not develop for the notes.

The notes are a new issue of securities for which there is no established public market. Although the underwriters have informed us that they intend to make a market in the notes, they have no obligation to do so and may discontinue making a market at any time without notice. Accordingly, a liquid market may not develop for the notes, you may not be able to sell your notes at a particular time and the prices that you receive when you sell the notes may not be favorable.

We do not intend to apply for the notes to be listed on any securities exchange or to arrange for the notes to be quoted on any quotation system. Notes that are sold to qualified institutional buyers will be eligible for trading on PORTAL.

Historically, the market for non-investment grade debt has been subject to disruptions that have caused substantial volatility in the prices of securities similar to the notes. The market, if any, for the notes may not be free from similar disruptions and any such disruptions may adversely affect the prices at which you may sell your notes. In addition, subsequent to their initial issuance, the notes may trade at a discount from their initial offering price, depending upon prevailing interest rates, the market for similar notes, our operating performance and financial condition and other factors.

Disclosure regarding forward-looking statements

Throughout this prospectus, we make statements that may be deemed "forward-looking" statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. 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 prospectus. 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 prospectus 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 prospectus 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 the registration statement of which this prospectus is a part with the Securities and Exchange Commission, except as required by law.

Use of proceeds

We estimate that the net proceeds from this offering will be approximately $344 million after deducting underwriting discounts and commissions and estimated expenses of the offering. We intend to use approximately $204 million of the net proceeds from this offering to redeem the outstanding 9.6% senior notes due 2012 assumed in the acquisition of Magnum Hunter. The 9.6% senior notes due 2012 have a face value of $195 million and are due March 15, 2012. As of December 31, 2006, the fair market value of the 9.6% senior notes due 2012 was approximately $210.7 million. Certain of the underwriters and their affiliates are lenders to us under our senior revolving credit facility. We intend to use the remainder of the proceeds to reduce outstanding borrowings under our senior revolving credit facility by approximately $140 million ($95 million outstanding at December 31, 2006 plus additional subsequent borrowings). Our senior revolving credit facility matures on July 1, 2010 and bore interest at a weighted average rate of approximately 6.75% as of December 31, 2006.

Capitalization

The following table sets forth our capitalization as of December 31, 2006 on a historical basis and on an as adjusted basis to give pro forma effect to this offering and the application of the net proceeds from the offering as described in "Use of proceeds."

You should read this table along with our audited consolidated financial statements and related notes and the other financial information contained in this prospectus.

				As of December 31, 2006

(Dollars in thousands)				Actual		As adjusted

				(unaudited)
Cash and cash equivalents				$	5,048	$	49,688

Long-term debt:
	Senior revolving credit facility(1)			$	95,000	$	—
	9.6% senior notes due 2012 (face value $195,000)(2)				210,746		—
	7¹/8% Senior Notes due 2017				—		350,000
	Floating rate convertible senior notes due 2023, 5.36% at December 31, 2006 (face value $125,000)(3)				137,921		137,921

		Total long-term debt			443,667		487,921
Total stockholders' equity(4)					2,976,143		2,979,793

			Total capitalization	$	3,419,810	$	3,467,714

(1): As of March 31, 2007, we had $161.0 million outstanding under our senior revolving credit facility. As of March 31, 2007, on a pro forma basis after giving effect to this offering and the application of the net proceeds from the offering as described in "Use of proceeds", we would have had $21.4 million outstanding.
(2): Fair market value at June 7, 2005 (date of acquisition of Magnum Hunter) equaled $215.5 million. The subsequent noted balances represent the fair market value at date of acquisition less amortization of the premium of fair market value over face value.
(3): Fair market value at June 7, 2005 equaled $144.75 million. The subsequent noted balances represent the fair market value at date of acquisition less amortization of the premium of fair market value over face value.
(4): The change in stockholders' equity results from an estimated pre-tax gain of $5.7 million (after tax gain of $3.7 million) to be realized from the redemption of our outstanding 9.6% senior notes due 2012. The book value of the senior notes at December 31, 2006 was $210.7 million. The estimated amount to redeem the senior notes is approximately $204 million ($195 million at a redemption price of 104.8% plus estimated costs).

Ratio of earnings to fixed charges

The following table sets forth our ratio of earnings to fixed charges:

	Year ended December 31,

(Dollars in thousands)	2006			2005			2004		2003		2002

Earnings:
Income from continuing operations before income taxes and cumulative change in accounting principle	$	544,324		$	516,455		$	246,318	$	148,169	$	61,379
Additions:
Fixed charges as shown below		29,795			19,262			1,900		1,977		820
Distributions received from equity-method investees		59,823			302			—		—		—

		89,618			19,564			1,900		1,977		820

Subtractions:
Equity in income of investees		17,712			473			—		—		—
Interest capitalized		25,478			12,315			—		304		206

		43,190			12,788			—		304		206

Earnings as adjusted	$	590,752		$	523,231		$	248,218	$	149,842	$	61,993

Fixed charges:
Interest on indebtedness, expensed or capitalized		31,829			20,236			1,075		1,285		620
Amortization of premium on indebtedness, expensed or capitalized		(3,784	)		(2,132	)		—		—		—
Interest within rent expense		1,750			1,158			825		692		200

Total fixed charges	$	29,795		$	19,262		$	1,900	$	1,977	$	820

Ratio of earnings to fixed charges		19.8			27.2			130.6		75.8		75.6

The ratio of earnings to fixed charges was computed by dividing earnings by fixed charges. Earnings consist of income from continuing operations before income taxes and cumulative change in accounting principle plus distributions received from equity investments, and fixed charges, minus income from equity investments and capitalized interest. Fixed charges consist of interest expensed, which includes amortization of the premium of fair market value over the face value of debt, an estimated interest component in net rental expense, and interest capitalized.

Selected historical consolidated financial data

The following table sets forth selected financial information as of the dates and for the periods indicated. This financial information is derived from our consolidated financial statements as of such dates and for such periods. This information should be read in conjunction with "Management's discussion and analysis of financial condition and results of operations" and our consolidated financial statements and notes thereto included elsewhere in this prospectus. The following information is not necessarily indicative of our future results.

		Year ended December 31,

(in thousands)		2006			2005			2004			2003			2002

Statement of operations data:
Revenues:
	Gas sales	$	810,894		$	807,007		$	366,260		$	250,764		$	128,060
	Oil sales		404,517			265,415			106,129			73,355			29,239
	Gas gathering and processing		47,879			44,238			101			679			1,067
	Gas marketing, net of related costs		3,854			1,962			2,674			823			2,254

Total revenues		$	1,267,144		$	1,118,622		$	475,164		$	325,621			160,620
Expenses:
	Depreciation, depletion and amortization	$	396,394		$	258,287		$	124,251		$	88,774		$	49,231
	Asset retirement obligation accretion		7,018			3,819			1,241			1,009			—
	Production		176,833			104,067			37,476			31,801			19,427
	Transportation		21,157			15,338			10,003			7,472			7,918
	Gas gathering and processing		27,410			31,890			284			849			642
	Taxes other than income		91,066			73,360			37,761			27,485			13,154
	General and administrative		42,288			33,497			22,483			17,526			8,568
	Stock compensation		8,243			4,959			1,957			1,824			125
	(Gain)/Loss on derivative instruments		(22,970	)		67,800			—			—			—
	Other operating, net		2,064			15,897			(3,394	)		—			—

Total expenses		$	749,503		$	608,914		$	232,062			176,740			99,065

Income from operations		$	517,641		$	509,708		$	243,102			148,881			61,555
Interest expense net of capitalized interest			5,692			7,921			1,075			981			414
Amortization of fair value of debt			(3,784	)		(2,132	)		—			—			—
Other, net			(28,591	)		(12,536	)		(4,291	)		(269	)		(238	)
Income before income tax expense and cumulative effect of a change in accounting principle		$	544,324		$	516,455		$	246,318		$	148,169		$	61,379
Income tax expense			198,605			188,130			92,726			55,141			21,560

Income before cumulative effect of a change in accounting principle		$	345,719		$	328,325		$	153,592		$	93,028		$	39,819
Cumulative effect of a change in accounting principle			—			—			—			1,605			—

Net Income		$	345,719		$	328,325		$	153,592		$	94,633		$	39,819

Balance sheet data (as of period end):
Cash and cash equivalents		$	5,048		$	61,647		$	115,746		$	40,420		$	22,327
Net oil and gas properties			3,587,710			2,876,959			802,293			624,304			530,718
Total assets			4,829,750			4,180,335			1,105,446			805,508			674,286
Total debt			443,667			352,451			—			—			32,000
Stockholders' equity			2,976,143			2,595,453			700,712			534,740			444,880
Cash flows data:
Net cash flow provided by (used in):
	Operating activities	$	878,419		$	704,734		$	355,853		$	205,110		$	104,455
	Investing activities		(1,009,802	)		(497,453	)		(293,101	)		(159,641	)		(71,685	)
	Financing activities		74,784			(261,380			12,574			(27,376	)		(17,613	)

	Year ended December 31,

(Dollars in thousands)	2006		2005		2004		2003		2002

Other financial data:
EBITDA(1)	$	942,626	$	780,531	$	371,644	$	239,529	$	111,024
Total interest(2)		29,940		19,607		1,075		1,285		620
Oil and gas expenditures(3)		1,030,791		631,549		281,407		150,501		66,458
Ratio of total debt to EBITDA		0.5x		0.5x		—		—		0.3x
Ratio of EBITDA to total interest(4)		31.5x		39.8x		345.7x		186.4x		179.1x

(1): EBITDA represents net earnings before income taxes, interest expense and depreciation, depletion and amortization. EBITDA is not a measure calculated in accordance with generally accepted accounting principles (GAAP). EBITDA should not be considered as an alternative to net income, income before taxes, net cash flow from operating activities or any other measure of financial performance presented in accordance with GAAP. We believe that EBITDA is a widely accepted financial indicator of a company's ability to incur and service debt and to fund capital expenditures. Because EBITDA is commonly used in the oil and gas industry, we believe it is useful in evaluating our ability to meet our interest obligations in connection with this offering. EBITDA calculations may vary among entities, so our computation of EBITDA may not be comparable to EBITDA or similar measures of other entities. In evaluating EBITDA, we believe that investors should consider, among other things, the amount by which EBITDA exceeds interest costs, how EBITDA compares to principal payments on debt and how EBITDA compares to capital expenditures for each period.

The following table provides a reconciliation of net income to EBITDA:

	Year ended December 31,

(in thousands)	2006			2005			2004		2003		2002

Net income	$	345,719		$	328,325		$	153,592	$	94,633	$	39,819
Income tax expense		198,605			188,130			92,726		55,141		21,560
Interest expense		5,692			7,921			1,075		981		414
Amortization of fair value of debt		(3,784	)		(2,132	)		—		—		—
Depreciation, depletion and amortization		396,394			258,287			124,251		88,774		49,231

EBITDA	$	942,626		$	780,531		$	371,644	$	239,529	$	111,024

(2): Includes capitalized interest of $24,248, $11,686, $0, $304 and $206 for the years ended December 31, 2006, 2005, 2004, 2003 and 2002, respectively.
(3): From Statements of Cash Flows.
(4): Represents EBITDA divided by total interest. The ratio of net income to total interest for the years ended December 31, 2006, 2005, 2004, 2003 and 2002 were 11.5x, 16.7x, 142.9x, 73.6x and 64.2x, respectively.

Management's discussion and analysis of
financial condition and results of operations

Introduction

Cimarex Energy Co. is an independent oil and gas exploration and production company, with operations focused mainly in Oklahoma, Texas, New Mexico, Kansas, Louisiana, and the Gulf of Mexico.

Our primary focus is exploration and development drilling for new reserves. To supplement our growth, we also consider mergers and acquisitions. On June 7, 2005, we acquired Magnum Hunter Resources, Inc, 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. Terms of the merger agreement provided that Magnum Hunter stockholders receive 0.415 shares of our common stock for each share of Magnum Hunter common stock. As a result of the merger, we issued 39.7 million common shares to Magnum Hunter's common stockholders and assumed $633 million of debt. The merger was accounted for as a purchase of Magnum Hunter by Cimarex. Results of operations from Magnum Hunter's properties are included in our consolidated statements of operations beginning June 7, 2005.

Our exploration and development expenditures totaled $1,049 million for 2006, up from $642 million in 2005. Operationally, we now have a large base of properties in the Permian Basin with operational characteristics similar to our Mid-Continent assets. The merger also extended our onshore Gulf Coast activities into the Gulf of Mexico. Overall, about 39 percent of our proved reserves are in the Permian Basin and 41 percent are in our Mid-Continent region. Our onshore Gulf Coast and Gulf of Mexico operations collectively make up 10 percent of our proved reserves.

Industry and economic factors

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

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

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

Extensive federal, state, and local regulation of the industry significantly affects our operations. In particular, our activities are subject to comprehensive environmental regulations. Compliance with these regulations increases the cost of planning, designing, drilling, installing, operating, and abandoning oil and gas wells and related facilities. These regulations may become more demanding in the future.

Approach to the business

Profitable growth largely depends upon our ability to successfully find and develop new proved reserves. To achieve an overall acceptable rate of growth, we maintain a blended portfolio of low, moderate, and higher risk exploration and development projects. We believe that this approach allows for consistent increases in our oil and gas reserves, while minimizing the chance of failure. To further mitigate risk, we have chosen to seek geologic and geographic diversification by operating in multiple basins. We may also consider the use of transaction-specific hedging of oil and gas prices to reduce price risk. In connection with the acquisition of Magnum Hunter, we acquired existing commodity derivatives, as well as in the third quarter of 2006 we entered into additional derivative contracts as discussed more fully below.

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

We project that 2007 exploration and development expenditures will range from $800 million to $1 billion. Approximately 37 percent of the expenditures will be in the Mid-Continent area, 28 percent in the Permian Basin, 24 percent in the Gulf Coast area, and 8 percent in the Gulf of Mexico.

Cash flow from operating activities for 2006 totaled $878.4 million, which helped to fund our drilling program. Based on expected cash provided by operating activities and monies available under our senior revolving credit facility, we believe we are well positioned to fund the projects identified for 2007 and beyond.

Critical accounting policies and estimates

Our discussion and analysis of our financial condition and results of operation are based upon our 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. In response to SEC Release No. 33-8040, Cautionary Advice Regarding Disclosure about Critical Accounting Policies, we have identified certain of these policies as being of particular importance to the portrayal of our financial position and results of operations and which require the application of significant judgment by our management. We analyze our estimates, including those related to oil and gas revenues, reserves and properties, as well as goodwill and contingencies, and base our estimates on historical experience and various other assumptions that we believe to be reasonable under the circumstances. Actual results may differ from these estimates under different assumptions or conditions. We believe the following critical accounting policies affect our more significant judgments and estimates used in the preparation of our consolidated financial statements.

Revenue recognition

Oil and gas sales. Revenue from the sale of oil and gas is recognized when title passes, net of royalties. This is known as the sales method (versus the entitlement method). Under the sales method, revenue is 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 earns a fee for such services. Revenues are recognized as gas is delivered and are reflected net of gas purchases on the accompanying consolidated statement of operations.

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, 2006 and 2005 was $3.2 million and $2.7 million, respectively. At December 31, 2006 we are 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, 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. For 2006, revisions of reserve estimates equaled a decrease of 3.7 MBbls of oil and 14.5 Bcf of gas (due to lower oil and gas prices), representing two and one half percent of proved oil and gas reserves as of December 31, 2006.

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

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.

At the end of each quarter, a full cost ceiling limitation calculation is made whereby net capitalized costs related to proved properties less associated deferred income taxes may not exceed an amount equal to the present value discounted at ten percent of estimated future net revenues from proved reserves less estimated future production and development costs and related income tax expense. Future net revenues used in the calculation of the full cost ceiling limitation are determined based on current oil and gas prices and are adjusted for designated cash flow hedges if it is determined that net capitalized costs exceed the full cost ceiling limit. If net capitalized costs subject to amortization were to exceed this limit, the excess would be charged to expense. However, if commodity prices increase subsequent to period end and prior to issuance of the financial statements, these higher commodity prices will be used to determine if the capital costs are in fact impaired as of the end of the period.

Goodwill

We account for goodwill in accordance with Statement of Financial Accounting Standard (SFAS) No. 142, Goodwill and Other Intangible Assets. SFAS No. 142 requires an annual impairment assessment. A more frequent assessment is required if certain events occur that reasonably indicate an impairment may have occurred. The volatility of oil and gas prices may cause more frequent assessments. The impairment assessment requires us to make estimates regarding the fair value of goodwill. The estimated fair value is based on numerous factors, including future net cash flows of our estimates of proved reserves as well as the success of future exploration for and development of unproved reserves. If the estimated fair value exceeds its carrying amount, goodwill is considered not impaired. If the carrying amount exceeds the estimated fair value, then a measurement of the loss must be performed, with any deficiency recorded as an impairment. To date, no related impairment has been recorded.

Derivatives

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

In connection with the Magnum Hunter merger, we recognized a $39.3 million net liability associated with Magnum Hunter's existing commodity derivatives at the merger date (June 7, 2005). These derivative instruments were not designated for hedge accounting treatment. As a result, we recognized a net gain for the year ended December 31, 2006 of $23 million. Activity included both non-cash mark-to-market derivative gains and losses as well as cash settlements. Cash payments related to these contracts that settled in the year ended December 31, 2006 was

$19 million. As of December 31, 2006, all derivative contracts assumed with the Magnum Hunter merger had matured.

In the third quarter of 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, 2006, this represented approximately 51% and 31% of our current anticipated Mid-Continent gas production for 2007 and 2008, respectively.

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

For the year ended December 31, 2006, we recorded an unrealized loss of $13 thousand related to the ineffective portion of the hedges. At December 31, 2006, $41.9 million and $7.1 million of the hedges were recorded as current and long-term assets, respectively, and an unrealized gain (net of deferred income taxes) of $31 million was recorded in other comprehensive income.

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

Contingencies

A provision for contingencies is charged to expense when the loss is probable and the cost can be reasonably estimated. Determining when expenses should be recorded for these contingencies and the appropriate amounts for accrual is a complex estimation process that includes subjective judgment. In many cases, this judgment is based on interpretation of laws and regulations, which can be interpreted differently by regulators and/or courts of law. We closely monitor known and potential legal, environmental, and other contingencies and periodically determine when we should record losses for these items based on information available to us. As of December 31, 2006, we have accrued $7.1 million for a mediated litigation settlement pertaining to post-production deductions on properties operated by us. We have also accrued an additional $1.5 million for a mediated litigation settlement pertaining to oil and gas property title issues. We anticipate payment of both settlements during 2007. We have other various litigation related matters in the normal course of business, none of which that can be estimated are deemed to be material, individually or in aggregate.

Asset retirement obligations

We recognize 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.

Recent accounting developments

In July 2006, the FASB issued Interpretation 48, Accounting for Uncertainty in Income Taxes, which clarifies the accounting for uncertainty in income taxes recognized in our financial statements in accordance with SFAS 109, Accounting for Income Taxes. The interpretation also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition. Along with these disclosures, a tabular presentation of significant changes during each period will be required. The Interpretation is effective as of the beginning of the first fiscal year beginning after December 15, 2006 (January 1, 2007 for calendar-year companies). We are currently evaluating the effects of implementing this interpretation and do not believe the adoption of this interpretation will have a material impact on our financial statements.

In September 2006, the Securities and Exchange Commission issued Staff Accounting Bulletin No. 108 regarding the process of quantifying misstatements within a financial statement, addressing in particular materiality analysis related to the correction of errors. The impact on the current year financial statements of correcting all misstatements, including both the carryover and reversing effects of prior year misstatements, must be quantified. Adjustment would be required if the misstatement is deemed material, after considering all relevant quantitative and qualitative factors. The periods in which the correction would be recorded would be dependent on the materiality considerations for each affected period. This did not have a material impact on our financial statements.

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

Overview

Our results of operations are primarily impacted by changes in oil and gas prices and changes in our production volumes. Realized gas prices decreased from $8.05 per Mcf in 2005 to $6.50 per Mcf in 2006, and oil prices increased from $55.25 per barrel in 2005 to $61.96 per barrel in 2006. We also sell gas on behalf of third parties that are incidental to sales of our own production. Sales and costs associated with our production are reflected in gas sales and transportation expense.

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

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

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

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

Depreciation, depletion and amortization of our producing properties is computed using the units-of-production method. Because the economic life of each producing well depends upon the assumed price for future sales of production, fluctuations in oil and gas prices may impact the level of proved reserves used in the calculation. Higher prices generally have the effect of increasing reserves, which reduces depletion 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. While we expect such costs to increase with our growth, we expect such increases to be proportionately smaller than our production growth.

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

Basis of presentation

In June 2005, we acquired Magnum Hunter Resources, Inc, by issuing 0.415 shares of our common stock for each share of outstanding Magnum Hunter common stock, resulting in the issuance of 39.7 million Cimarex common shares. At December 31, 2005, we had 82.4 million shares outstanding. The merger was accounted for as a purchase of Magnum Hunter by Cimarex. The results of operations of Magnum Hunter were included in our consolidated statements of operations beginning June 7, 2005.

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

Results of operations

Year ended December 31, 2006 compared with year ended December 31, 2005

Summary data

		For the years ended December 31,

(in thousands or as indicated)		2006			2005

Net income		$	345,719		$	328,325
	Per share—basic		4.21			5.07
	Per share—diluted		4.11			4.90
Gas sales		$	810,894		$	807,007
Oil sales			404,517			265,415

	Total oil and gas sales	$	1,215,411		$	1,072,422

Total gas volume—Mcf			124,733			100,272
Gas volume—MMcf per day			341.7			274.7
Average gas price—per Mcf		$	6.50		$	8.05
Total oil volume—thousand barrels			6,529			4,804
Oil volume—barrels per day			17,887			13,162
Average oil price—per barrel		$	61.96		$	55.25
Gas gathering and processing revenues		$	47,879		$	44,238
Gas gathering and processing costs			(27,410	)		(31,890	)

	Gas gathering and processing margin	$	20,469		$	12,348

Gas marketing revenues, net of related costs		$	3,854		$	1,962
Expenses and other income:
Depreciation, depletion and amortization		$	396,394		$	258,287
Production			176,833			104,067
Transportation			21,157			15,338
Taxes other than income			91,066			73,360
General and administrative			42,288			33,497
Stock compensation			8,243			4,959
Other operating, net			2,064			15,897
(Gain) Loss on derivative instruments			(22,970	)		67,800
Int. exp., net of cap. int. & amort. of F.V. of debt			1,908			5,789
Asset retirement obligation accretion			7,018			3,819
Other, net			(28,591	)		(12,536	)

Net income for the year of 2006 was $345.7 million, or $4.11 per diluted share, compared to net income of $328.3 million, or $4.90 per diluted share in 2005. The change in net income results from the effect of changes in revenues and costs, as discussed further. The results of operations of Magnum Hunter are included in our consolidated statements of operations only for the period since the acquisition on June 7, 2005.

Oil and gas sales for the year of 2006 totaled $1.2 billion, compared to $1.1 billion for 2005. The $143.0 million increase in sales between the two periods results from $292.0 million related to higher production volumes, offset by a decrease of $149.0 million resulting from lower commodity prices.

Sales benefited from higher production volumes. Average daily gas production rose 67.0 MMcf in 2006 to 341.7 MMcf from 274.7 MMcf in 2005, resulting in $197.0 million of incremental revenues. Oil volumes averaged 17,887 barrels per day for 2006, compared to 13,162 barrels per day in 2005, resulting in increased revenues of $95.0 million. The increase in sales volumes between the periods of 2006 and 2005 is due to the inclusion of Magnum Hunter operations beginning June 7, 2005 (date of acquisition) and positive drilling results during 2005 and 2006. Production volumes in the Gulf of Mexico and along the Texas and Louisiana Gulf Coast area were negatively impacted during the fourth quarter of 2005 as a result of hurricanes. It is estimated to have negatively impacted fourth-quarter 2005 production by 41 to 45 MMcf equivalent per day. These volumes were brought back online throughout 2006, and by the fourth quarter of 2006 less than one MMcf equivalent per day was shut-in from the 2005 hurricane activity. No oil and gas reserves have been lost as a result of the storms and the majority of associated repair costs will be covered by insurance.

Realized gas prices averaged $6.50 per Mcf for 2006, compared to $8.05 per Mcf for 2005. This 19 percent change decreased sales by $193.0 million between the two periods. Realized oil prices, however, averaged $61.96 per barrel for 2006, compared to $55.25 per barrel for 2005. The increase in sales between periods resulting from this 12 percent improvement in oil prices totaled $44.0 million. Changes in realized prices were the direct result of overall market conditions.

Gas gathering and processing revenues, net of related costs, equaled $20.5 million in 2006, compared to $12.4 million in 2005. The increase is due to the inclusion of related activities from Magnum Hunter operations from June 7, 2005. We own interests in gas gathering systems and gas processing plants that are connected to our production operations. We transport and process third party gas that is associated with our gas.

Gas marketing net revenues increased to $3.9 million from $2 million, net of related costs of $144.7 million and $213.7 million for 2006 and 2005, respectively. Gas marketing revenues, net of related costs, pertain to sales of gas on behalf of third parties that is incidental to sales of our own production.

Costs and expenses

Net costs and expenses (not including gas gathering, marketing and processing costs, as well as income tax expense) were $695.4 million in 2006 compared to $570.3 million in 2005. Depreciation, depletion and amortization (DD&A) was the largest component of the increase between periods. DD&A equaled $396.4 million in 2006 compared to $258.3 million in 2005. On a unit of production basis, DD&A was $2.42 per Mcfe in 2006 compared to $2.00 per Mcfe for 2005. The increase stems from higher costs for reserves added during 2005 and 2006. Service costs to drill and complete wells have been increasing. That along with certain high cost dry holes in our Gulf Coast and Gulf of Mexico regions have influenced our per unit rates, even though overall drilling success rates have remained high.

Production costs rose $72.7 million from $104.1 million ($.81 per Mcfe) in 2005 to $176.8 million ($1.08 per Mcfe) in 2006. The higher costs in 2006 resulted from higher field operating expenses from an expanded number and type of properties, higher maintenance costs and increased insurance costs due to past hurricanes. Additional workover/maintenance projects were implemented in 2006, totaling $28.9 million ($0.18 per Mcfe) compared to $11.6 million ($0.09 per Mcfe) in 2005.

Transportation costs increased from $15.3 million in 2005 to $21.2 million in 2006. The increase is the result of higher sales volumes and that expiring contracts are being renewed with increased current market rates.

Taxes other than income were $17.7 million greater, rising from $73.4 million in 2005 to $91.1 million in 2006. The increase between periods resulted from increases in oil and gas sales stemming from higher production volumes and oil prices.

General and administrative (G&A) expenses increased $8.8 million from $33.5 million in 2005 to $42.3 million in 2006. The increase between periods is due to an expansion of staff and higher employee-benefit costs.

Other operating, net decreased from $15.9 million in 2005 to $2.1 million in 2006. These expenses in 2005 consisted primarily of $9.4 million of costs associated with the Magnum Hunter merger. Of this $9.4 million, $3.6 million is due to the acceleration of vesting of stock options and restricted stock units resulting from change of control provisions under our stock incentive plan becoming effective due to the Magnum Hunter merger. The remaining $5.8 million consists of $4.3 million of general integration costs, $1.0 million for retention bonuses, and $0.5 million of related financing costs. In addition to merger costs, 2005 expenses also included a mediated $6.5 million litigation settlement pertaining to post-production deductions on properties operated by us. Other expense for 2006 included $2.1 million of litigation settlements pertaining primarily to resolution of oil and gas property title issues.

Another component of net costs and expenses for 2006 and 2005 was the gain and loss on derivative instruments. In connection with the Magnum Hunter merger, we recognized a $39.3 million liability associated with Magnum Hunter's existing commodity derivatives at the merger date (June 7, 2005). These derivative instruments were not designated for hedge accounting treatment. As a result, we recognized net gains for the year 2006 of $23.0 million and net losses for 2005 of $67.8 million, respectively. Activity includes both non-cash mark-to-market derivative gains and losses as well as cash settlements. Cash payments related to these contracts that settled in 2006 and 2005 totaled $19.0 million and $64.3 million, respectively. Theses contracts expired December 31, 2006.

To mitigate a portion of the potential exposure to adverse market changes in an environment of volatile gas prices, we entered into additional derivative contracts in third quarter of 2006. These derivatives have been designated for hedge accounting treatment as cash flow hedges. Changes in the fair value of the hedges, to the extent the hedge is effective, are recognized in other comprehensive income until the hedged item is settled. Changes in the fair value of the hedge resulting from ineffectiveness are recognized currently as unrealized gains or losses in

other income and expense in the consolidated statements of operations. Gains and losses upon settlement of the cash flow hedges will be recognized in gas revenues in the period the contracts are settled. During 2006, we recognized an unrealized loss of $13 thousand related to the ineffective portion of the derivative contracts.

Net interest expense in 2006 totaled $1.9 million, comprised of $29.9 million of interest expense, offset by $24.2 million of capitalized interest and $3.8 million of amortization of fair value of debt. We capitalize interest related to borrowings associated with costs incurred to bring properties under development, not being amortized, to their intended use. This has decreased from $5.8 million of net interest expense in 2005, which was comprised of $19.6 million of interest expense, offset by $11.7 million of capitalized interest and $2.1 million of amortization of fair value of debt. The increases in the components of the 2006 net interest amount results from amounts associated with the debt assumed in the Magnum Hunter merger and an increase in costs incurred to bring properties under development, not being amortized, to their intended use. Prior to the Magnum Hunter merger, we had no outstanding debt.

Asset retirement obligation accretion increased $3.2 million from $3.8 million in 2005 to $7.0 million in 2006. We recognize 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. Since 2005 the liability has increased $28.0 million from $101.1 million in 2005 to $129.1 million in 2006.

Other, net increased from $12.5 million of income in 2005 to $28.6 million of income in 2006. The components of this other income net of other expenses consist of miscellaneous items that will vary from period to period, including income and loss in equity investees. The large increase from 2005 to 2006 is due primarily to distribution received in excess of our investment in our limited partnership affiliates, Teal Hunter L.P. and Mallard Hunter L.P. These partnerships sold all of their interest in oil and gas properties during 2006. Our investments in these partnerships had been reflected in other assets, net. Net sales consideration received via distributions from the partnerships equaled $59.3 million, which are in excess of our investment balance in the partnerships. The excess distributions of $19.8 million have been recorded in other income for 2006.

Income tax expense

Income tax expense totaled $198.6 million for 2006 versus $188.1 million for 2005. Tax expense equaled a combined federal and state effective income tax rate of 36.5 percent and 36.4 percent in 2006 and 2005, respectively. Included in the 2006 income tax expense of $198.6 million is a current benefit of $21.9 million.

Year ended December 31, 2005 compared with year ended December 31, 2004

Summary data

		For the years ended December 31,

(in thousands or as indicated)		2005			2004

Net income		$	328,325		$	153,592
	Per share—basic		5.07			3.70
	Per share—diluted		4.90			3.59
Gas sales		$	807,007		$	366,260
Oil sales			265,415			106,129

	Total oil and gas sales	$	1,072,422		$	472,389

Total gas volume—MMcf			100,272			63,611
Gas volume—MMcf per day			274.7			173.8
Average gas price—per Mcf		$	8.05		$	5.76
Total oil volume—thousand barrels			4,804			2,641
Oil volume—barrels per day			13,162			7,215
Average oil price—per barrel		$	55.25		$	40.19
Gas gathering and processing revenues		$	44,238		$	101
Gas gathering and processing costs			(31,890	)		(284	)

	Gas gathering and processing margin	$	12,348		$	(183	)

Gas marketing revenues, net of related costs		$	1,962		$	2,674
Costs and expenses:
Depreciation, depletion and amortization		$	258,287		$	124,251
Production			104,067			37,476
Transportation			15,338			10,003
Taxes other than income			73,360			37,761
General and administrative			33,497			22,483
Stock compensation			4,959			1,957
Other operating, net			15,897			(3,394	)
Loss on derivative instruments			67,800			—
Int. exp., net of cap. int. & amort. of F.V. of debt			5,789			1,075
Asset retirement obligation accretion			3,819			1,241
Other, net			(12,536	)		(4,291	)

Net income for the year of 2005 was $328.3 million, or $4.90 per diluted share, compared to net income of $153.6 million, or $3.59 per diluted share in 2004. The change in net income results from the effect of changes in revenues and costs, as discussed further. The results of operations of Magnum Hunter are included in our consolidated statements of operations only for the period since the acquisition on June 7, 2005.

Oil and gas sales for the year of 2005 totaled $1.1 billion, compared to $472.4 million for 2004. The $600.0 million increase in sales between the two periods results from $302.0 million related

to higher commodity prices and $298.0 million due to higher production volumes (due primarily to increased production resulting from the acquisition of Magnum Hunter).

Realized gas prices averaged $8.05 per Mcf for 2005, compared to $5.76 per Mcf for 2004. This 40 percent change increased sales by $230.0 million between the two periods. Realized oil prices averaged $55.25 per barrel for 2005, compared to $40.19 per barrel for 2004. The increase in sales between periods resulting from this 37 percent improvement in oil prices totaled $72.0 million. Changes in realized prices were the direct result of overall market conditions.

Sales also benefited from higher production volumes. Average gas volumes rose 100.9 MMcf per day in 2005 to 274.7 MMcf per day from 173.8 MMcf per day in 2004, resulting in $211.1 million of incremental revenues. Oil volumes averaged 13,162 barrels per day for 2005, compared to 7,215 barrels per day in 2004, resulting in increased revenues of $86.9 million. The increase in sales volumes between the periods of 2005 and 2004 is due to positive drilling results during 2004 and 2005, and the inclusion of production from Magnum Hunter operations from June 7, 2005. Production volumes in the Gulf of Mexico and along the Texas and Louisiana Gulf Coast area were negatively impacted during the third and fourth quarters of 2005 as a result of hurricanes. It is estimated to have negatively impacted fourth-quarter 2005 production by 41 to 45 MMcf equivalent per day and full-year volumes by 17 to 20 MMcf equivalent per day. At year-end 2005, approximately 20 MMcf equivalent was still shut-in. It is anticipated that most of the remaining shut-in volumes will be restored by the end of the first quarter of 2006. The timetable to restore full production largely depends on the startup of refineries, gas processing plants, platforms, facilities and pipelines owned and operated by others. No oil and gas reserves have been lost as a result of the storms and essentially all associated repair costs will be covered by insurance.

Gas gathering and processing revenues, net of related costs, equaled $12.4 million in 2005, compared to a loss of $0.2 million in 2004. The increase is due to the inclusion of related activities from Magnum Hunter operations from June 7, 2005. We own interests in gas gathering systems and gas processing plants that are connected to our production operations. We transport and process third party gas that is associated with our gas.

Gas marketing net revenues decreased to $2 million from $2.7 million, net of related costs of $213.7 million and $193.0 million for 2005 and 2004, respectively. Gas marketing revenues, net of related costs, pertain to sales of gas on behalf of third parties that is incidental to sales of our own production.

Costs and expenses

Costs and expenses (not including gas gathering, marketing and processing costs as well as income tax expense) were $570.3 million in 2005 compared to $228.6 million in 2004. Depreciation, depletion and amortization (DD&A) was the largest component of the increase between periods. DD&A equaled $258.3 million in 2005 compared to $124.3 million in 2004. On a unit of production basis, DD&A was $2.00 per Mcfe in 2005 compared to $1.56 per Mcfe for 2004. The increase largely stems from costs associated with Magnum Hunter operations and higher costs for reserves added during 2004 and 2005.

Production costs rose $66.6 million from $37.5 million ($.47 per Mcfe) in 2004 to $104.1 million ($.81 per Mcfe) in 2005. The higher costs in 2005 resulted primarily from the inclusion of costs

associated with Magnum Hunter operations, higher field operating expenses from an expanded number of properties and higher maintenance costs.

Transportation costs increased from $10.0 million in 2004 to $15.3 million in 2005. The increase is the result of expiring contracts being renewed with increased current market rates and the inclusion of transportation costs associated with Magnum Hunter operations.

Taxes other than income were $35.6 million greater, rising from $37.8 million in 2004 to $73.4 million in 2005. The increase between periods resulted from increases in oil and gas sales stemming from inclusion of Magnum Hunter operations, higher production volumes and commodity prices.

General and administrative (G&A) expenses increased $11.0 million from $22.5 million in 2004 to $33.5 million in 2005. The increase between periods is due to an expansion of staff and higher employee-benefit costs.

Stock compensation expense consists of non-cash charges resulting from the issuance of restricted stock, restricted stock units and stock option awards. Stock compensation increased from $2.0 million in 2004 to $5.0 million in 2005 due primarily to the $3.4 million expensing of stock options resulting from the adoption of SFAS No. 123R as of January 1, 2005.

Other operating, net totaled an expense of $15.9 million in 2005 and income of $3.4 million in 2004. The 2005 expenses consisted primarily of $9.4 million of costs associated with the Magnum Hunter merger. Of this $9.4 million, $3.6 million is due to the acceleration of vesting of stock options and restricted stock units resulting from change of control provisions under our stock incentive plan becoming effective due to the Magnum Hunter merger. The remaining $5.8 million consisted of $4.3 million of general integration costs, $1.0 million for retention bonuses, and $0.5 million of related financing costs. In addition to merger costs, 2005 expenses also included a mediated $6.5 million litigation settlement pertaining to post-production deductions on properties operated by us. The income reflected in 2004 consisted of miscellaneous litigation settlements in our favor.

Another large component of the increase in costs and expenses between periods was the loss on derivative instruments. Prior to the acquisition of Magnum Hunter, we did not use financial instruments to mitigate commodity price changes. In connection with the merger, we recognized a $39.3 million liability associated with Magnum Hunter's existing commodity derivatives at the merger date (June 7, 2005). These derivative instruments have not been designated for hedge accounting treatment. As a result, we recognized in earnings during 2005 a net loss of $67.8 million. The charge includes both non-cash mark-to-market derivative losses as well as cash settlements. Cash payments related to these contracts that settled in 2005 totaled $64.3 million. The net derivative liability at December 31, 2005 equals $41.9 million. We will continue to recognize mark-to-market gains and losses as well as amortization of these contracts in future earnings until the derivative instruments mature.

Net interest expense in 2005 of $5.8 million is comprised of $19.6 million of interest expense, offset by $11.7 million of capitalized interest resulting from interest recognized on borrowings associated with costs incurred to bring properties under development, not being amortized, to their intended use and $2.1 million of amortization of fair value of debt. This has increased from $1.1 million of interest expense in 2004. The additional components of the 2005 net interest amount and the increase from 2004 results from amounts associated with the debt

assumed in the Magnum Hunter merger. Prior to the Magnum Hunter merger, we had no outstanding debt.

Asset retirement obligation accretion increased $2.6 million from $1.2 million in 2004 to $3.8 million in 2005. We recognize 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. Since 2004 the liability has increased $81.3 million from $19.8 million in 2004 to $101.1 million in 2005.

Other, net increased from $4.3 million of income in 2004 to $12.5 million of income in 2005. The components of this other income net of other expenses consist of miscellaneous items that will vary from period to period. The increase from 2004 to 2005 is due primarily to additional gains on the sale of miscellaneous equipment inventory.

Income tax expense

Income tax expense totaled $188.1 million for 2005 versus $92.7 million for 2004. Tax expense equaled a combined federal and state effective income tax rate of 36.4 percent and 37.6 percent in 2005 and 2004, respectively.

Liquidity and capital resources

Cash flows

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

Cash flow provided by operating activities for 2006 was $878.4 million, compared to $704.7 million for 2005. The increase in 2006 from the earlier period resulted primarily from higher oil and gas production and higher oil prices.

Cash flow used in investing activities for 2006 was $1.0 billion, compared to $497.5 million for 2005. The increase in 2006 stemmed from a larger exploration and development program.

Cash flow provided by financing activities in 2006 was $74.8 million versus $261.4 million used in 2005. The cash provided by financing activities in 2006 resulted primarily from the borrowing of $95.0 million on our credit facility.

Financial condition

As of December 31, 2006, stockholders' equity totaled $3.0 billion, up from $2.6 billion at December 31, 2005. The increase resulted primarily from 2006 net income of $345.7 million. At December 31, 2006, our cash balance equaled $5.0 million.

In December 2005, our Board of Directors declared our first quarterly cash dividend of $.04 per share payable to shareholders. A $.04 per share dividend has been authorized in every quarter of 2006. Also in December 2005, our Board of Directors authorized the repurchase of up to four million shares of common stock. Through December 31, 2005, 68,000 shares had been repurchased at an average price of $43.03. Since December 31, 2005 and through December 31, 2006, an additional 182,100 shares have been repurchased for an average price of $44.43 per share.

Working capital

Working capital at December 31, 2006 totaled $62.2 million, compared to $31.6 million at December 31, 2005. The increase is primarily the result of settlement of the liability associated with derivative contracts outstanding at December 31, 2005 and entering into new derivative contracts in the third quarter for which a current asset was recorded at December 31, 2006.

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.

Financing

Pre-offering

Debt at December 31, 2005 consisted of the following (in thousands):


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

Total long-term debt	$	352,451

Debt at December 31, 2006 consisted of the following (in thousands):


Bank debt	$	95,000
9.6% senior notes due 2012 (face value $195,000)(1)		210,746
Floating rate convertible senior notes due 2023, 5.36% at December 31, 2006 (face value $125,000)(2)		137,921

Total long-term debt	$	443,667

(1): Fair market value at June 7, 2005 (date of acquisition of Magnum Hunter) equaled $215.5 million. The subsequent noted balance represents the fair market value at date of acquisition less amortization of the premium of fair market value over face value.
(2): Fair market value at June 7, 2005 equaled $144.75 million. The subsequent noted balance represents the fair market value at date of acquisition less amortization of the premium of fair market value over face value.

Our senior revolving credit facility provides for $500 million of long-term committed credit. The facility is scheduled to mature on July 1, 2010 and is secured by mortgages on certain oil and gas properties and the stock of certain wholly-owned operating subsidiaries. At December 31, 2006, there were outstanding borrowings of $95 million under the senior revolving credit facility at a weighted average interest rate of approximately 6.75%. We also had outstanding letters of credit of approximately $5 million, leaving an unused borrowing capacity of approximately $400 million at December 31, 2006.

The credit facility agreement contains both financial and non-financial covenants. We continue to comply with these covenants and do not view them as materially restrictive.

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

Year		Percentage


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

We intend to redeem the 9.6% senior notes due 2012 in full with the proceeds of this offering.

The floating rate convertible senior notes due 2023 were assumed in the Magnum Hunter merger and mature on December 15, 2023. The notes are senior unsecured obligations and bear interest at an annual rate equal to three-month LIBOR, reset quarterly. On December 31, 2006, the interest rate equaled 5.36%.

Holders of the convertible notes may surrender their notes for conversion into a combination of cash and shares of our common stock upon the occurrence of certain circumstances, including if the price of our common stock has been trading above the fixed conversion price of $28.99 per share. On December 29, 2006, the closing price of our common stock traded on the New York Stock Exchange was $36.50. There is not an observable market for the notes. Based on an average common stock price of $36.50, management estimates the fair value of the notes at December 31, 2006 was approximately $157.4 million (or $1,259 per bond).

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

Post-offering

Debt at December 31, 2006, as adjusted to give pro forma effect to the offering and the application of the net proceeds from the sale of the notes as set forth under "Use of Proceeds," would have consisted of the following (in thousands):


Bank debt	$	—
9.6% senior notes due 2012 (face value $195,000)		—
7¹/8% Senior Notes due 2017		350,000
Floating rate convertible senior notes due 2023 (face value $125,000)		137,921

Total long-term debt	$	487,921

As of December 31, 2006, on a pro forma basis, after giving effect to the offering of the notes offered hereby, we would have had outstanding $487.9 million in aggregate indebtedness,

with an additional $495.0 million of borrowing capacity available under our senior revolving credit facility. Our liquidity requirements will be significant, primarily due to funding our operation, exploration and development activities and debt service requirements.

At December 31, 2006, on a pro forma basis, we would have had $125 million face value of debt subject to variable interest rates. A 1% increase in the average interest rate would increase annual interest expense by approximately $1.25 million.

We intend to use a portion of the proceeds of the offering to reduce outstanding borrowings under our senior revolving credit facility by approximately $140 million ($95 million outstanding at December 31, 2006 plus additional subsequent borrowings). Our senior revolving credit facility matures on July 1, 2010 and bore interest at a weighted average rate of approximately 6.75% as of December 31, 2006. Reductions of outstanding borrowings under our senior revolving credit facility can be temporary, as additional borrowing capacity is available under the facility.

In addition, the indenture governing the notes being offered hereby will limit our (and our subsidiary guarantors') ability to:

•: incur additional debt or issue certain preferred shares;
•: pay dividends on or make other distributions in respect of our capital stock or make other restricted payments;
•: make certain investments;
•: enter into certain types of transactions with affiliates;
•: sell certain assets;
•: create liens on certain assets to secure debt; and
•: consolidate, merge, sell or otherwise dispose of all or substantially all of our assets.

Subject to certain exceptions, the indenture governing the notes will permit us and our restricted subsidiaries to incur additional indebtedness, including secured indebtedness. See "Description of notes."

Contractual obligations and material commitments

The following table sets forth our contractual obligations and material commitments as of December 31, 2006 on a historical basis:

	Payments due by period

Contractual obligations (in thousands)	Total		Less than 1 year		1-3 years		3-5 years		More than 5 years

Long-term debt(1)	$	415,000	$	—	$	—	$	95,000	$	320,000
Fixed-rate interest payments(1)		102,960		18,720		37,440		37,440		9,360
Operating leases		31,278		5,158		10,074		7,868		8,178
Drilling commitments		55,322		55,322		—		—		—
Asset retirement obligation(2)		129,141		4,320		—		—		—
Other liabilities		5,932		202		67		51		5,612

(1): These amounts do not include interest on the $95 million of bank debt outstanding at December 31, 2006. The weighted average interest rate at December 31, 2006 on the bank debt was approximately 6.75%.
(2): We have excluded the long term asset retirement obligations because we are not able to precisely predict the timing of these amounts.

At December 31, 2006, we had a firm sales contract to deliver approximately four Bcf of natural gas over the next eight months. If this gas is not delivered, our financial commitment would be approximately $22.3 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.

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 $2.8 million.

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

Based on current commodity prices and anticipated levels of production, we believe that the estimated net cash generated from operations, coupled with the cash on hand and amounts available under our existing line of credit will be adequate to meet future liquidity needs, including satisfying our financial obligations and funding our operations and exploration and development activities.

2007 outlook

Our projected 2007 exploration and development expenditure program ranging from $800 million to $1 billion will require a great deal of coordination and effort. Though there are a variety of factors that could curtail, delay or even cancel some of our drilling operations, we believe our projected program has a high degree of occurrence. The majority of projects are in hand, drilling rigs are being scheduled, and the historical results of our drilling efforts in these areas warrant pursuit of the projects.

Costs of operations on a per Mcfe basis for 2007 are estimated to approximate levels realized in late 2006. Should factors beyond our control change, our program and realized costs will vary from current projections. These factors could include volatility in commodity prices, changes in the supply of and demand for oil and gas, weather conditions, governmental regulations and more.

Production estimates for 2007 range from 450 to 470 MMcfe per day. Revenues will be dependent not only on the level of oil and gas actually produced, but also the prices that will be realized. During 2006, our realized prices averaged $6.50 per Mcf of gas and $61.96 per barrel of oil. Prices can be very volatile and the possibility of 2007 realized prices being different than they were in 2006 is high.

Qualitative and quantitative disclosures about market risk

Price fluctuations

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

Monthly gas price realizations during 2006 ranged from $4.23 per Mcf to $8.43 per Mcf. Oil prices ranged from $54.85 per barrel to $70.61 per barrel. It is impossible to predict future oil and gas prices with any degree of certainty.

In third quarter 2006, we entered into derivative contracts to mitigate a portion of our potential exposure to adverse market changes in the Mid-Continent region, in an environment

of volatile gas prices. These arrangements, which were based on prices available in the financial markets at the time the contracts were entered into, will be settled in cash and will not require physical delivery of hydrocarbons. These hedges have been designated for hedge accounting treatment as cash flow hedges under SFAS No. 133 and therefore, gains and losses upon settlement of the hedges will be recognized in gas revenue in the period the contracts are settled. We believe that we have sufficient production volumes such that the hedge contract transactions will occur as expected.

The following tables reflect the volumes, weighted average contract prices and fair values of the contracts we have in place as of December 31, 2006. We are exposed to risks associated with these contracts arising from volatility in commodity prices and the unlikely event of non-performance by the counterparties to the agreements.

Commodity	Type	Volume/day	Duration	Mid-continent weighted average price		Fair value (000's)


Natural Gas	Collars	80,000 MMBTU	Jan 07-Dec 07	$	7.00-$10.17	$	41,945
Natural Gas	Collars	40,000 MMBTU	Jan 08-Dec 08	$	7.00-$9.90		7,051

						$	48,996

At December 31, 2006, the weighted average Mid-Continent prices for the 2007 and 2008 contracts approximated $6.13 and $7.02, respectively.

Interest rate risk

Fixed and variable rate debt. We assumed fixed and variable rate debt as part of the acquisition of Magnum Hunter. These agreements expose us to market risk related to changes in interest rates. We have a credit facility that bears interest at either a Base rate or a Eurodollar rate at our option.

The following table presents the carrying and fair value of our debt along with average interest rates as of December 31, 2006. The fair value for the convertible notes was based on an average price per share of $36.50 for our common stock. The fair value for the existing

fixed rate senior notes that will be redeemed in connection with this offering was valued at their last traded value before December 31, 2006.

Expected maturity dates (in thousands)	2010		2012		2017		2023		Total		Book value		Fair value


Pre-offering:
Variable Rate Debt:
Bank debt(a)	$	95,000	$	—	$	—	$	—	$	95,000	$	95,000	$	95,000
Convertible notes(b)	$	—	$	—	$	—	$	125,000	$	125,000	$	137,921	$	157,393
Fixed Rate Debt:
9.6% senior notes due 2012(c)	$	—	$	195,000	$	—	$	—	$	195,000	$	210,746	$	205,238
Post-offering(d):
Variable Rate Debt:
Bank debt(a)	$	—	$	—	$	—	$	—	$	—	$	—	$	—
Convertible notes(b)	$	—	$	—	$	—	$	125,000	$	125,000	$	137,921	$	157,393
Fixed Rate Debt:
9.6% senior notes due 2012	$	—	$	—	$	—	$	—	$	—	$	—	$	—
7¹/8% Senior Notes due 2017	$	—	$	—	$	350,000	$	—	$	350,000	$	350,000	$	350,000

(a): At December 31, 2006, the weighted average interest rate on outstanding borrowings under the credit facility was approximately 6.75%.
(b): The interest rate on the convertible notes is 5.36%. The rate on these notes is equal to the three month LIBOR, adjusted quarterly. A holder of these notes has the right to require us to repurchase all or a portion of these notes on December 15, 2008, 2013, and 2018. The repurchase will be equal to the face value of the notes plus accrued and unpaid interest up to the date of repurchase.
(c): The interest rate on the senior notes due 2012 is a fixed 9.6%.
(d): As adjusted to give pro forma effect to this offering and the application of the net proceeds from the sale of the notes as set forth under "Use of proceeds."

Business

Our company

We are an independent oil and gas exploration and production company. Our core areas of operation are in the Mid-Continent, Permian Basin and onshore Gulf Coast regions of the U.S. We also have a small presence in the Gulf of Mexico and are expanding our operations in Wyoming. As of December 31, 2006 our estimated proved reserves were 1,449 Bcfe, of which 80% were proved developed and 75% were gas. During 2006, our net production averaged 449 MMcfe per day, which implies a reserve life of approximately 8.8 years. For the year ended December 31, 2006, we generated revenues and EBITDA of $1,267 million and $943 million, respectively. See "Summary—Summary historical consolidated financial data" for reconciliation of EBITDA to net income.

The following table summarizes our estimated proved oil and gas reserves by region as of December 31, 2006 and our average daily production by region for 2006.

					2006 average daily production

				Percent of proved reserves	2006 average daily production
	Oil (MBbl)	Gas (MMcf)	Equivalent (MMcfe)	Percent of proved reserves	Oil (MBbl/d)	Gas (MMcf/d)	Total (MMcfe/d)

Mid-Continent	8,709	542,447	594,701	41%	4.7	152.5	180.7
Permian Basin	44,351	296,969	563,076	39%	8.1	83.8	132.4
Gulf Coast	4,671	76,640	104,663	7%	3.2	61.8	80.7
Gulf of Mexico	964	38,111	43,895	3%	1.6	36.2	45.9
Western/Other	1,102	136,195	142,811	10%	0.3	7.4	9.4

	59,797	1,090,362	1,449,146	100%	17.9	341.7	449.1

Business strengths

Blended portfolio of low-risk development and potentially high-return exploration projects. We seek to maintain a geographically and geologically diverse portfolio of low-to-moderate risk development and higher risk exploration projects. The low-risk, repeatable results we achieve in our Mid-Continent and Permian Basin regions provide moderate and predictable production and reserve growth. Our higher-risk drilling locations along the Gulf Coast and in the Gulf of Mexico are characterized by higher reserves per well and potentially higher

economic returns. We believe that this blend of low-risk Mid-Continent and Permian Basin drilling combined with higher-potential Gulf Coast exploration allows us to achieve consistent, profitable results while also enabling us to pursue larger growth opportunities.

Large undeveloped acreage position with an active drilling program. As of December 31, 2006, we owned leases covering more than 4.4 million net acres, of which 80% were undeveloped. In 2006, we drilled more than 550 gross wells completing 91% as producers. More than 80% of this drilling occurred in the Mid-Continent and Permian Basin where we achieved drilling success rates of 97% and 96%, respectively. Our technical teams and operating managers continue to generate projects on our existing acreage inventory and also seek to identify new areas for exploration and development.

Business strategy

Focus on blended portfolio. We maintain a diverse portfolio of prospects that is underpinned by approximately 70%-80% low-to-moderate risk projects combined with a smaller percentage of higher risk/higher potential prospects. Our objective is to achieve consistent, profitable growth while still preserving opportunities for potentially meaningful new discoveries. We also seek to maintain geographic diversification so as to mitigate certain operational and market risks and to position us to benefit from emerging plays.

effectively control operating costs, timing of development activities and technological enhancements, marketing of production and allocation of our capital budget.

Maintain financial flexibility and a conservative capital structure. We believe that maintaining a conservative capital structure will provide us with the flexibility needed to capitalize on future growth opportunities while limiting our financial risk. We have historically used leverage conservatively, funding our development and growth activity through a combination of internally generated cash flow, bank borrowings and stock-for-stock mergers. Prior to our 2005 acquisition of Magnum Hunter and the assumption of its debt, we had no debt outstanding at year-end 2003 and 2004 and our 2006 year-end debt-to-capitalization ratio was 13%. Based on expected cash flow provided by operating activities and available liquidity under our senior revolving credit facility, we believe we are well positioned to fund our identified drilling opportunities for the foreseeable future.

Business segments

We have 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; the upper Gulf Coast areas of Texas, south Louisiana and Mississippi; and the Gulf of Mexico.

A summary of our 2006 exploration and development activity by region is as follows.

(Dollars in millions)	Exploration and development capital	Gross wells drilled	Net wells drilled	Completion rate	12/31/06 proved reserves (Bcfe)


Mid-Continent	$350	302	186	97%	595
Permian Basin	331	167	119	96%	563
Gulf Coast	211	49	28	65%	105
Gulf of Mexico	128	16	6	44%	44
Western/Other	29	24	7	71%	142

	$1,049	558	346	91%	1,449

Company-wide, we participated in drilling 558 gross wells during 2006, with an overall completion rate of 91 percent. On a net basis, 316 of 346 total wells drilled during 2006 were completed as producers.

Our 2006 exploration and development expenditures (E&D) totaled $1,049 million and resulted in 201 Bcfe of proved reserve additions from drilling. Of total expenditures, 33 percent were invested in projects located in the Mid-Continent area; 32 percent in the Permian Basin; 20 percent in the Gulf Coast; and 12 percent in the Gulf of Mexico.

Mid-Continent

Our Mid-Continent operations cover the Anadarko and Arkoma basins of central and southeastern Oklahoma, the Hugoton Basin of southwest Kansas and the Texas Panhandle. We drilled 302 gross (186 net) Mid-Continent wells during 2006, completing 97 percent as producers. The bulk of this activity occurred in the Texas Panhandle and the Anadarko Basin. Full-year 2006 drilling investment in this area totaled $350 million, or 33% of total E&D capital.

We drilled 86 gross (59 net) Texas Panhandle wells with 98 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. Drilling activity in the Granite Wash remains active with 75-100 wells planned for 2007.

We drilled 92 gross (18 net) Anadarko Basin wells, of which 98 percent were completed as producers. The drilling activity mainly targets the Red Fork and Clinton Lake/Atoka formations at depths ranging from 12,000-15,000 feet. Gross proved reserves for these wells averaged 1.3 Bcfe. We expect to continue an active program in this area, drilling a similar number of wells in 2007 as in 2006.

We have a large inventory of recompletion and in-fill drilling locations in several exploitation projects, including the Cumberland, Madill and Caddo fields in southern Oklahoma and the Panoma field in the Texas Panhandle. The Panoma field area targets the Brown Dolomite formation at depths of approximately 2,200 feet. In 2006 we drilled 80 gross (79 net) wells at Panoma with a 100% success rate, increasing field production by 3.2 MMcfe/d.

Permian Basin

In the Permian Basin our operations cover both west Texas and southeast New Mexico. In total, we drilled 167 gross (119 net) wells completing 161 gross (115 net) as producers in the Permian Basin during 2006. Full-year 2006 drilling investment in this area totaled $331 million, or 32% of total E&D capital.

Southeast New Mexico drilling totaled 69 gross (47 net) wells with 94% being completed as producers. The primary formations we target in this area are comprised of Pennsylvanian-aged Morrow, Atoka and Strawn sandstones and conglomerate gas reservoirs at depths ranging from 11,500-14,000 feet.

In West Texas, a total of 98 gross (72 net) wells were drilled, of which 98% were successful. Included in the West Texas program is exploitation of the Westbrook Unit (90% working interest) where 44 infill wells have been drilled and completed in the Clearfork formation at 3,200 feet.

Other geologic targets in West Texas include the Devonian, Ellenburger, Bone Spring and Spraberry. We drilled or participated in 21 (seven net) Devonian wells in the Arbol de Nada field in Winkler and Ector Counties, Texas; five gross (five net) Ellenburger wells in the Will-O field in Val Verde County, Texas; and six gross (2.7 net) Bone Spring wells in the War-Wink field in Ward County, Texas.

Gulf Coast /Gulf of Mexico

Our onshore Gulf Coast focus area generally encompasses coastal Texas, south Louisiana and Mississippi. Our Gulf of Mexico operations are primarily located in offshore Louisiana in water

depths less than 300 feet and covering approximately one million gross acres. We obtained all of our offshore position through the Magnum Hunter acquisition. Our Gulf Coast and Gulf of Mexico effort is generally characterized by a greater reliance on 3-D seismic information for prospect generation, larger potential reserves per well, greater drilling depths and lower success rates.

During 2006 we drilled 49 gross (28 net) Gulf Coast wells, realizing a 65 percent success rate. A significant portion of the drilling occurred in Liberty County, Texas. Targeting the Yegua and Cook Mountain formations at 10,500 feet, we drilled 14 gross (nine net) Liberty County wells with a success rate of 64 percent. Gulf of Mexico 2006 drilling consisted of 16 gross (6.7 net) wells, of which 44% were successful.

Western/other

Our Western/Other region principally includes operations in California, Michigan, North Dakota and Wyoming. We drilled 24 gross (7.2 net) wells in the Western/Other region completing only 17 gross (0.2 net) as producers. Included in this area is the Riley Ridge Unit gas development project in Sublette County, Wyoming.

Production and pricing information

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

		Years ended December 31,

		2006		2005		2004

Production Volumes
	Gas (MMcf)		124,733		100,272		63,611
	Oil (MBbls)		6,529		4,804		2,641
	Equivalent (MMcfe)		163,907		129,096		79,457
Net Average Daily Volumes:
	Gas (MMcf)		341.7		274.7		173.8
	Oil (MBbl)		17.9		13.2		7.2
	Equivalent (MMcfe)		449.1		353.7		217.1
Average Sales Price
	Gas ($/Mcf)	$	6.50	$	8.05	$	5.76
	Oil ($/Bbl)	$	61.96	$	55.25	$	40.19

Combined oil and gas production volumes increased 27 percent to 449.1 MMcfe per day. Gas production in 2006 rose 24 percent to 341.7 MMcf per day and oil production increased 36 percent to 17,887 barrels per day. The increase in volumes primarily stems from the inclusion of production from Magnum Hunter operations beginning June 7, 2005 and exploration and development drilling.

The weighted-average gas price we received during 2006 was $6.50 per Mcf, which was 19 percent lower than the $8.05 per Mcf average price we received during 2005. Our annual average realized oil price during 2006 increased by 12 percent to $61.96 per barrel from $55.25 per barrel in 2005. Gas prices fell in 2006 as compared to 2005 as a result of a number of factors including lower demand because of warm winter weather, no significant hurricane

activity causing supply disruptions in the Gulf of Mexico and rising storage levels relative to historic averages.

We assumed Magnum Hunter's oil and gas commodity swap and collar contracts as part of the merger. These instruments did not qualify for hedge accounting treatment and as such they are not included in the above average sales prices. In third quarter of 2006, we entered into natural gas collars for calendar 2007 and 2008 for 80,000 and 40,000 MMBtu per day, respectively. The collars have been executed to settle against regional delivery points that correspond with our Mid-Continent production. Beginning in January 2007, these instruments will affect average sales prices to the extent that the benchmark prices fall outside the collar range.

	2006 average daily production

	2006 average daily production			Second-half 2005 avg. (MMcfe/d)
	Oil (MBbl/d)	Gas (MMcf/d)	Total (MMcfe/d)	Second-half 2005 avg. (MMcfe/d)

Mid-Continent	4.7	152.5	180.7	175.3
Permian Basin	8.1	83.8	132.4	130.1
Gulf Coast	3.2	61.8	80.7	84.4
Gulf of Mexico	1.6	36.2	45.9	37.9
Western/Other	0.3	7.4	9.4	10.5

	17.9	341.7	449.1	438.2

Our largest producing area is the Mid-Continent region which averaged 180.7 MMcfe per day making-up 40 percent of our total 2006 production. We grew our 2006 production in this region as a result of successful drilling programs in the Texas Panhandle and the Anadarko Basin. The Permian Basin contributed 132.4 MMcfe per day in 2006, which was 29 percent of our total production for this period. The current year production increased as a result of successful Morrow drilling in southeast New Mexico and West Texas secondary oil projects and development drilling. Gulf Coast production was 80.7 MMcfe per day during 2006, or 18 percent of total production. Gulf Coast volumes decreased in 2006 as a result of natural decline in our wells which were only partially offset by exploration success. Production from the Gulf of Mexico totaled 45.9 MMcfe per day, or 10 percent of our total 2006 production. Our second-half 2005 Gulf of Mexico production rate of 37.9 MMcfe per day was negatively impacted by hurricanes.

We have field offices located near our major concentrations of operated properties and have a centralized production management team in our Tulsa office.

Acquisitions and divestitures

We completed our acquisition of 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 of West Texas and southeast New Mexico and in 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 (73 percent proved developed).

Various interests in oil and gas properties were sold during 2006, with proceeds totaling $4.5 million. Proceeds from the sales were recorded as a reduction to oil and gas properties, as prescribed under the full cost method of accounting. Proved reserves associated with the sold properties approximated 2.5 billion cubic feet equivalent. We also recognized a $19.8 million gain on sale of certain limited partnership interests in oil and gas properties. Net sales consideration received via distributions from these affiliated partnerships totaled $59.3 million.

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. Revenues are recognized as gas is delivered and are reflected in our income statement net of gas purchases.

We sell our oil and gas to a broad portfolio of customers. Our largest customer accounted for 11 percent of 2006 revenues. Because over two-thirds 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 734 people on December 31, 2006. 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 financial and human resources substantially larger than ours. The effect of these competitive factors on our business 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. Our oil and gas properties are subject to customary royalty interests contracted for in connection with the acquisition of title, 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 many varying and complex federal and state regulations. In recent years, we have been most directly affected by federal and state environmental regulations and energy conservation rules. We are indirectly affected by federal and state regulation of pipelines and other oil and gas transportation systems. Compliance with such laws and regulations increases our overall cost of business, but has not had a material adverse effect on our operations or financial condition.

Most of the states in which we conduct operations regulate the size of well spacing units, drilling density within productive formations and the unitization or pooling of properties. In addition, state conservation laws 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 often 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. To date, we have not expended any material amounts to comply with such regulations, and our management does not currently anticipate that future compliance will have a materially adverse effect on our consolidated financial position or results of operations.

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.

Gas gathering and transportation. The Federal Energy Regulatory Commission (FERC) requires interstate gas pipelines to provide open access transportation. Interstate pipelines have implemented this requirement by modifying their tariffs and implementing new services and rates. These changes have provided 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 federal regulatory oversight, our natural gas gathering systems and services may receive regulatory scrutiny by state agencies.

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.

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.

Federal and state income taxation

Cimarex and the petroleum industry in general are affected by both federal and state income tax laws. 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.

Properties

Oil and gas properties and reserves

All of our proved reserves and undeveloped acreage are located in the United States. We have varying levels of ownership interests in our properties consisting of working, royalty and overriding royalty interests. We operate the wells that comprise 73 percent of our proved reserves.

Our engineers estimate our proved oil and gas reserve quantities in accordance with guidelines established by the SEC. DeGolyer and MacNaughton, independent petroleum engineers, reviewed our reserve estimates for those properties that comprised at least 80 percent of the discounted value of the projected future net cash flow before income taxes as of December 31, 2006. All information in this prospectus relating to oil and gas reserves is net to our interest

unless stated otherwise. The following table sets forth the present value and estimated volume of our oil and gas proved reserves:

		Years ended December 31,

		2006		2005		2004

Total Proved Reserves—
	Gas (MMcf)		1,090,362		1,004,482		364,641
	Oil, condensate and NGLs (MBbls)		59,797		64,710		14,063
	Equivalent (MMcfe)		1,449,146		1,392,742		449,020
Standardized measure of discounted future net cash flow after-tax, discounted at 10 percent (in thousands)		$	2,200,889	$	3,028,100	$	798,033
Average price used in calculation of future net cash flow—
	Gas ($/Mcf)	$	5.54	$	7.89	$	5.58
	Oil ($/Bbl)	$	56.91	$	57.65	$	40.76

Significant properties

As of December 31, 2006, 90 percent of proved reserves were located in the Mid-Continent, Permian Basin, Gulf Coast and Gulf of Mexico regions. In total we owned an interest in 13,194 gross (4,757 net) productive oil and gas wells.

The following table summarizes our estimated proved oil and gas reserves by region as of December 31, 2006.

	Oil (MBbl)	Gas (MMcf)	Equivalent (MMcfe)	Percent of proved reserves


Mid-Continent	8,709	542,447	594,701	41%
Permian Basin	44,351	296,969	563,076	39%
Gulf Coast	4,671	76,640	104,663	7%
Gulf of Mexico	964	38,111	43,895	3%
Western/Other	1,102	136,195	142,811	10%

	59,797	1,090,362	1,449,146	100%

Our ten largest fields hold 30 percent of our total equivalent proved reserves. We are the principal operator of our production in each of these fields (except Jo-Mill). The table below summarizes certain key statistics about these properties.

Field	Region	% of total proved reserves	Avg. working interest	Avg. depth (feet)	Primary formation


Hugoton	Mid-Continent	4.3%	59%	2,600	Chase
Hemphill	Mid-Continent	4.1%	95%	11,000	Granite Wash
Panhandle East	Mid-Continent	3.5%	98%	2,400	Brown Dolomite
Eola-Robberson	Mid-Continent	3.2%	95%	5,500-11,000	Bromide/McLish/Oil Creek
Carlsbad South	Permian	2.8%	58%	11,500	Morrow/Atoka
Red Deer Creek	Mid-Continent	2.8%	47%	11,000	Granite Wash
Quail Ridge	Permian	2.6%	59%	13,000	Morrow
Jo-Mill	Permian	2.5%	13%	7,500	Spraberry
Mendota NW	Mid-Continent	2.3%	71%	11,000	Granite Wash
Westbrook	Permian	2.1%	90%	3,500	Clearfork

		30.2%

Acreage

The following table sets forth as of December 31, 2006, the gross and net acres of both developed and undeveloped leases held by us. Gross acres are the total number of acres in which we own a working interest. Net acres are the gross acres multiplied by our working interest.

		Undeveloped acreage		Developed acreage		Total acreage

		Gross	Net	Gross	Net	Gross	Net

Mid-Continent
	Kansas	3,480	2,415	158,391	105,601	161,871	108,016
	Oklahoma	103,772	85,182	395,645	168,255	499,417	253,437
	Texas	144,826	106,218	232,402	110,785	377,228	217,003

		252,078	193,815	786,438	384,641	1,038,516	578,456
Permian Basin
	New Mexico	86,178	64,943	144,645	94,115	230,823	159,058
	Texas	53,794	37,850	232,664	156,045	286,458	193,895

		139,972	102,793	377,309	250,160	517,281	352,953
Gulf Coast
	Louisiana	22,063	17,114	21,521	6,356	43,584	23,470
	Texas	81,473	33,938	164,734	61,674	246,207	95,612
	Mississippi	6,027	3,779	25,583	6,539	31,610	10,318

		109,563	54,831	211,838	74,569	321,401	129,400
Gulf of Mexico		711,140	438,125	324,614	110,709	1,035,754	548,834
Western/Other
	Arkansas	—	—	6,719	2,115	6,719	2,115
	Arizona	914,695	914,695	—	—	914,695	914,695
	California	35,715	30,678	8,770	6,752	44,485	37,430
	Colorado	96,690	6,759	26,497	6,498	123,187	13,257
	Illinois	1,782	1,191	554	183	2,336	1,374
	Indiana	175	175	344	310	519	485
	Michigan	31,803	31,686	549	549	32,352	32,235
	Montana	49,449	16,298	18,858	7,735	68,307	24,033
	Nebraska	4,560	116	2,118	168	6,678	284
	Nevada	160	1	560	1	720	2
	New Mexico	1,649,340	1,621,646	13,574	2,281	1,662,914	1,623,927
	North Dakota	64,741	18,152	25,818	2,706	90,559	20,858
	South Dakota	10,583	9,329	2,420	379	13,003	9,708
	Utah	120,625	63,621	20,159	2,223	140,784	65,844
	Wyoming	252,551	31,542	118,416	24,239	370,967	55,781

		3,232,869	2,745,889	245,356	56,139	3,478,225	2,802,028

		4,445,622	3,535,453	1,945,555	876,218	6,391,177	4,411,671

Gross wells drilled

We participated in drilling the following number of gross wells during calendar years 2006, 2005, and 2004:

	Exploratory			Developmental

	Productive	Dry	Total	Productive	Dry	Total

Year ended December 31, 2006	20	32	52	490	16	506
Year ended December 31, 2005	55	20	75	283	24	307
Year ended December 31, 2004	12	11	23	177	21	198

We were in the process of drilling 30 gross (16 net) wells at December 31, 2006.

Net wells drilled

The number of net wells we drilled during calendar years 2006, 2005, and 2004 are shown below:

	Exploratory			Developmental

	Productive	Dry	Total	Productive	Dry	Total

Year ended December 31, 2006	12.4	23.9	36.3	303.7	6.2	309.9
Year ended December 31, 2005	33.2	15.6	48.8	144.8	16.8	161.6
Year ended December 31, 2004	6.8	6.5	13.3	78.8	12.1	90.9

Productive wells

We have working interests in the following productive wells as of December 31, 2006:

	Gas		Oil

	Gross	Net	Gross	Net

Mid-Continent	3,396	1,721	1,017	529
Permian	1,023	557	6,109	1,629
Gulf Coast	525	138	186	91
Gulf of Mexico	124	27	38	6
Western/Other	144	24	632	35

	5,212	2,467	7,982	2,290

Management

Our directors and executive officers as of March 21, 2007 were:

Name	Age	Office


F.H. Merelli	70	Chairman of the Board, Chief Executive Officer and President
Joseph R. Albi	48	Executive Vice President-Operations
Thomas E. Jorden	49	Executive Vice President-Exploration
Stephen P. Bell	52	Senior Vice President, Business Development and Land
Paul Korus	50	Vice President, Chief Financial Officer, and Treasurer
Gary R. Abbott	34	Vice President, Corporate Engineering
Richard S. Dinkins	62	Vice President, Human Resources
James H. Shonsey	55	Vice President, Chief Accounting Officer and Controller
Jerry Box	68	Director
Glenn A. Cox	77	Director
Cortlandt S. Dietler	85	Director
Hans Helmerich	48	Director
David A. Hentschel	73	Director
Paul D. Holleman	75	Director
Monroe W. Robertson	57	Director
Michael J. Sullivan	66	Director
L. Paul Teague	72	Director

There are no family relationships by blood, marriage, or adoption among any of the above directors or executive officers. Our board of directors consists of ten members and is divided into three classes: Class I, Class II and Class III directors. At each annual meeting of stockholders, a class of directors is elected for a term expiring at the annual meeting in the third year following the year of election. Each director holds office until his successor is elected and qualifies. All executive officers are elected annually by the board of directors to serve for one year or until a successor is elected and qualified. There is no arrangement or understanding between any of the directors or executive officers and any other person pursuant to which he was selected as a director or executive officer.

Executive officers

F.H. Merelli was elected chairman of the board, chief executive officer, and president on September 30, 2002. Prior to its merger with Cimarex, Mr. Merelli served as chairman and chief executive officer of Key Production Company, Inc. from September 1992 to September 2002. From June 1988 to July 1991 he was president and chief operating officer of Apache Corporation.

Joseph R. Albi was named executive vice president of operations on March 1, 2005. Since December 8, 2003, Mr. Albi served as senior vice president of corporate engineering. From September 30, 2002 to December 8, 2003, Mr. Albi served as vice president of engineering. Prior to September 30, 2002, Mr. Albi was with Key Production Company, Inc. where he served

as vice president of engineering (October 1999 to September 2002) and manager of engineering (June 1994 to October 1999).

Thomas E. Jorden was named executive vice president of exploration on December 8, 2003 and has served in a similar capacity since September 30, 2002. Prior to September 2002, Mr. Jorden was with Key Production Company, Inc., where he served as vice president of exploration (October 1999 to September 2002) and chief geophysicist (November 1993 to September 1999). Prior to joining Key, Mr. Jorden was with Union Pacific Resources.

Stephen P. Bell was elected senior vice president of business development and land on September 30, 2002. Prior to its merger with Cimarex, Mr. Bell had been with Key Production Company, Inc. since February 1994. In September 1999, he was appointed senior vice president, business development and land. From February 1994 to September 1999, he served as vice president, land.

Paul Korus was elected vice president, chief financial officer and treasurer on September 30, 2002. Mr. Korus was vice president and chief financial officer of Key Production Company, Inc. from September 1999 to September 2002. Prior to September 1999 and since June 1995, Mr. Korus was an equity research analyst with Petrie Parkman & Co., an investment banking firm.

Gary R. Abbott was elected vice president of corporate engineering on March 1, 2005. Since January 2002, Mr. Abbott served as manager, corporate reservoir engineering. From April 1999 to January 2002, Mr. Abbott was a reservoir engineer with Key Production Company, Inc.

Richard S. Dinkins was named vice president of human resources on December 8, 2003. Mr. Dinkins joined Key Production Company, Inc. in March 2002 as its director of human resources and continued in that position with Cimarex commencing in September 2002. Prior to joining Key and since February 1999, Mr. Dinkins was with Sprint.

James H. Shonsey was named vice president in April, 2006. Mr. Shonsey was elected chief accounting officer and controller on May 28, 2003. From 2001 to May 2003, Mr. Shonsey was chief financial officer of The Meridian Resource Corporation; and from 1997 to 2001, he served as the chief financial officer of Westport Resources Corporation.

Directors

Jerry Box has served as our director since 2005. He served as Chairman of Magnum Hunter Resources, Inc. from October 2004 until June 2005, and as a director of Magnum Hunter Resources from March 1999 to June 2005. Mr. Box served as President, COO and a director of Oryx Energy Company from February 1998 to March 1999. He had previously held a number of managerial and executive positions with Oryx Energy and its predecessor company, Sun Oil Company. Currently, Mr. Box is a director and chairman of the compensation committee and member of the nominating and governance committee of Newpark Resources, Inc., a Houston, Texas based oilfield services company traded on the NYSE.

Glenn A. Cox has served as our director since 2002. He served as President and Chief Operating Officer of Phillips Petroleum Company from June 1985 until his retirement in 1991. He also served as Chief Financial Officer of Phillips Petroleum Company from June 1980 to May 1985. Mr. Cox is currently a director and chairman of audit committee of Helmerich & Payne, Tulsa,

Oklahoma, and previous director and member of audit committees of The Williams Companies, a gas gathering and exploration and production company located in Tulsa, Oklahoma, and Union Texas Petroleum, an exploration and production company located in Houston, Texas.

Cortlandt S. Dietler has served as our director since 2002. He currently serves as the owner of Poison Spider Oil Company LLC. From April 1995 through September 1, 2006, he was Chairman of the Board of TransMontaigne, Inc. He also served as Chief Executive Officer of TransMontaigne from April 1995 through September 1999. Mr. Dietler is currently a director of Hallador Petroleum Company, a Denver, Colorado exploration and production company traded on the OTC Bulletin Board, and Forest Oil Corporation, a Denver, Colorado exploration and production company traded on the NYSE. He also serves as chairman of the nominating and corporate governance committee and the compensation committee of Forest Oil.

Hans Helmerich has served as our director since 2002. He has served as a director of Helmerich & Payne since 1987, and as President and Chief Executive Officer of Helmerich & Payne since 1989. Mr. Helmerich also serves as a director of Atwood Oceanics, Inc., Houston, Texas, an international offshore drilling company, and as trustee of The Northwestern Mutual Life Insurance Company.

David A. Hentschel has served as our director since 2002. He served as Chairman and Chief Executive Officer of Occidental Oil and Gas Corporation from 1997 until 1999, when he retired. He also served as President and Chief Executive Officer of Canadian Occidental Petroleum, Ltd, now known as Nexen, from 1995 until 1997. Mr. Hentschel is currently a director of Nexen Inc., a global energy company located in Calgary, Alberta, Canada.

Paul D. Holleman has served as our director since 2002. He served as senior partner of Holme Roberts & Owen LLP, a Denver law firm, until 2000, when he retired. At Holme Roberts, he served as legal counsel to Key Production Company, Inc. and other oil and gas companies. Other positions in his 40 years with Holme Roberts included Chairman of the Natural Resources Department and member of the executive committee.

Monroe W. Robertson has served as our director since 2005. He is currently a private investor. Mr. Robertson was with Key Production Company, Inc., a company acquired by Cimarex in 2002, for 10 years until retirement in March 2002. He held the positions of President, Chief Operating Officer, Senior Vice President and Principal Financial Officer.

Michael J. Sullivan has served as our director since 2002. He has been a member of the Denver law firm, Rothgerber Johnson & Lyons LLP, since 2001, most recently as partner of the Casper office. He served as United States Ambassador to Ireland from 1998 until 2001. Prior to that, he practiced law with Brown, Drew, Apostolos, Massey & Sullivan from 1964 to 1986 and from 1995 until 1998. Mr. Sullivan was Governor of Wyoming from 1987 through 1995. He currently serves as a director of Kerry Group plc, a global food and food ingredients producer headquartered in Tralee, Ireland; director and member of audit committee and governance committee of Allied Irish Bank Group, Dublin, Ireland; director and member of the governance committee of First Interstate BancSystem, Billings, Montana and director and member of the governance and audit committee of Slatten Construction, Inc., Great Falls, Montana.

L. Paul Teague has served as our director since 2002. He was with Texaco Exploration & Producing Inc. for 35 years until his retirement in 1994. He held the positions of Vice President, Western Region; Division Manager of the New Orleans Division, Eastern Producing Department; Vice President, New Orleans Producing Division of Texaco USA; and Vice President, Producing Department, Texaco USA in Houston.

Stock ownership of directors, management
and certain beneficial owners

We have one class of voting securities outstanding. On March 21, 2007, there were 83,444,376 shares of common stock outstanding, with each share entitled to one vote.

Beneficial ownership by executive officers and directors

The following table shows, as of March 21, 2007, the number of shares of common stock "beneficially owned," as determined in accordance with Rule 13d-3 under the Securities Exchange Act of 1934, by our named executive officers, the directors, and all executive officers and directors, as a group:

Name of beneficial owner	Shares owned(1)		Option shares(2)	Beneficial ownership total		Percent of class


Named executive officers
F. H. Merelli (also director)	511,029		462,920	973,949		1%
Joseph R. Albi	67,371		71,100	138,471		<1%
Stephen P. Bell	64,500		72,800	137,300		<1%
Thomas E. Jorden	71,130		54,600	125,730		<1%
Paul Korus	83,515		0	83,515		<1%
Directors
Jerry Box	10,901		—	10,901		<1%
Glenn A. Cox	9,472		10,000	19,472		<1
Cortlandt S. Dietler	132,285		30,000	162,285		<1%
Hans Helmerich	84,670	(3)	10,000	94,670	(3)	<1%
David A. Hentschel	8,285		10,000	18,285		<1%
Paul D. Holleman	8,285		35,000	43,285		<1%
Monroe W. Robertson	5,862		—	5,862		<1%
Michael J. Sullivan	4,479		10,000	14,479		<1%
L. Paul Teague	48,667		16,667	65,334		<1%
All executive officers & directors as a group (17 persons)	1,233,099		852,087	2,085,186		2%

(1): Includes restricted stock, direct and indirect ownership of common stock and equivalent shares of common stock held by the trustee for the benefit of the named individual in the Cimarex Energy Co. 401(k) Plan. Does not include restricted stock units held by executive officers or deferred compensation units held by some directors. See Equity-Related Interests table below.
(2): Shares of common stock that could be purchased by the exercise of vested stock options within the 60-day period following March 21, 2007 under the Cimarex Energy Co. 2002 Stock Incentive Plan.
(3): Includes 7,865 shares held for various trusts for immediate family members of which Mr. Helmerich is trustee and 1,072 shares held by a family trust of which Mr. Helmerich is a co-trustee. Also includes 11,450 shares owned by Mr. Helmerich's wife, and Mr. Helmerich disclaims beneficial ownership of these shares.

Beneficial owners of more than five percent

Third Avenue Management LLC is the only stockholder who beneficially owns more than five percent of our outstanding shares of common stock. The following table provides information

regarding Third Avenue Management's stock ownership and is based on its filing with the Securities and Exchange Commission.

	Voting authority		Dispositive authority

					Total amount of beneficial ownership
						Percent of class
Name and address	Sole	Shared	Sole	Shared		Percent of class

Third Avenue Management LLC 622 Third Avenue New York, NY 10017	4,587,179	0	4,608,879	0	4,608,879	5.56%

Equity and equity-related interests held by executive officers and directors

The following table shows, as of March 21, 2007, vested and unvested equity interests and common stock held by each of our named executive officers, the directors and all of the executive officers and directors as a group:

		Restricted stock units/deferred comp units(3)(4)		Shares underlying stock options

	Unvested restricted stock(1)(2)
							Common stock
		Vested	Unvested	Vested	Unvested	401(k)	Common stock	Total

Named executive officers
F. H. Merelli (also director)	120,000	168,960	42,240	462,920	84,480	13,400	377,629	1,269,366
Joseph R. Albi	60,000	—	45,500	71,100	18,200	5,112	2,259	202,171
Stephen P. Bell	60,000	—	45,500	72,800	18,200	—	4,500	201,000
Thomas E. Jorden	60,000	—	45,500	54,600	18,200	7,308	3,822	189,430
Paul Korus	60,000	—	45,500	0	18,200	0	23,515	147,215
Directors
Jerry Box	3,639	—	—	—	—	—	7,262	10,901
Glenn A. Cox	4,406	—	—	10,000	—	—	5,066	19,472
Cortlandt S. Dietler	4,406	—	—	30,000	—	—	127,879	162,285
Hans Helmerich	1,319	1,219	3,087	10,000	—	—	83,351	98,976
David A. Hentschel	4,406	—	—	10,000	—	—	3,879	18,285
Paul D. Holleman	4,406	—	—	35,000	—	—	3,879	43,285
Monroe W. Robertson	3,302	—	—	—	—	—	2,830	5,862
Michael J. Sullivan	1,319	1,219	3,087	10,000	—	—	3,160	18,785
L. Paul Teague	3,796	1,219	610	16,667	—	—	44,871	67,163
All executive officers & directors as a group (17 persons)	507,459	172,617	312,774	852,087	185,080	28,387	697,233	2,755,657

(1): The restricted stock held by the executive officers is subject to three-year cliff vesting and the satisfaction of performance goals.
(2): The restricted stock held by the directors vests in three equal annual installments, beginning with the first anniversary from the grant date.
(3): The restricted stock units vest five years from the date of grant and are payable in shares of common stock on the eighth anniversary of the date of grant.
(4): The deferred compensation units held by certain directors vest in three equal annual installments and represent the right to receive one share of Cimarex common stock at the time provided in the director's deferred compensation election.

Transactions with related persons

During 2006, no related person had a direct or indirect material interest in any transaction with Cimarex.

Description of other indebtedness

Senior revolving credit facility

Our senior revolving credit facility provides for $500 million of long-term committed credit. The facility is scheduled to mature on July 1, 2010 and is secured by mortgages on certain oil and gas properties and the stock of certain wholly-owned operating subsidiaries. At December 31, 2006, there were outstanding borrowings of $95 million under the senior revolving credit facility at a weighted average interest rate of approximately 6.75%. We also had letters of credit for approximately $5 million posted against the borrowing base, leaving an unused borrowing amount of approximately $400 million at December 31, 2006.

The credit facility agreement contains both financial and non-financial covenants. We continue to comply with these covenants and do not view them as materially restrictive.

9.6% senior notes due 2012

Year		Percentage


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

Floating rate convertible senior notes due 2023

Description of notes

The Company will issue the Notes under the Indenture (the "Indenture") among itself, the Subsidiary Guarantors and U.S. Bank National Association, as trustee (the "Trustee"). The terms of the Notes include those expressly set forth in the Indenture and those made part of the Indenture by reference to the Trust Indenture Act of 1939, as amended (the "Trust Indenture Act"). The Indenture is unlimited in aggregate principal amount, although the issuance of notes in this offering will be limited to $350 million. We may issue an unlimited principal amount of additional notes having identical terms and conditions as the Notes other than issue date, issue price and the first interest payment date (the "Additional Notes"). We will only be permitted to issue such Additional Notes if at the time of such issuance, we are in compliance with the covenants contained in the Indenture. Any Additional Notes will be part of the same issue as the Notes that we are currently offering and will vote on all matters with the holders of the Notes.

This description of notes is intended to be a useful overview of the material provisions of the Notes and the Indenture. Since this description of notes is only a summary, you should refer to the Indenture for a complete description of the obligations of the Company and your rights. We have filed a copy of the Indenture as an exhibit to the registration statement which includes this Prospectus.

You will find the definitions of capitalized terms used in this description under the heading "—Certain definitions." For purposes of this description, references to "the Company," "we," "our" and "us" refer only to Cimarex Energy Co. and not to its subsidiaries. Certain defined terms used in this description but not defined herein have the meanings assigned to them in the Indenture.

General

The notes. The Notes:

•: are general unsecured, senior obligations of the Company;
•: are limited to an aggregate principal amount of $350 million, subject to our ability to issue Additional Notes;
•: mature on May 1, 2017;
•: will be issued in denominations of $2,000 and integral multiples of $1,000 in excess thereof;
•: will be represented by one or more registered Notes in global form, but in certain circumstances may be represented by Notes in definitive form. See "Book-entry, delivery and form;"
•: rank equally in right of payment to any future senior Indebtedness of the Company, without giving effect to collateral arrangements;
•: are unconditionally guaranteed on a senior unsecured basis by each Subsidiary Guarantor. See "Subsidiary guarantees;" and

•: are expected to be eligible for trading in The PORTAL Market.

Interest. Interest on the Notes will compound semi-annually and:

•: accrue at the rate of 7¹/8% per annum;
•: accrue from the date of original issuance or, if interest has already been paid, from the most recent interest payment date;
•: be payable in cash semi-annually in arrears on May 1 and November 1, commencing on November 1, 2007;
•: be payable to the holders of record on the April 15 and October 15 immediately preceding the related interest payment dates; and
•: be computed on the basis of a 360-day year comprised of twelve 30-day months.

Payments on the notes; paying agent and registrar

We will pay principal of, premium, if any, and interest on the Notes at the office or agency designated by the Company in the Borough of Manhattan, The City of New York, except that we may, at our option, pay interest on the Notes by check mailed to holders of the Notes at their registered address as it appears in the Registrar's books. We have initially designated the corporate trust office of the Trustee in New York, New York to act as our Paying Agent and Registrar. We may, however, change the Paying Agent or Registrar without prior notice to the holders of the Notes, and the Company or any of its Restricted Subsidiaries may act as Paying Agent or Registrar.

We will pay principal of, premium, if any, and interest on, Notes in global form registered in the name of or held by The Depository Trust Company or its nominee in immediately available funds to The Depository Trust Company or its nominee, as the case may be, as the registered holder of such global Note.

Transfer and exchange

A holder may transfer or exchange Notes in accordance with the Indenture. The Registrar and the Trustee may require a holder, among other things, to furnish appropriate endorsements and transfer documents. No service charge will be imposed by the Company, the Trustee or the Registrar for any registration of transfer or exchange of Notes, but the Company may require a holder to pay a sum sufficient to cover any transfer tax or other governmental taxes and fees required by law or permitted by the Indenture. The Company is not required to transfer or exchange any Note selected for redemption. Also, the Company is not required to transfer or exchange any Note for a period of 15 days before a selection of Notes to be redeemed.

The registered holder of a Note will be treated as the owner of it for all purposes.

Optional redemption

Except as described below, the Notes are not redeemable until May 1, 2012. On and after May 1, 2012, the Company may redeem all or, from time to time, a part of the Notes upon not less than 30 nor more than 60 days' notice, at the following redemption prices (expressed as a percentage of principal amount) plus accrued and unpaid interest on the Notes, if any, to the

applicable redemption date (subject to the right of holders of record on the relevant record date to receive interest due on the relevant interest payment date), if redeemed during the twelve-month period beginning on May 1 of the years indicated below:

Year		Percentage


2012		103.563%
2013		102.375%
2014		101.188%
2015 and thereafter		100.00%

Prior to May 1, 2010, the Company may on any one or more occasions redeem up to 35% of the original principal amount of the Notes (including the original principal amount of any Additional Notes) with the Net Cash Proceeds of one or more Equity Offerings at a redemption price of 107.125% of the principal amount thereof, plus accrued and unpaid interest, if any, to the redemption date (subject to the right of holders of record on the relevant record date to receive interest due on the relevant interest payment date); provided that

(1): at least 65% of the original principal amount of the Notes (including the original principal amount of any Additional Notes) remains outstanding immediately after each such redemption; and
(2): the redemption occurs within 60 days after the closing of such Equity Offering.

If the optional redemption date is on or after an interest record date and on or before the related interest payment date, the accrued and unpaid interest, if any, will be paid to the Person in whose name the Note is registered at the close of business, on such record date, and no additional interest will be payable to holders whose Notes will be subject to redemption by the Company.

In the case of any partial redemption, selection of the Notes for redemption will be made by the Trustee in compliance with the requirements of the principal national securities exchange, if any, on which the Notes are listed or, if the Notes are not listed, then on a pro rata basis, by lot or by such other method as the Trustee in its sole discretion will deem to be fair and appropriate, although no Note of $2,000 in original principal amount or less will be redeemed in part. If any Note is to be redeemed in part only, the notice of redemption relating to such Note will state the portion of the principal amount thereof to be redeemed. A new Note in principal amount equal to the unredeemed portion thereof will be issued in the name of the holder thereof upon cancellation of the original Note.

In addition, at any time prior to May 1, 2012, the Notes may be redeemed, in whole but not in part, at the option of the Company upon not less than 30 nor more than 60 days' prior notice mailed by first-class mail to each holder of Notes at its registered address, at a redemption price equal to 100% of the principal amount of the Notes redeemed plus the Applicable Premium plus accrued and unpaid interest, if any, to the redemption date (subject to the right of holders of record on the relevant record date to receive interest due on the relevant interest payment date).

"Applicable Premium" means, with respect to a Note on any date of redemption prior to May 1, 2012, the greater of (1) 1.0% of the principal amount of such Note and (2) the excess

of (a) the present value at such time of (i) the redemption price of such Note on May 1, 2012 (such redemption price being described under the first paragraph under "Optional redemption") plus (ii) all required interest payments due on such Note through May 1, 2012 (but excluding accrued and unpaid interest to the redemption date), computed using a discount rate equal to the Treasury Rate plus 50 basis points, over (b) the then-outstanding principal amount of such Note.

"Treasury Rate" means the yield to maturity at the time of computation of United States Treasury securities with a constant maturity (as compiled and published in the most recent Federal Reserve Statistical Release H.15 (519) that has become publicly available at least two business days prior to the redemption date (or, if such Statistical Release is no longer published, any publicly available source of similar market data)) most nearly equal to the period from the redemption date to May 1, 2012; provided, however, that if the period from the redemption date to May 1, 2012 is not equal to the constant maturity of a United States Treasury security for which a weekly average yield is given, the Treasury Rate shall be obtained by linear interpolation (calculated to the nearest one-twelfth of a year) from the weekly average yields of United States Treasury securities for which such yields are given, except that if the period from the redemption date to May 1, 2012 is less than one year, the weekly average yield on actually traded United States Treasury securities adjusted to a constant maturity of one year shall be used.

The Company is not required to make mandatory redemption payments or sinking fund payments with respect to the Notes.

The Company and its Subsidiaries and Affiliates may acquire Notes by means other than a redemption, whether by tender offer, open market purchases, negotiated transactions or otherwise, in accordance with applicable securities laws, so long as such acquisition does not otherwise violate the terms of the Indenture.

Ranking

The Notes will be general unsecured obligations of the Company that rank senior in right of payment to all existing and future Indebtedness that is expressly subordinated in right of payment to the Notes. The Notes will rank equally in right of payment with all existing and future liabilities of the Company that are not so subordinated and will be effectively subordinated to all of our secured Indebtedness and liabilities of our Subsidiaries that do not guarantee the Notes. Each of the Subsidiary Guarantees will be effectively subordinated to all of the secured Indebtedness of the Subsidiary Guarantor. In the event of bankruptcy, liquidation, reorganization or other winding up of the Company or its Subsidiary Guarantors or upon a default in payment with respect to, or the acceleration of, any Indebtedness under the Senior Secured Credit Agreement or other senior secured Indebtedness, the assets of the Company and its Subsidiary Guarantors that secure such senior secured Indebtedness will be available to pay obligations on the Notes and the Subsidiary Guarantees only after all Indebtedness under such Senior Secured Credit Agreement and other senior secured Indebtedness has been repaid in full from such assets. However, payment from the money or the proceeds of U.S. Government Obligations held in any defeasance trust (as described under "Defeasance" below) will not be subordinated to any Senior Indebtedness or subject to these restrictions. We advise you that there may not be sufficient assets remaining to pay amounts due on any or all the Notes and the Subsidiary Guarantees then outstanding.

Assuming that we had completed the offering of the Notes and applied the net proceeds we receive therefrom in the manner described under "Use of proceeds," as of December 31, 2006:

•: our outstanding Indebtedness (including, without limitation, Indebtedness under the Indenture and the Notes) would have been $487.9 million, none of which would have been secured;
•: Restricted Subsidiaries would have had approximately $82.6 million of liabilities (excluding intercompany liabilities and Guarantees of the Senior Secured Credit Agreement and the Indenture); and
•: Non-Guarantor Restricted Subsidiaries would not have had any outstanding Indebtedness or liabilities (other than inter-company Indebtedness or liabilities).

Subsidiary guarantees

The Subsidiary Guarantors will, jointly and severally, unconditionally guarantee on a senior unsecured basis the Company's obligations under the Notes and all obligations under the Indenture. Such Subsidiary Guarantors will agree to pay, in addition to the amount stated above, any and all costs and expenses (including, without limitation, reasonable counsel fees and expenses) Incurred by the Trustee or the holders in enforcing any rights under the Subsidiary Guarantees. The obligations of the Subsidiary Guarantors under the Subsidiary Guarantees will rank equally in right of payment with all existing and future Indebtedness of such Subsidiary Guarantors that is not expressly subordinated to the obligations arising under the Subsidiary Guarantees and will be effectively subordinated to all of our Subsidiary Guarantors' secured Indebtedness.

Assuming that we had completed the offering of the Notes and applied the net proceeds we receive therefrom in the manner described under "Use of proceeds," as of December 31, 2006, there would have been no outstanding Indebtedness of Subsidiary Guarantors.

Although the Indenture will limit the amount of indebtedness that the Company and any Restricted Subsidiaries may Incur, such indebtedness may be substantial.

The obligations of each Subsidiary Guarantor under its Subsidiary Guarantee will be limited as necessary to prevent that Subsidiary Guarantee from constituting a fraudulent conveyance or fraudulent transfer under applicable law. See "Risk factors—Risks relating to our indebtedness and the notes—A subsidiary guarantee could be voided if it constitutes a fraudulent transfer under U.S. bankruptcy or similar state law, which would prevent the holders of the notes from relying on that subsidiary to satisfy claims."

In the event a Subsidiary Guarantor is sold or disposed of (whether by merger, consolidation, the sale of its Capital Stock or the sale of all or substantially all of its assets (other than by lease) and whether or not the Subsidiary Guarantor is the surviving corporation in such transaction) to a Person which is not the Company or a Restricted Subsidiary of the Company (after giving effect to the sale or other disposition), such Subsidiary Guarantor will be released from its obligations under its Subsidiary Guarantee if:

(1): the sale or other disposition is in compliance with the Indenture, including the covenants "Certain covenants—Limitation on sales of assets and subsidiary stock" (it being understood that only such portion of the Net Available Cash as is required to be applied on or before the

date of such release in accordance with the terms of the Indenture needs to be applied in accordance therewith at such time), "Certain covenants—Limitation on sales of capital stock of restricted subsidiaries" and "Certain covenants—Merger and consolidation;" and

(2): all the obligations of such Subsidiary Guarantor under all Credit Facilities and any other agreements evidencing any other Indebtedness of the Company or its Restricted Subsidiaries (after giving effect to the sale or other disposition) terminate upon consummation of such transaction.

In the event that a Subsidiary Guarantor is released and discharged in full from all of its obligations under its Guarantees of the Senior Secured Credit Agreement and all other Indebtedness of the Company and its other Restricted Subsidiaries, then such Subsidiary Guarantor will be released from its obligations under its Subsidiary Guarantee as specified under the covenant "Certain covenants—Future subsidiary guarantors."

In addition, a Subsidiary Guarantor will be released from its obligations under the Indenture and its Subsidiary Guarantee if the Company designates such Subsidiary as an Unrestricted Subsidiary and such designation complies with the other applicable provisions of the Indenture or in connection with any legal defeasance of the Notes or upon satisfaction and discharge of the Indenture, each in accordance with the terms of the Indenture.

Book-entry, delivery and form

The Notes will be represented by one or more global notes in registered, global form without interest coupons (collectively, the "Global Notes"). The Global Notes initially will be deposited upon issuance with the Trustee as custodian for The Depository Trust Company, or DTC, in New York, New York, and registered in the name of DTC or its nominee, in each case for credit to an account of a direct or indirect participant as described below.

Except as set forth below, the Global Notes may be transferred, in whole and not in part, only to another nominee of DTC or to a successor of DTC or its nominee. Beneficial interests in the Global Notes may not be exchanged for Notes in certificated form except in the limited circumstances described below. See "—Exchange of global notes for certificated notes." In addition, transfers of beneficial interests in the Global Notes will be subject to the applicable rules and procedures of DTC and its direct or indirect participants, which may change from time to time.

The Notes may be presented for registration of transfer and exchange at the offices of the Registrar.

Depository procedures

The following description of the operations and procedures of DTC is provided solely as a matter of convenience. These operations and procedures are solely within the control of the respective settlement systems and are subject to changes by them. We take no responsibility for these operations and procedures and urge investors to contact the system or their participants directly to discuss these matters.

DTC has advised us that DTC is a limited-purpose trust company organized under the laws of the State of New York, a "banking organization" within the meaning of the New York Banking Law, a member of the Federal Reserve System, a "clearing corporation" within the meaning of

the Uniform Commercial Code and a "clearing agency" registered pursuant to the provisions of Section 17A of the Exchange Act. DTC was created to hold securities for its participating organizations (collectively, the "participants") and to facilitate the clearance and settlement of transactions in those securities between participants through electronic book-entry changes in accounts of its participants. The participants include securities brokers and dealers, banks, trust companies, clearing corporations and certain other organizations. Access to DTC's system is also available to other entities such as banks, brokers, dealers and trust companies that clear through or maintain a custodial relationship with a participant, either directly or indirectly (collectively, the "indirect participants"). Persons who are not participants may beneficially own securities held by or on behalf of DTC only through the participants or the indirect participants. The ownership interests in, and transfers of ownership interests in, each security held by or on behalf of DTC are recorded on the records of the participants and indirect participants.

DTC has also advised us that, pursuant to procedures established by it:

(1): upon deposit of the Global Notes, DTC will credit the accounts of participants designated by the underwriters with portions of the principal amount of the Global Notes; and
(2): ownership of these interests in the Global Notes will be shown on, and the transfer of ownership of these interests will be effected only through, records maintained by DTC (with respect to the participants) or by the participants and the indirect participants (with respect to other owners of beneficial interests in the Global Notes).

Investors in the Global Notes who are participants in DTC's system may hold their interests therein directly through DTC. Investors in the Global Notes who are not participants may hold their interests therein indirectly through organizations which are participants in such system. All interests in a Global Note may be subject to the procedures and requirements of DTC. The laws of some states require that certain persons take physical delivery in definitive form of securities that they own. Consequently, the ability to transfer beneficial interests in a Global Note to such persons will be limited to that extent. Because DTC can act only on behalf of participants, which in turn act on behalf of indirect participants, the ability of a person having beneficial interests in a Global Note to pledge such interests to persons that do not participate in the DTC system, or otherwise take actions in respect of such interests, may be affected by the lack of a physical certificate evidencing such interests.

Except as described below, owners of an interest in the Global Notes will not have Notes registered in their names, will not receive physical delivery of Notes in certificated form and will not be considered the registered owners or "holders" thereof under the Indenture for any purpose.

Payments in respect of the principal of, and interest and premium, if any, on a Global Note registered in the name of DTC or its nominee will be payable to DTC in its capacity as the registered holder under the Indenture. Under the terms of the Indenture, we and the Trustee will treat the persons in whose names the Notes, including the Global Notes, are registered as the owners of the Notes for the purpose of receiving payments and for all other purposes. Consequently, neither we, the Trustee nor any agent of us or the Trustee has or will have any responsibility or liability for:

(1): any aspect of DTC's records or any participant's or indirect participant's records relating to or payments made on account of beneficial ownership interests in the Global Notes or for

maintaining, supervising or reviewing any of DTC's records or any participant's or indirect participant's records relating to the beneficial ownership interests in the Global Notes; or

(2): any other matter relating to the actions and practices of DTC or any of its participants or indirect participants.

DTC has advised us that its current practice, upon receipt of any payment in respect of securities such as the Notes (including principal and interest), is to credit the accounts of the relevant participants with the payment on the payment date unless DTC has reason to believe it will not receive payment on such payment date. Each relevant participant is credited with an amount proportionate to its beneficial ownership of an interest in the principal amount of the relevant security as shown on the records of DTC. Payments by the participants and the indirect participants to the beneficial owners of Notes will be governed by standing instructions and customary practices and will be the responsibility of the participants or the indirect participants and will not be the responsibility of DTC, the Trustee or us. Neither we nor the Trustee will be liable for any delay by DTC or any of its participants in identifying the beneficial owners of the Notes, and we and the Trustee may conclusively rely on and will be protected in relying on instructions from DTC or its nominee for all purposes.

Transfers between participants in DTC will be effected in accordance with DTC's procedures, and will be settled in same-day funds.

DTC has advised us that it will take any action permitted to be taken by a holder of Notes only at the direction of one or more participants to whose account DTC has credited the interests in the Global Notes and only in respect of such portion of the aggregate principal amount of the Notes as to which such participant or participants has or have given such direction. However, if there is an event of default under the Notes, DTC reserves the right to exchange the Global Notes for Legend Notes in certificated form, and to distribute such Notes to its participants.

Although DTC has agreed to the foregoing procedures in order to facilitate transfers of interests in the Global Notes among participants, it is under no obligation to perform such procedures, and such procedures may be discontinued or changed at any time. Neither we, the Trustee nor any agent of us or the Trustee will have any responsibility for the performance by DTC or its participants or indirect participants of their respective obligations under the rules and procedures governing their operations.

Exchange of Global Notes for Certificated Notes

A Global Note is exchangeable for definitive Notes in registered certificated form ("Certificated Notes") if:

(1): DTC (A) notifies us that it is unwilling or unable to continue as depositary for the Global Notes or (B) has ceased to be a clearing agency registered under the Exchange Act and, in each case, a successor depositary is not appointed;
(2): we, at our option, notify the Trustee in writing that we elect to cause the issuance of the Certificated Notes; or
(3): there has occurred and is continuing a default with respect to the Notes.

In addition, beneficial interests in a Global Note may be exchanged for Certificated Notes upon prior written notice given to the Trustee by or on behalf of DTC in accordance with the Indenture. In all cases, Certificated Notes delivered in exchange for any Global Note or beneficial interests in Global Notes will be registered in the names, and issued in any approved denominations, requested by or on behalf of the depositary (in accordance with its customary procedures).

Exchange of Certificated Notes for Global Notes

Certificated Notes may not be exchanged for beneficial interests in any Global Note unless the transferor first delivers to the Trustee a written certificate (in the form provided in the Indenture) to the effect that such transfer will comply with the appropriate transfer restrictions applicable to such Notes.

Same day settlement and payment

We will make payments in respect of the Notes represented by the Global Notes (including principal, premium, if any, and interest, if any) by wire transfer of immediately available funds to the accounts specified by the Global Note holder. We will make all payments of principal, interest and premium, if any, with respect to Certificated Notes by wire transfer of immediately available funds to the accounts specified by the holders of the Certificated Notes or, if no such account is specified, by mailing a check to each such holder's registered address. The Notes represented by the Global Notes are expected to be eligible to trade in DTC's Same-Day Funds Settlement System, and any permitted secondary market trading activity in such Notes will, therefore, be required by DTC to be settled in immediately available funds. We expect that secondary trading in any Certificated Notes will also be settled in immediately available funds.

Change of control

If a Change of Control occurs, unless the Company has exercised its right to redeem all of the Notes as described under "—Optional redemption," each holder will have the right to require the Company to repurchase all or any part (equal to $2,000 or an integral multiple of $1,000 in excess thereof) of such holder's Notes at a purchase price in cash equal to 101% of the principal amount of such Notes plus accrued and unpaid interest, if any, to the date of purchase (subject to the right of holders of record on the relevant record date to receive interest due on the relevant interest payment date).

Within 30 days following any Change of Control, unless the Company has exercised its right to redeem all of the Notes as described under "—Optional redemption," or at the Company's option, prior to such Change of Control but after it is publicly announced, the Company will mail a notice (the "Change of Control Offer") to each holder, with a copy to the Trustee, stating:

(1): that a Change of Control has occurred or will occur and that such holder has the right to require the Company to purchase such holder's Notes at a purchase price in cash equal to 101% of the principal amount of such Notes plus accrued and unpaid interest, if any, to the date of purchase (subject to the right of holders of record on a record date to receive interest on the relevant interest payment date) (the "Change of Control Payment");

(2): the repurchase date (which shall be no earlier than 30 days nor later than 60 days from the date such notice is mailed, or such later date as is necessary to comply with the requirements under the Exchange Act) (the "Change of Control Payment Date"); provided that the Change of Control Payment Date may not occur prior to the Change of Control; and
(3): the procedures determined by the Company, consistent with the Indenture, that a holder must follow in order to have its Notes repurchased.

On the Change of Control Payment Date, the Company will, to the extent lawful:

(1): accept for payment all Notes or portions of Notes (of $2,000 or an integral multiple of $1,000 in excess thereof) properly tendered and not withdrawn pursuant to the Change of Control Offer;
(2): deposit, to the extent not previously deposited for such purpose, with the paying agent an amount equal to the Change of Control Payment in respect of all Notes or portions of Notes so tendered; and
(3): deliver or cause to be delivered to the Trustee the Notes, to the extent not previously delivered for such purpose, so accepted and an Officers' Certificate stating the aggregate principal amount of Notes or portions of Notes being purchased by the Company.

The paying agent will promptly mail to each holder of Notes so tendered the Change of Control Payment for such Notes, and the Trustee will promptly authenticate and mail or deliver (or cause to be transferred by book entry) to each holder a new Note equal in principal amount to any unpurchased portion of the Notes surrendered, if any; provided that each such new Note will be in a principal amount of $2,000 or an integral multiple of $1,000 in excess thereof. The paying agent will deliver the Change of Control Payment for such Notes in global form registered in the name of or held by The Depository Trust Company or its nominee in immediately available funds to The Depository Trust Company or its nominee, as the case may be, as the registered holder of such global Note.

If the Change of Control Payment Date is on or after an interest record date and on or before the related interest payment date, any accrued and unpaid interest, if any, will be paid to the Person in whose name a Note is registered at the close of business on such record date, and no additional interest will be payable to holders who tender pursuant to the Change of Control Offer.

The Change of Control provisions described above will be applicable whether or not any other provisions of the Indenture are applicable. Except as described above with respect to a Change of Control, the Indenture does not contain provisions that permit the holders to require that the Company repurchase or redeem the Notes in the event of a takeover, recapitalization or similar transaction.

The Company will not be required to make a Change of Control Offer upon a Change of Control if a third party makes the Change of Control Offer in the manner, at the times and otherwise in compliance with the requirements set forth in the Indenture applicable to a Change of Control Offer made by the Company and purchases all Notes validly tendered and not withdrawn under such Change of Control Offer.

The Company will comply, to the extent applicable, with the requirements of Rule 14e-1 under the Exchange Act and any other securities laws or regulations in connection with the repurchase of Notes pursuant to this covenant. To the extent that the provisions of any securities laws or regulations conflict with provisions of the Indenture, the Company will comply with the applicable securities laws and regulations and will not be deemed to have breached its obligations described in the Indenture by virtue of the conflict.

The Company's ability to repurchase Notes pursuant to a Change of Control Offer may be limited by a number of factors. The occurrence of certain of the events that constitute a Change of Control would constitute a default under the Senior Secured Credit Agreement. In addition, certain events that may constitute a change of control under the Senior Secured Credit Agreement and cause a default under that agreement may not constitute a Change of Control under the Indenture. Future Indebtedness of the Company and its Subsidiaries may also contain prohibitions of certain events that would constitute a Change of Control or require such Indebtedness to be repurchased upon a Change of Control. Moreover, the exercise by the holders of their right to require the Company to repurchase the Notes could cause a default under such Indebtedness, even if the Change of Control itself does not, due to the financial effect of such repurchase on the Company. Finally, the Company's ability to pay cash to the holders upon a repurchase may be limited by the Company's then existing financial resources. There can be no assurance that sufficient funds will be available when necessary to make any required repurchases.

Even if sufficient funds were otherwise available, the terms of the Senior Secured Credit Agreement will, and other Indebtedness may, prohibit the Company's prepayment of Notes before their scheduled maturity. Consequently, if the Company is not able to prepay the Senior Secured Credit Agreement and any such other Indebtedness containing similar restrictions or obtain requisite waivers or consents, the Company will be unable to fulfill its repurchase obligations if holders of Notes exercise their repurchase rights following a Change of Control, resulting in a default under the Indenture. A default under the Indenture likely will result in a cross-default under the Senior Secured Credit Agreement and other Indebtedness.

The Change of Control provisions described above may deter certain mergers, tender offers and other takeover attempts involving the Company by increasing the capital required to effectuate such transactions. The definition of "Change of Control" includes a disposition of all or substantially all of the property and assets of the Company and its Restricted Subsidiaries taken as a whole to any Person. Although there is a limited body of case law interpreting the phrase "substantially all," there is no precise established definition of the phrase under applicable law. Accordingly, in certain circumstances there may be a degree of uncertainty as to whether a particular transaction would involve a disposition of "all or substantially all" of the property or assets of a Person. As a result, it may be unclear as to whether a Change of Control has occurred and whether a holder of Notes may require the Company to make an offer to repurchase the Notes as described above. Certain provisions under the Indenture relative to the Company's obligation to make an offer to repurchase the Notes as a result of a Change of Control may be waived or modified with the written consent of the holders of a majority in principal amount of the Notes.

Certain covenants

Effectiveness of covenants

Following the first day:

(1): the Notes have an Investment Grade Rating from both of the Rating Agencies; and
(2): no Default has occurred and is continuing under the Indenture;

the Company and its Restricted Subsidiaries will not be subject to the provisions of the Indenture summarized under the subheadings below:

•: "—Limitation on indebtedness,"
•: "—Limitation on restricted payments,"
•: "—Limitation on restrictions on distributions from restricted subsidiaries,"
•: "—Limitation on sales of assets and subsidiary stock,"
•: "—Limitation on affiliate transactions,"
•: "—Limitation on the sale of capital stock of restricted subsidiaries,"
•: "—Limitation on lines of business," and
•: Clause (3) of "—Merger and consolidation."

(collectively, the "Suspended Covenants"). If at any time the Notes' credit rating is downgraded from an Investment Grade Rating by any Rating Agency or a Default or Event of Default occurs and is continuing, then the Suspended Covenants will thereafter be reinstated as if such covenants had never been suspended (the "Reinstatement Date") and thereafter be applicable pursuant to the terms of the Indenture (including in connection with performing any calculation or assessment to determine compliance with the terms of the Indenture), unless and until the Notes subsequently attain an Investment Grade Rating (in which event the Suspended Covenants shall no longer be in effect for such time that the Notes maintain an Investment Grade Rating and no Default or Event of Default has occurred and is continuing); provided, however, that no Default, Event of Default or breach of any kind shall be deemed to exist under the Indenture, the Notes or the Subsidiary Guarantees with respect to the Suspended Covenants based on, and none of the Company or any of its Subsidiaries shall bear any liability for, any actions taken or events occurring after the Notes attain an Investment Grade Rating and before any reinstatement of such Suspended Covenants as provided above, or any actions taken at any time pursuant to any contractual obligation arising prior to such reinstatement, regardless of whether such actions or events would have been permitted if the applicable Suspended Covenants remained in effect during such period. The period of time between the date of suspension of the covenants and the Reinstatement Date is referred to as the "Suspension Period."

On the Reinstatement Date, all Indebtedness Incurred during the Suspension Period will be classified to have been Incurred pursuant to the first paragraph of "Limitation on indebtedness" or one of the clauses set forth in the second paragraph of "Limitation on indebtedness" (to the extent such Indebtedness would be permitted to be Incurred thereunder as of the Reinstatement Date and after giving effect to Indebtedness Incurred prior to the Suspension Period and outstanding on the Reinstatement Date). To the extent such Indebtedness would not be so permitted to be Incurred pursuant to the first or second paragraph of "Limitation on indebtedness," such Indebtedness will be deemed to have been

outstanding on the Issue Date, so that it is classified as permitted under clause (4)(b) of the second paragraph of "Limitation on indebtedness." Calculations made after the Reinstatement Date of the amount available to be made as Restricted Payments under "—Limitation on restricted payments" will be made as though the covenants described under "—Limitation on restricted payments" had been in effect since the Issue Date and throughout the Suspension Period. Accordingly, Restricted Payments made during the Suspension Period will reduce the amount available to be made as Restricted Payments under the first paragraph of "—Limitation on restricted payments."

During any period when the Suspended Covenants are suspended, the Board of Directors of the Company may not designate any of the Company's Subsidiaries as Unrestricted Subsidiaries pursuant to the Indenture.

Limitation on indebtedness

The Company will not, and will not permit any of its Restricted Subsidiaries to, Incur any Indebtedness (including, without limitation, Acquired Indebtedness); provided, however, that any of the Company and the Subsidiary Guarantors may Incur Indebtedness if on the date thereof:

(1): the Consolidated Coverage Ratio for the Company and its Restricted Subsidiaries is at least 2.25 to 1.00; and
(2): no Default or Event of Default will have occurred or be continuing or would occur as a consequence of Incurring the Indebtedness or transactions relating to such Incurrence.

The first paragraph of this covenant will not prohibit the Incurrence of the following Indebtedness:

(1)

Indebtedness of any of the Company and the Subsidiary Guarantors at any time outstanding pursuant to a Credit Facility in an aggregate principal amount up to the greater of (a) $1.0 billion and (b) 30% of Adjusted Consolidated Net Tangible Assets determined as of the date of the Incurrence of such Indebtedness;

(2)

Guarantees by (a) any of the Company and the Subsidiary Guarantors of Indebtedness Incurred by the Company or any Subsidiary Guarantor in accordance with the provisions of the Indenture; provided that in the event such Indebtedness that is being Guaranteed is a Subordinated Obligation or a Guarantor Subordinated Obligation, then the related Guarantee shall be subordinated in right of payment to the Notes or the Subsidiary Guarantee, as the case may be, and (b) Non-Guarantor Restricted Subsidiaries of Indebtedness Incurred by Non-Guarantor Restricted Subsidiaries in accordance with the provisions of the Indenture;

(3)

Indebtedness of the Company owing to and held by any Restricted Subsidiary or Indebtedness of a Restricted Subsidiary owing to and held by the Company or any other Restricted Subsidiary; provided, however,

(a): if the Company is the obligor on such Indebtedness and such Indebtedness is owing to and held by a Restricted Subsidiary that is not a Subsidiary Guarantor, such Indebtedness is expressly subordinated to the prior payment in full in cash of all obligations with respect to the Notes;

(b)

if a Subsidiary Guarantor is the obligor on such Indebtedness and the Company or a Subsidiary Guarantor is not the obligee, such Indebtedness is subordinated in right of payment to the Subsidiary Guarantees of such Subsidiary Guarantor; and

(c)

(i) any subsequent issuance or transfer of Capital Stock or any other event which results in any such Indebtedness being beneficially held by a Person other than the Company or a Restricted Subsidiary of the Company; and

(ii): any sale or other transfer of any such Indebtedness to a Person other than the Company or a Restricted Subsidiary of the Company;

shall be deemed, in each case, to constitute an Incurrence of such Indebtedness by the Company or such Subsidiary, as the case may be;

(4): Indebtedness represented by (a) the Notes issued on the Issue Date and the Subsidiary Guarantees, (b) any Indebtedness (other than the Indebtedness described in clauses (1), (2), (3), (9) and (10) of this paragraph) outstanding on the Issue Date and (c) any Refinancing Indebtedness Incurred in respect of any Indebtedness described in this clause (4) or clause (5) of this paragraph or Incurred pursuant to the first paragraph of this covenant;
(5): Indebtedness of a Restricted Subsidiary Incurred and outstanding on the date on which such Restricted Subsidiary was acquired by, or merged into, the Company or any Restricted Subsidiary (other than Indebtedness Incurred (a) to provide all or any portion of the funds utilized to consummate the transaction or series of related transactions pursuant to which such Restricted Subsidiary became a Restricted Subsidiary or was otherwise acquired by the Company or (b) otherwise in connection with, or in contemplation of, such acquisition); provided, however, that at the time such Restricted Subsidiary is acquired by the Company, the Company would have been able to Incur $1.00 of additional Indebtedness pursuant to the first paragraph of this covenant after giving effect to the Incurrence of such Indebtedness pursuant to this clause (5);
(6): Indebtedness under Hedging Obligations that are Incurred in the ordinary course of business (a) for the purpose of fixing or hedging interest rate risk with respect to any Indebtedness Incurred in accordance with the Indenture; (b) for the purpose of fixing or hedging currency exchange rate risk with respect to any currency exchanges; or (c) for the purpose of fixing or hedging commodity price risk with respect to any commodities;
(7): the Incurrence by any of the Company and the Restricted Subsidiaries of Indebtedness represented by Capitalized Lease Obligations, mortgage financings, purchase money obligations or other payments, in each case Incurred to finance all or any part of the purchase price or cost of acquisition, construction, improvement or development of assets or property (other than Capital Stock or other Investments) acquired, constructed, improved or developed in the ordinary course of business of the Company or such Restricted Subsidiary, and Attributable Indebtedness, in an aggregate principal amount, including all Refinancing Indebtedness Incurred to refund, defease, renew, extend, refinance or replace any Indebtedness Incurred pursuant to this clause (7), not to exceed $20.0 million at any time outstanding;
(8): Indebtedness Incurred in respect of workers' compensation claims, self-insurance obligations, bid, performance, surety, appeal and similar bonds, bankers' acceptances,

completion guarantees, and similar instruments provided by the Company or a Restricted Subsidiary in the ordinary course of business;

(9): Indebtedness arising from agreements of any of the Company and the Restricted Subsidiaries providing for indemnification, adjustment of purchase price or similar obligations, earn-outs or similar obligations, in each case, Incurred or assumed in connection with the disposition of any business, properties or assets of the Company or any Restricted Subsidiary or Capital Stock of a Restricted Subsidiary, provided that the maximum aggregate liability in respect of all such Indebtedness shall at no time exceed the gross proceeds actually received by the Company and its Restricted Subsidiaries in connection with such disposition;
(10): Indebtedness arising from the honoring by a bank or other financial institution of a check, draft or similar instrument (except in the case of daylight overdrafts) drawn against insufficient funds in the ordinary course of business, provided, however, that such Indebtedness is extinguished within five business days of Incurrence;
(11): Indebtedness relating to Hydrocarbon balancing positions arising in the ordinary course of business;
(12): Indebtedness of any of the Company and the Restricted Subsidiaries to the extent the net proceeds thereof are promptly (a) used to redeem all of the Notes or (b) deposited to defease or satisfy the Notes as described below under "—Defeasance" or "—Satisfaction and discharge;" and
(13): in addition to the items referred to in clauses (1) through (12) above, Indebtedness of any of the Company and the Restricted Subsidiaries in an aggregate outstanding principal amount (or accreted value, as the case may be) which, when taken together with the principal amount of all other Indebtedness Incurred pursuant to this clause (13) and then outstanding, will not exceed $50.0 million at any time outstanding.

The Company will not Incur any Indebtedness under the preceding paragraph if the proceeds thereof are used, directly or indirectly, to refinance any Subordinated Obligations of the Company unless such Indebtedness will be subordinated to the Notes to at least the same extent as such Subordinated Obligations. No Subsidiary Guarantor will Incur any Indebtedness under the preceding paragraph if the proceeds thereof are used, directly or indirectly, to refinance any Guarantor Subordinated Obligations of such Subsidiary Guarantor unless such Indebtedness will be subordinated to the obligations of such Subsidiary Guarantor under its Subsidiary Guarantee to at least the same extent as such Guarantor Subordinated Obligations. No Restricted Subsidiary (other than a Subsidiary Guarantor) may Incur any Indebtedness if the proceeds are used to refinance Indebtedness of the Company or a Subsidiary Guarantor.

For purposes of determining compliance with, and the outstanding principal amount of any particular Indebtedness Incurred pursuant to and in compliance with, this covenant:

(1): subject to clause (2) below, in the event that Indebtedness meets the criteria of more than one of the types of Indebtedness described in the first and second paragraphs of this covenant, the Company, in its sole discretion, will classify or reclassify such item of Indebtedness in any manner that complies with this covenant and only be required to include the amount and type of such Indebtedness in one of such clauses or paragraphs;

(2): all Indebtedness outstanding on the Issue Date under the Senior Secured Credit Agreement shall be deemed Incurred under clause (1) of the second paragraph of this covenant and not the first paragraph or clause (4) of the second paragraph of this covenant;
(3): Guarantees of, or obligations in respect of letters of credit relating to, Indebtedness which is otherwise included in the determination of a particular amount of Indebtedness shall not be included;
(4): if obligations in respect of letters of credit are Incurred pursuant to a Credit Facility and are being treated as Incurred pursuant to clause (1) of the second paragraph above and the letters of credit relate to other Indebtedness, then such other Indebtedness shall not be included;
(5): the principal amount of any Disqualified Stock of the Company or a Restricted Subsidiary, or Preferred Stock of a Restricted Subsidiary that is not a Subsidiary Guarantor, will be equal to the greater of the maximum mandatory redemption or repurchase price (not including, in either case, any redemption or repurchase premium) or the liquidation preference thereof;
(6): Indebtedness permitted by this covenant need not be permitted solely by reference to one provision permitting such Indebtedness but may be permitted in part by one such provision and in part by one or more other provisions of this covenant permitting such Indebtedness;
(7): the principal amount of any Indebtedness outstanding in connection with a securitization transaction or series of transactions is the amount of obligations outstanding under the legal documents entered into as part of such transaction that would be characterized as principal if such transaction were structured as a secured lending transaction rather than as a purchase relating to such transaction; and
(8): the amount of Indebtedness issued at a price that is less than the principal amount thereof will be equal to the amount of the liability in respect thereof determined in accordance with GAAP.

Accrual of interest, accrual of dividends, the accretion of accreted value, the payment of interest in the form of additional Indebtedness and the payment of dividends in the form of additional shares of Preferred Stock or Disqualified Stock will not be deemed to be an Incurrence of Indebtedness for purposes of this covenant. The amount of any Indebtedness outstanding as of any date shall be (i) the accreted value thereof in the case of any Indebtedness issued with original issue discount and (ii) the principal amount or liquidation preference thereof, together with any interest thereon that is more than 30 days past due, in the case of any other Indebtedness.

In addition, the Company will not permit any of its Unrestricted Subsidiaries to Incur any Indebtedness or issue any shares of Disqualified Stock, other than Non-Recourse Debt. If at any time an Unrestricted Subsidiary becomes a Restricted Subsidiary, any Indebtedness of such Subsidiary shall be deemed to be Incurred by a Restricted Subsidiary as of such date (and, if such Indebtedness is not permitted to be Incurred as of such date under this "—Limitation on indebtedness" covenant, the Company shall be in Default of this covenant).

For purposes of determining compliance with any U.S. dollar-denominated restriction on the Incurrence of Indebtedness, the U.S. dollar-equivalent principal amount of Indebtedness denominated in a foreign currency shall be calculated based on the relevant currency exchange

rate in effect on the date such Indebtedness was Incurred, in the case of term Indebtedness, or first committed, in the case of revolving credit Indebtedness; provided that if such Indebtedness is Incurred to refinance other Indebtedness denominated in a foreign currency, and such refinancing would cause the applicable U.S. dollar-dominated restriction to be exceeded if calculated at the relevant currency exchange rate in effect on the date of such refinancing, such U.S. dollar-dominated restriction shall be deemed not to have been exceeded so long as the principal amount of such refinancing Indebtedness does not exceed the principal amount of such Indebtedness being refinanced, plus, without duplication, any additional Indebtedness Incurred to pay interest or premiums required by the instruments governing the Indebtedness being refinanced and fees and expenses Incurred in connection therewith. Notwithstanding any other provision of this covenant, the maximum amount of Indebtedness that the Company may Incur pursuant to this covenant shall not be deemed to be exceeded solely as a result of fluctuations in the exchange rate of currencies. The principal amount of any Indebtedness Incurred to refinance other Indebtedness, if Incurred in a different currency from the Indebtedness being refinanced, shall be calculated based on the currency exchange rate applicable to the currencies in which such Refinancing Indebtedness is denominated that is in effect on the date of such refinancing.

Limitation on restricted payments

The Company will not, and will not permit any of its Restricted Subsidiaries, directly or indirectly, to:

(1)

declare or pay any dividend or make any distribution (whether made in cash, securities or other property) on or in respect of its Capital Stock (including, without limitation, any payment thereof in connection with any merger or consolidation involving the Company or any of its Restricted Subsidiaries) except:

(a): dividends or distributions payable in Capital Stock of the Company (other than Disqualified Stock) or in options, warrants or other rights to purchase such Capital Stock of the Company; and
(b): dividends or distributions payable to the Company or another Restricted Subsidiary (and if such Restricted Subsidiary is not a Wholly Owned Subsidiary, to its other holders of the applicable class or classes of Capital Stock on a pro rata basis);

(2)

purchase, redeem, retire or otherwise acquire for value any Capital Stock of the Company or any direct or indirect parent of the Company held by Persons other than the Company or a Restricted Subsidiary (other than in exchange for Capital Stock of the Company (other than Disqualified Stock));

(3)

purchase, repurchase, redeem, defease or otherwise acquire or retire for value, prior to scheduled maturity, scheduled repayment or scheduled sinking fund payment, any Subordinated Obligations or Guarantor Subordinated Obligations (other than (a) Indebtedness of the Company owing to and held by any Subsidiary Guarantor or Indebtedness of a Subsidiary Guarantor owing to and held by the Company or any other Subsidiary Guarantor permitted under clause (3) of the second paragraph of the covenant "—Limitation on indebtedness" or (b) the purchase, repurchase, redemption, defeasance or other acquisition or retirement of Subordinated Obligations or Guarantor Subordinated Obligations purchased in anticipation of satisfying a sinking fund obligation, principal installment or final maturity, in

each case due within one year of the date of purchase, repurchase, redemption, defeasance or other acquisition or retirement); or

(4): make any Restricted Investment in any Person;

(any such dividend, distribution, purchase, redemption, repurchase, defeasance, other acquisition, retirement or Restricted Investment referred to in clauses (1) through (4) shall be referred to herein as a "Restricted Payment"), if at the time the Company or such Restricted Subsidiary makes such Restricted Payment:

(a)

a Default shall have occurred and be continuing (or would result therefrom); or

(b)

the Company is not able to Incur $1.00 of additional Indebtedness pursuant to the first paragraph under the "—Limitation on indebtedness" covenant after giving effect, on a pro forma basis, to such Restricted Payment; or

(c)

the aggregate amount of such Restricted Payment and all other Restricted Payments declared or made subsequent to the Issue Date would exceed the sum of:

(i)

50% of Consolidated Net Income for the period (treated as one accounting period) from the beginning of the fiscal quarter in which the Issue Date occurs to the end of the most recent fiscal quarter ending prior to the date of such Restricted Payment for which financial statements are in existence (or, in case such Consolidated Net Income is a deficit, minus 100% of such deficit);

(ii)

100% of the aggregate Net Cash Proceeds, or the fair market value of property other than cash, received by the Company from the issue or sale of its Capital Stock (other than Disqualified Stock) or other capital contributions subsequent to the Issue Date (other than Net Cash Proceeds or property received from an issuance or sale of such Capital Stock to a Subsidiary of the Company or an employee stock ownership plan, option plan or similar trust to the extent such sale to an employee stock ownership plan, option plan or similar trust is financed by loans from or Guaranteed by the Company or any Restricted Subsidiary unless such loans have been repaid with cash on or prior to the date of determination) excluding in any event Net Cash Proceeds received by the Company from the issue and sale of its Capital Stock or capital contributions to the extent applied to redeem Notes in compliance with the provisions set forth under the second paragraph of the caption "—Optional redemption;"

(iii)

the amount by which Indebtedness of the Company or its Restricted Subsidiaries is reduced on the Company's consolidated balance sheet upon the conversion or exchange (other than by a Subsidiary of the Company) subsequent to the Issue Date of any Indebtedness of the Company or its Restricted Subsidiaries convertible or exchangeable for Capital Stock (other than Disqualified Stock) of the Company (less the amount of any cash, or the fair market value of any other property, distributed by the Company upon such conversion or exchange);

(iv)

the amount equal to the net reduction in Restricted Investments made by the Company or any of its Restricted Subsidiaries in any Person resulting from:

(A): repurchases, repayments or redemptions of such Restricted Investments by such Person, proceeds realized upon the sale of such Restricted Investment to an

unaffiliated purchaser, repayments of loans or advances or other transfers of cash or assets (including, without limitation, by way of dividend or distribution) by such Person to the Company or any Restricted Subsidiary (other than for reimbursement of tax payments); or

(B): the redesignation of Unrestricted Subsidiaries as Restricted Subsidiaries (valued in each case as provided in the definition of "Investment") not to exceed, in the case of any Unrestricted Subsidiary, the amount of Investments previously made by the Company or any Restricted Subsidiary in such Unrestricted Subsidiary,

which amount in each case under this clause (iv) was included in the calculation of the amount of Restricted Payments; provided, however, that no amount will be included under this clause (iv) to the extent it is already included in Consolidated Net Income; and

(v): any amount that previously qualified as a Restricted Payment on account of any Guarantee entered into by the Company or any Restricted Subsidiary; provided, that the obligation arising under such Guarantee no longer exists (and excluding any amount actually paid by the Company or any Restricted Subsidiary to satisfy its obligations under such Guarantee); and

The provisions of the preceding paragraph will not prohibit:

(1): any Restricted Payment (other than a Restricted Payment described in clause (1) of the definition of "Restricted Payment") made by exchange for, or out of the proceeds of the substantially concurrent sale of, Capital Stock of the Company (other than Disqualified Stock and other than Capital Stock issued or sold to a Subsidiary or an employee stock ownership plan or similar trust to the extent such sale to an employee stock ownership plan or similar trust is financed by loans from or Guaranteed by the Company or any Restricted Subsidiary unless such loans have been repaid with cash on or prior to the date of determination); provided, however, that the amount of such Restricted Payments will be excluded in subsequent calculations of the amount of Restricted Payments; provided, further, that the Net Cash Proceeds or property other than cash received from such sale of Capital Stock to the extent such proceeds are used to make such Restricted Payments will be excluded from clause (4)(c)(ii) of the preceding paragraph;
(2): any principal payment on, purchase, repurchase, redemption, defeasance or other acquisition or retirement of Subordinated Obligations of the Company or Guarantor Subordinated Obligations of any Subsidiary Guarantor made by exchange for, or out of the proceeds of the substantially concurrent sale of, Subordinated Obligations of the Company or any principal payment on, purchase, repurchase, redemption, defeasance or other acquisition or retirement of Guarantor Subordinated Obligations made by exchange for or out of the proceeds of the substantially concurrent sale of Guarantor Subordinated Obligations that, in each case, is permitted to be Incurred pursuant to the covenant described under "—Limitation on indebtedness" and that in each case constitutes Refinancing Indebtedness; provided, however, that the amount of such Restricted Payments will be excluded in subsequent calculations of the amount of Restricted Payments;
(3): any principal payment on, purchase, repurchase, redemption, defeasance or other acquisition or retirement of Disqualified Stock of the Company or a Restricted Subsidiary made

by exchange for or out of the proceeds of the substantially concurrent sale of Disqualified Stock of the Company or such Restricted Subsidiary, as the case may be, that, in each case, is permitted to be Incurred pursuant to the covenant described under "—Limitation on indebtedness" and that in each case constitutes Refinancing Indebtedness; provided, however, that the amount of such Restricted Payments will be excluded in subsequent calculations of the amount of Restricted Payments;

(4)

so long as no Default or Event of Default has occurred and is continuing, any purchase or redemption of Subordinated Obligations or Guarantor Subordinated Obligations of a Subsidiary Guarantor from Net Available Cash to the extent permitted under "—Limitation on sales of assets and subsidiary stock" below; provided, however, that the amount of such Restricted Payments will be excluded in subsequent calculations of the amount of Restricted Payments;

(5)

dividends paid within 60 days after the date of declaration if at such date of declaration such dividend would have complied with this provision; provided, however, that the amount of such Restricted Payments will be included in subsequent calculations of the amount of Restricted Payments;

(6)

so long as no Default or Event of Default has occurred and is continuing,

(a): the purchase, redemption or other acquisition, cancellation or retirement for value of Capital Stock, or options, warrants or other rights to purchase or acquire Capital Stock of the Company or any Restricted Subsidiary or any direct or indirect parent of the Company held by any existing or former officers, directors, employees, management or consultants of the Company or any Subsidiary of the Company or their assigns, estates or heirs, in each case in connection with the repurchase provisions under employee stock option or stock purchase agreements or other agreements to compensate officers, directors, employees, management or consultants; provided that such Capital Stock, or options, warrants or other rights to purchase or acquire Capital Stock, were received for services related to, or for the benefit of, the Company and its Restricted Subsidiaries; and provided further that such redemptions or repurchases pursuant to this clause will not exceed $2.0 million in the aggregate during any calendar year (with unused amounts in any calendar year being carried over to the succeeding calendar years) and $5.0 million in the aggregate for all such redemptions and repurchases, plus the amount of any capital contributions to the Company as a result of sales of Capital Stock, or options, warrants or other rights to purchase or acquire Capital Stock, of the Company or any direct or indirect parent of the Company to such persons, plus the cash proceeds of key man life insurance policies received by the Company and its Restricted Subsidiaries after the Issue Date (provided, however, that the Net Cash Proceeds from such sale of Capital Stock to the extent such proceeds are used to make such Restricted Payments will be excluded from clause (4)(c)(ii) of the preceding paragraph and provided, further, however, that the amount of such Restricted Payments will be excluded in subsequent calculations of the amount of Restricted Payments); and
(b): loans or advances to employees, officers, directors, management or consultants of the Company or any Subsidiary of the Company the proceeds of which are used to purchase Capital Stock of the Company, in an aggregate amount not in excess of $2.0 million with respect to all loans or advances made since the Issue Date (without giving effect to the forgiveness of any such loan); provided, however, that the amount of such Restricted Payments will be included in subsequent calculations of the amount of Restricted Payments;

(7): so long as no Default or Event of Default has occurred and is continuing, the declaration and payment of dividends to holders of any class or series of Disqualified Stock of the Company issued in accordance with the terms of the Indenture to the extent such dividends are included in the definition of "Consolidated Interest Expense"; provided, however, that the amount of such Restricted Payments will be excluded in subsequent calculations of the amount of Restricted Payments;
(8): repurchases of Capital Stock deemed to occur upon the exercise of stock options, warrants or other convertible securities if such Capital Stock represents a portion of the exercise price thereof; provided, however, that the amount of such Restricted Payments will be excluded in subsequent calculations of the amount of Restricted Payments;
(9): the purchase, repurchase, redemption, defeasance or other acquisition or retirement for value of any Subordinated Obligation or Guarantor Subordinated Obligation (a) at a purchase price not greater than 101% of the principal amount of such Subordinated Obligation or Guarantor Subordinated Obligation in the event of a Change of Control in accordance with provisions similar to the "—Change of control" covenant or (b) at a purchase price not greater than 100% of the principal amount thereof in accordance with provisions similar to the "—Limitation on sales of assets and subsidiary stock" covenant; provided that, prior to or simultaneously with such purchase, repurchase, redemption, defeasance or other acquisition or retirement, the Company has made the Change of Control Offer or Asset Disposition Offer, as applicable, as provided in such covenant with respect to the Notes and has completed the repurchase or redemption of all Notes validly tendered for payment in connection with such Change of Control Offer or Asset Disposition Offer; provided, however, that the amount of such Restricted Payments will be excluded in subsequent calculations of the amount of Restricted Payments;
(10): so long as no Default or Event of Default has occurred and is continuing, the payment of dividends on the Company's Common Stock of an amount per annum not to exceed $0.20 per share (but in no event in excess of $20.0 million in the aggregate during any calendar year pursuant to this clause (10)); provided, however, that the amount of such Restricted Payments will be included in subsequent calculations of Restricted Payments;
(11): the payment of cash in lieu of fractional shares of Capital Stock in connection with any transaction that is not prohibited by the Indenture (including, without limitation, in connection with the conversion of convertible Indebtedness into Capital Stock); provided, however, that such Restricted Payments will be excluded in subsequent calculations of the amount of Restricted Payments;
(12): payments to dissenting stockholders not to exceed $5.0 million in the aggregate after the Issue Date (x) pursuant to applicable law or (y) in connection with the settlement or other satisfaction of claims made pursuant to or in connection with a consolidation, merger or transfer of assets in connection with a transaction that is not prohibited by the Indenture; provided, however, that such Restricted Payments will be included in subsequent calculations of the amount of Restricted Payments;
(13): so long as no Default or Event of Default has occurred and is continuing, any redemption of share purchase rights at a redemption price not to exceed $0.01 per right; provided,

however, that such Restricted Payment will be included in subsequent calculations of the amount of Restricted Payments;

(14): so long as no Default or Event of Default has occurred and is continuing, the purchase, redemption or other acquisition, cancellation or retirement for value of Capital Stock, or options, warrants or other rights to purchase or acquire Capital Stock, of the Company pursuant to a stock repurchase program authorized by the Board of Directors of the Company for an aggregate amount not to exceed $200.0 million after the Issue Date; provided, however, that such Restricted Payments will be included in subsequent calculations of the amount of Restricted Payments; and
(15): Restricted Payments in an amount not to exceed $25.0 million; provided, however, that the amount of such Restricted Payments will be included in subsequent calculations of the amount of Restricted Payments.

The amount of all Restricted Payments (other than cash) shall be the fair market value on the date of such Restricted Payment of the asset(s) or securities proposed to be paid, transferred or issued by the Company or such Restricted Subsidiary, as the case may be, pursuant to such Restricted Payment.

Limitation on liens

The Company will not, and will not permit any of its Restricted Subsidiaries to, directly or indirectly, create, Incur or suffer to exist any Lien (other than Permitted Liens) upon any of its property or assets (including, without limitation, Capital Stock of Subsidiaries), whether owned on the Issue Date or acquired after that date, which Lien is securing any Indebtedness, unless contemporaneously with the Incurrence of such Liens effective provision is made to secure the Indebtedness due under the Indenture and the Notes or, in respect of Liens on any Restricted Subsidiary's property or assets, any Subsidiary Guarantee of such Restricted Subsidiary, equally and ratably with (or senior in priority to in the case of Liens with respect to Subordinated Obligations or Guarantor Subordinated Obligations, as the case may be) the Indebtedness secured by such Lien for so long as such Indebtedness is so secured.

Limitation on sale/leaseback transactions

The Company will not, and will not permit any of its Restricted Subsidiaries to, enter into any Sale/Leaseback Transaction unless:

(1): the Company or such Restricted Subsidiary, as the case may be, receives consideration at the time of such Sale/Leaseback Transaction at least equal to the fair market value (as conclusively determined by the Board of Directors of the Company or such Restricted Subsidiary) of the property subject to such transaction;
(2): the Company or such Restricted Subsidiary could have Incurred Indebtedness at the time of such Sale/Leaseback Transaction in an amount equal to the Attributable Indebtedness in respect of such Sale/Leaseback Transaction pursuant to the covenant described under "—Limitation on indebtedness;" and
(3): the Sale/Leaseback Transaction is treated as an Asset Disposition and all of the conditions of the Indenture described under "—Limitation on sales of assets and subsidiary stock" (including the provisions concerning the application of Net Available Cash) are satisfied with

respect to such Sale/Leaseback Transaction, treating all of the consideration received in such Sale/Leaseback Transaction as Net Available Cash for purposes of such covenant.

Limitation on restrictions on distributions from restricted subsidiaries

The Company will not, and will not permit any Restricted Subsidiary to, create or otherwise cause or permit to exist or become effective any consensual encumbrance or consensual restriction on the ability of any Restricted Subsidiary to:

(1): pay dividends or make any other distributions on its Capital Stock or pay any Indebtedness or other obligations owed to the Company or any Restricted Subsidiary (it being understood that the priority of any Preferred Stock in receiving dividends or liquidating distributions prior to dividends or liquidating distributions being paid on Common Stock and any subordination of such Indebtedness or other obligations shall be deemed not to be an encumbrance or restriction on the ability to pay dividends or make any other distributions on Capital Stock);
(2): make any loans or advances to the Company or any Restricted Subsidiary (it being understood that the subordination of loans or advances made to the Company or any Restricted Subsidiary to other Indebtedness Incurred by the Company or any Restricted Subsidiary shall be deemed not to be an encumbrance or restriction on the ability to make loans or advances); or
(3): transfer any of its property or assets to the Company or any Restricted Subsidiary.

The preceding provisions will not prohibit:

(a): any encumbrance or restriction pursuant to an agreement or instrument in effect at or entered into on the Issue Date, including, without limitation, the Indenture, the Notes, the Subsidiary Guarantees, and the Senior Secured Credit Agreement (and related documentation);
(b): any encumbrance or restriction with respect to a Restricted Subsidiary pursuant to any agreement or instrument that is in existence at the time such Person becomes a Restricted Subsidiary (and not Incurred in connection with, or in contemplation of, such Person becoming a Restricted Subsidiary); provided, that any such encumbrance or restriction shall not extend to any assets or property of the Company or any other Restricted Subsidiary other than the assets and property so acquired and that, in the case of Indebtedness, was permitted to be Incurred pursuant to the Indenture;
(c): any encumbrance or restriction pursuant to any agreement or instrument governing any Acquired Indebtedness or other agreement or instrument of any Person or related to property, assets or Capital Stock of a Person acquired by or merged into or consolidated with the Company or any Restricted Subsidiary; provided, that such encumbrance or restriction (i) was not entered into in contemplation of the acquisition, merger or consolidation transaction, and (ii) shall not extend to any assets or property of the Company or any other Restricted Subsidiary other than the assets and property so acquired and that, in the case of Indebtedness, was permitted to be Incurred pursuant to the Indenture;
(d): any encumbrance or restriction with respect to a Restricted Subsidiary pursuant to an agreement effecting a refunding, replacement or refinancing of Indebtedness Incurred

pursuant to an agreement referred to in any of clauses (a), (b) or (c) of this paragraph or this clause (d) or contained in any amendment, restatement, modification, renewal, restructuring, supplement, extension, substitution, refunding, replacement or refinancing of an agreement referred to in any of such clauses; provided, however, that, in the good faith reasonable determination of the Company, the encumbrances and restrictions with respect to such Restricted Subsidiary contained in any such agreement are no less favorable in any material respect, taken as a whole, to the holders of the Notes than the encumbrances and restrictions contained in such agreements referred to in clauses (a), (b) or (c) of this paragraph on the Issue Date or the date such Restricted Subsidiary became a Restricted Subsidiary or was merged into a Restricted Subsidiary, whichever is applicable;

(e)

in the case of clause (3) of the first paragraph of this covenant, any encumbrance or restriction:

(i): that restricts in a customary manner the subletting, assignment or transfer of any property or asset that is subject to a lease, license or similar contract, or the assignment or transfer of any lease, license or other contract;
(ii): contained in mortgages, pledges or other security agreements permitted under the Indenture securing Indebtedness of the Company or a Restricted Subsidiary to the extent such encumbrances or restrictions restrict the transfer of the property subject to such mortgages, pledges or other security agreements; or
(iii): pursuant to customary provisions restricting dispositions of real property interests set forth in any reciprocal easement agreements of the Company or any Restricted Subsidiary;

(f)

(i) purchase money obligations for property acquired in the ordinary course of business and (ii) Capitalized Lease Obligations permitted under the Indenture, in each case, that impose encumbrances or restrictions of the nature described in clause (3) of the first paragraph of this covenant on the property so acquired;

(g)

any encumbrance or restriction with respect to a Restricted Subsidiary (or any of its property or assets) imposed pursuant to an agreement entered into for the direct or indirect sale or other disposition of the Capital Stock, property or assets of such Restricted Subsidiary (or the property or assets that are subject to such encumbrance or restriction) pending the closing of such sale or disposition;

(h)

any customary encumbrances or restrictions imposed pursuant to any agreement referred to in the definition of "Permitted Business Investment;"

(i)

deposit arrangements or net worth provisions in leases and other agreements entered into by the Company or any Restricted Subsidiary in the ordinary course of business;

(j)

in the case of clause (3) of the first paragraph of this covenant, any encumbrance or restriction that is a Lien otherwise permitted to be Incurred pursuant to the covenant described under "—Limitation on liens";

(k)

any encumbrance or restriction in respect of a Sale/Leaseback Transaction permitted under "—Limitation on sale/leaseback transactions"; and

(l)

encumbrances or restrictions arising or existing by reason of applicable law or any applicable rule, regulation or order.

Limitation on sales of assets and subsidiary stock

The Company will not, and will not permit any of its Restricted Subsidiaries to, make any Asset Disposition unless:

(1)

the Company or such Restricted Subsidiary, as the case may be, receives consideration at least equal to the Fair Market Value, including as to the value of all non-cash consideration, as determined in good faith by the Company, of the shares and assets subject to such Asset Disposition;

(2)

at least 75% of the consideration from such Asset Disposition received by the Company or such Restricted Subsidiary, as the case may be, is in the form of cash or Cash Equivalents; and

(3)

an amount equal to 100% of the Net Available Cash from such Asset Disposition is applied by the Company or any one or more Restricted Subsidiaries:

(a): to the extent the Company or any Restricted Subsidiary, as the case may be, elects (or is required by the terms of any Indebtedness), to prepay, repay or purchase Indebtedness of the Company (other than any Disqualified Stock or Subordinated Obligations) or Indebtedness of a Wholly Owned Subsidiary (other than any Disqualified Stock or Guarantor Subordinated Obligations of a Wholly Owned Subsidiary that is a Subsidiary Guarantor) (in each case other than Indebtedness owed to the Company or an Affiliate of the Company) within 365 days from the later of the date of such Asset Disposition and the receipt of such Net Available Cash; provided, however, that, in connection with any prepayment, repayment or purchase of Indebtedness pursuant to this clause (a), the Company or such Restricted Subsidiary will retire such Indebtedness and will cause the related commitment (if any) to be permanently reduced in an amount equal to the principal amount so prepaid, repaid or purchased; and
(b): to the extent the Company or any Restricted Subsidiary elects, to invest in Additional Assets within 365 days from the later of the date of such Asset Disposition and the receipt of such Net Available Cash;

provided that the Company and its Restricted Subsidiaries may make any combination of prepayment, repayment, purchase or investment permitted by clause (a) or clause (b) above and, pending the final application of any such Net Available Cash in accordance with clause (a) or clause (b) above or pursuant to an Asset Disposition Offer described below, the Company and its Restricted Subsidiaries may temporarily reduce Indebtedness or otherwise invest such Net Available Cash in any manner not prohibited by the Indenture.

Any Net Available Cash from Asset Dispositions that are not applied or invested as provided in the preceding paragraph will be deemed to constitute "Excess Proceeds." Within 30 days following the 365^th day after an Asset Disposition, if the aggregate amount of Excess Proceeds exceeds $25.0 million, the Company will be required to make an offer ("Asset Disposition Offer") to all holders of Notes and to the extent required by the terms of other Pari Passu Indebtedness, to all holders of other Pari Passu Indebtedness outstanding with similar provisions requiring the Company to make an offer to purchase such Pari Passu Indebtedness with the proceeds from any Asset Disposition ("Pari Passu Notes"), to purchase the maximum principal amount of Notes and any such Pari Passu Notes to which the Asset Disposition Offer applies that may be purchased out of the Excess Proceeds, at an offer price in cash in an amount equal to 100% of the principal amount of the Notes and Pari Passu Notes plus accrued

and unpaid interest to the date of purchase, in accordance with the procedures set forth in the Indenture or the agreements governing the Pari Passu Notes, as applicable, in each case in denominations of $2,000 and integral multiples of $1,000 in excess thereof. To the extent that the aggregate amount of Notes and Pari Passu Notes so validly tendered and not properly withdrawn pursuant to an Asset Disposition Offer is less than the Excess Proceeds, the Company may use any remaining Excess Proceeds for general corporate or other purposes, subject to other covenants contained in the Indenture. If the aggregate principal amount of Notes surrendered by holders thereof and other Pari Passu Notes surrendered by holders or lenders, collectively, exceeds the amount of Excess Proceeds, the Trustee shall select the Notes and Pari Passu Notes to be purchased on a pro rata basis on the basis of the aggregate principal amount of tendered Notes and Pari Passu Notes. Upon completion of such Asset Disposition Offer, the amount of Excess Proceeds shall be reset at zero.

The Asset Disposition Offer will remain open for a period of 20 Business Days following its commencement, except to the extent that a longer period is required by applicable law (the "Asset Disposition Offer Period"). No later than five Business Days after the termination of the Asset Disposition Offer Period (the "Asset Disposition Purchase Date"), the Company will purchase the principal amount of Notes and Pari Passu Notes required to be purchased pursuant to this covenant (the "Asset Disposition Offer Amount") or, if less than the Asset Disposition Offer Amount has been so validly tendered, all Notes and Pari Passu Notes validly tendered in response to the Asset Disposition Offer.

If the Asset Disposition Purchase Date is on or after an interest record date and on or before the related interest payment date, any accrued and unpaid interest will be paid to the Person in whose name a Note is registered at the close of business on such record date, and no additional interest will be payable to holders who tender Notes pursuant to the Asset Disposition Offer.

On or before the Asset Disposition Purchase Date, the Company will, to the extent lawful, accept for payment, on a pro rata basis to the extent necessary, the Asset Disposition Offer Amount of Notes and Pari Passu Notes or portions of Notes and Pari Passu Notes so validly tendered and not properly withdrawn pursuant to the Asset Disposition Offer, or if less than the Asset Disposition Offer Amount has been validly tendered and not properly withdrawn, all Notes and Pari Passu Notes so validly tendered and not properly withdrawn, in each case in denominations of $2,000 and integral multiples of $1,000 in excess thereof. The Company will deliver to the Trustee an Officers' Certificate stating that such Notes or portions thereof were accepted for payment by the Company in accordance with the terms of this covenant and, in addition, the Company will deliver all certificates and notes required, if any, by the agreements governing the Pari Passu Notes. The Company or the Paying Agent, as the case may be, will promptly (but in any case not later than five Business Days after termination of the Asset Disposition Offer Period) mail or deliver to each tendering holder of Notes or holder or lender of Pari Passu Notes, as the case may be, an amount equal to the purchase price of the Notes or Pari Passu Notes so validly tendered and not properly withdrawn by such holder or lender, as the case may be, and accepted by the Company for purchase, and the Company will promptly issue a new Note, and the Trustee, upon delivery of an Officers' Certificate from the Company, will authenticate and mail or deliver such new Note to such holder, in a principal amount equal to any unpurchased portion of the Note surrendered; provided that each such new Note will be in a principal amount of $2,000 or an integral multiple of $1,000 in excess thereof. In

addition, the Company will take any and all other actions required by the agreements governing the Pari Passu Notes in connection with the Asset Disposition Offer. Any Note not so accepted will be promptly mailed or delivered by the Company to the holder thereof. The Company will publicly announce the results of the Asset Disposition Offer on or before the Asset Disposition Purchase Date.

For the purposes of this covenant, the following will be deemed to be cash:

(1): the assumption by the transferee of Indebtedness (other than Subordinated Obligations or Disqualified Stock) of the Company or Indebtedness of a Wholly Owned Subsidiary (other than Guarantor Subordinated Obligations or Disqualified Stock of any Wholly Owned Subsidiary that is a Subsidiary Guarantor) and the release of the Company or such Restricted Subsidiary from all liability on such Indebtedness in connection with such Asset Disposition (in which case the Company will, without further action, be deemed to have applied such deemed cash to Indebtedness in accordance with clause (3)(a) above); and
(2): securities, notes or other obligations received by the Company or any Restricted Subsidiary from the transferee that, within 180 days of receipt thereof, are converted, sold or exchanged by the Company or such Restricted Subsidiary into or for cash.

The Company will comply, to the extent applicable, with the requirements of Rule 14e-1 under the Exchange Act and any other securities laws or regulations in connection with the repurchase of Notes pursuant to the Indenture. To the extent that the provisions of any securities laws or regulations conflict with provisions of this covenant, the Company will comply with the applicable securities laws and regulations and will not be deemed to have breached its obligations under the Indenture by virtue of any conflict. See "Description of other indebtedness."

Limitation on affiliate transactions

The Company will not, and will not permit any of its Restricted Subsidiaries to, directly or indirectly, enter into any transaction (including, without limitation, the purchase, sale, lease or exchange of any property or the rendering of any service) with any Affiliate of the Company (an "Affiliate Transaction") unless:

(1): the terms of such Affiliate Transaction are not materially less favorable to the Company or such Restricted Subsidiary, as the case may be, than those that could be obtained in a comparable transaction at the time of such transaction in arm's-length dealings with a Person who is not such an Affiliate;
(2): in the event such Affiliate Transaction involves an aggregate consideration to the Affiliate of the Company with a value in excess of $10.0 million, the terms of such transaction have been approved by a majority of the members of the Board of Directors of the Company and by a majority of the members of such Board having no personal stake in such transaction, if any (and such majority or majorities, as the case may be, determines that such Affiliate Transaction satisfies the criteria in clause (1) above); and
(3): in the event such Affiliate Transaction involves an aggregate consideration to the Affiliate of the Company with a value in excess of $25.0 million, the Company has received a written opinion from an independent investment banking, engineering, consulting, accounting or appraisal firm of nationally recognized standing, or other recognized firm or expert that in the

judgment of the Board of Directors of the Company is independent and qualified to render such opinion, either (i) that such Affiliate Transaction is fair, from a financial point of view, to the Company or the applicable Restricted Subsidiary, as the case may be, or (ii) that the terms of such Affiliate Transaction are not materially less favorable to the Company or the applicable Restricted Subsidiary, as the case may be, than those that might reasonably have been obtained in a comparable transaction at such time on an arm's length basis from a Person that is not an Affiliate.

The preceding paragraph will not apply to:

(1): any Restricted Payment (other than a Restricted Investment) permitted to be made pursuant to the covenant described under "—Limitation on restricted payments;"
(2): any issuance of securities, or other payments, awards or grants in cash, securities or otherwise pursuant to, or the funding of, employment agreements and other compensation arrangements, options to purchase Capital Stock of the Company, restricted stock plans, long-term incentive plans, stock appreciation rights plans, participation plans or other employee benefits plans and/or insurance and indemnification arrangements approved by the Board of Directors of the Company or the applicable Restricted Subsidiary provided to or for the benefit of directors, officers, employees, managers or consultants who are Affiliates of the Company;
(3): loans or advances to employees, officers, directors, managers and consultants who are Affiliates of the Company in the ordinary course of business of the Company or any Restricted Subsidiary, in an aggregate principal amount not in excess of $2.0 million with respect to all loans or advances made since the Issue Date (without giving effect to the forgiveness of any such loan);
(4): any transaction between the Company and a Restricted Subsidiary or between Restricted Subsidiaries and Guarantees issued by the Company or a Restricted Subsidiary for the benefit of the Company or a Restricted Subsidiary, as the case may be, in accordance with "—Limitations on indebtedness;"
(5): any transaction with a joint venture, partnership, limited liability company or other entity that would constitute an Affiliate Transaction solely because the Company or a Restricted Subsidiary owns an equity interest in such joint venture, partnership, limited liability company or other entity;
(6): the payment of reasonable and customary fees paid to, and indemnity provided on behalf of, directors of the Company or any Restricted Subsidiary;
(7): the existence of, and the performance of obligations of the Company or any of its Restricted Subsidiaries under the terms of, any agreement to which the Company or any of its Restricted Subsidiaries is a party as of or on the Issue Date, as these agreements may be amended, modified, supplemented, extended or renewed from time to time; provided, however, that any future amendment, modification, supplement, extension or renewal entered into after the Issue Date will be permitted to the extent that its terms are not more disadvantageous to the holders of the Notes than the terms of the agreements in effect on the Issue Date;

(8): transactions with customers, clients, suppliers or purchasers or sellers of goods or services that are Affiliates of the Company, in each case in the ordinary course of the business of the Company and its Restricted Subsidiaries and otherwise in compliance with the terms of the Indenture; provided that in the good faith reasonable determination of the Company, such transactions are on terms that are not materially less favorable, taken as a whole, to the Company or the relevant Restricted Subsidiary, as the case may be, than those that would have been obtained in a comparable transaction at such time by the Company or such Restricted Subsidiary from a Person that is not an Affiliate;
(9): any issuance or sale of Capital Stock or debt securities made to an Affiliate of the Company on the same terms as are being made to the non-Affiliate investors in any public or private issuance or sale of such Capital Stock or debt securities; provided, that any such issuance or sale complies with the requirements of clause (1) of the first paragraph of this covenant; and
(10): any issuance or sale of Capital Stock (other than Disqualified Stock) to Affiliates of the Company and the granting of registration and other customary rights in connection therewith.

Limitation on the sale of capital stock of restricted subsidiaries

The Company will not, and will not permit any Restricted Subsidiary to, transfer, convey, sell, lease or otherwise dispose of any Voting Stock of any Restricted Subsidiary or, with respect to a Restricted Subsidiary, to issue any of the Voting Stock of a Restricted Subsidiary (other than, if necessary, shares of its Voting Stock constituting directors' qualifying shares) to any Person except:

(1): to the Company or a Wholly Owned Subsidiary; or
(2): in compliance with the covenant described under "—Limitation on sales of assets and subsidiary stock" and immediately after giving effect to such issuance or sale, such Restricted Subsidiary would continue to be a Restricted Subsidiary.

Notwithstanding the preceding paragraph, the Company and its Restricted Subsidiaries may sell all the Voting Stock of a Restricted Subsidiary as long as the Company or its Restricted Subsidiaries comply with the terms of the covenant described under "—Limitation on sales of assets and subsidiary stock" (it being understood that only such portion of the Net Available Cash, if any, as is required to be applied on the date of such transaction in accordance with the terms of the Indenture needs to be applied in accordance therewith at such time).

SEC reports

Notwithstanding that the Company may not be subject to the reporting requirements of Section 13 or 15(d) of the Exchange Act, to the extent permitted by the Exchange Act, the Company will file with the SEC, and make available to the Trustee and the registered holders of the Notes, the annual reports and the information, documents and other reports (or copies of such portions of any of the foregoing as the SEC may by rules and regulations prescribe) that are specified in Sections 13 and 15(d) of the Exchange Act with respect to U.S. issuers within the time periods specified therein or in the relevant forms. In the event that the Company is not permitted to file such reports, documents and information with the SEC pursuant to the Exchange Act, the Company will nevertheless make available such Exchange Act information to the Trustee and the holders of the Notes as if the Company were subject to

the reporting requirements of Section 13 or 15(d) of the Exchange Act within the time periods specified therein or in the relevant forms.

If the Company has designated any of its Subsidiaries as Unrestricted Subsidiaries and the aggregate amount of net assets of all such Unrestricted Subsidiaries exceeds the greater of $10.0 million and 0.5% of Adjusted Consolidated Net Tangible Assets determined as of the filing date of any quarterly or annual report required by the preceding paragraph, then the quarterly and annual financial information required by the preceding paragraph shall include a reasonably detailed presentation, either on the face of the financial statements or in the footnotes to the financial statements and in Management's Discussion and Analysis of Results of Operations and Financial Condition, of the financial condition and results of operations of the Company and its Restricted Subsidiaries.

In addition, the Company and the Subsidiary Guarantors have agreed that they will make available to the holders and to prospective investors, upon the request of such holders, the information required to be delivered pursuant to Rule 144A(d)(4) under the Securities Act so long as the Notes are not freely transferable under the Securities Act.

For purposes of this covenant, the Company and the Subsidiary Guarantors will be deemed to have furnished the reports to the Trustee and the holders of Notes as required by this covenant if it has filed such reports with the SEC via the EDGAR filing system and such reports are publicly available.

In the event that any direct or indirect parent company of the Company becomes a guarantor of the Notes, the Company may satisfy its obligations under this covenant by furnishing financial information relating to such parent; provided that (a) such financial statements are accompanied by consolidating financial information for such parent, the Company, the Subsidiary Guarantors and the Subsidiaries of the Company that are not Subsidiary Guarantors in the manner prescribed by the SEC and (b) such parent is not engaged in any business in any material respect other than incidental to its ownership, directly or indirectly, of the Capital Stock of the Company.

Merger and consolidation

The Company will not consolidate with or merge with or into, or convey, transfer or lease all or substantially all its assets to, any Person, unless:

(1): the resulting, surviving or transferee Person (the "Successor Company") will be a corporation, partnership, trust or limited liability company organized and existing under the laws of the United States of America, any State of the United States or the District of Columbia and the Successor Company (if not the Company) will expressly assume, by supplemental indenture, executed and delivered to the Trustee, in form satisfactory to the Trustee, all the obligations of the Company under the Notes and the Indenture; provided, that if the Successor Company is not a corporation, a corporate Wholly Owned Subsidiary that is a Restricted Subsidiary organized under the laws of the United States of America, any State thereof or the District of Columbia shall become a co-issuer of the Notes;
(2): immediately after giving effect to such transaction (and treating any Indebtedness not previously an obligation of the Company or any of its Restricted Subsidiaries that becomes an obligation of the Successor Company or any Subsidiary of the Successor Company as a result of

such transaction as having been Incurred by the Successor Company or such Subsidiary at the time of such transaction), no Default or Event of Default shall have occurred and be continuing;

(3): immediately after giving effect to such transaction, the Successor Company would be able to Incur at least $1.00 of additional Indebtedness pursuant to the first paragraph of the "—Limitation on indebtedness" covenant;
(4): each Subsidiary Guarantor (unless it is the other party to the transactions above, in which case clause (1) shall apply) shall have by supplemental indenture confirmed that its Subsidiary Guarantee shall apply to such Person's obligations in respect of the Indenture and the Notes; and
(5): the Company shall have delivered to the Trustee an Officers' Certificate and an Opinion of Counsel, each stating that such consolidation, merger or transfer and such supplemental indenture (if any) comply with the Indenture.

For purposes of this covenant, the sale, lease, conveyance, assignment, transfer, or other disposition of all or substantially all of the properties and assets of one or more Subsidiaries of the Company, which properties and assets, if held by the Company instead of such Subsidiaries, would constitute all or substantially all of the properties and assets of the Company on a consolidated basis, shall be deemed to be the transfer of all or substantially all of the properties and assets of the Company.

The predecessor Company will be released from its obligations under the Indenture and the Successor Company will succeed to, and be substituted for, and may exercise every right and power of, the Company under the Indenture, but, in the case of a lease of all or substantially all its assets, the predecessor Company will not be released from the obligation to pay the principal of and interest on the Notes.

Although there is a limited body of case law interpreting the phrase "substantially all," there is no precise established definition of the phrase under applicable law. Accordingly, in certain circumstances there may be a degree of uncertainty as to whether a particular transaction would involve "all or substantially all" of the property or assets of a Person.

Notwithstanding the preceding clauses (2) and (3), (a) any Restricted Subsidiary may consolidate with, merge into or transfer all or part of its properties and assets to the Company and (b) the Company may merge with an Affiliate incorporated or organized solely for the purpose of reincorporating or reorganizing the Company in another jurisdiction to realize tax benefits; provided that, in the case of a Restricted Subsidiary that merges into the Company, the Company will not be required to comply with the preceding clause (5).

In addition, the Company will not permit any Subsidiary Guarantor to consolidate with, merge with or into any Person (other than the Company or another Subsidiary Guarantor) and will not permit the conveyance, transfer or lease of all or substantially all of the assets of any Subsidiary Guarantor (other than to the Company or another Subsidiary Guarantor) unless:

(1): (a) if such entity remains a Subsidiary Guarantor, the resulting, surviving or transferee Person will be a corporation, partnership, trust or limited liability company organized and existing under the laws of the United States of America, any State of the United States or the District of Columbia and shall have by supplemental indenture confirmed that its Subsidiary

Guarantee shall apply to such Person's obligations in respect of the Indenture and the Notes; (b) immediately after giving effect to such transaction (and treating any Indebtedness not previously an obligation of the Company or any of its Subsidiaries that becomes an obligation of the resulting, surviving or transferee Person or any Restricted Subsidiary as a result of such transaction as having been Incurred by such Person or such Restricted Subsidiary at the time of such transaction), no Default of Event of Default shall have occurred and be continuing; and (c) the Company will have delivered to the Trustee an Officers' Certificate and an Opinion of Counsel, each stating that such consolidation, merger or transfer and such supplemental indenture (if any) comply with the Indenture; and

(2): if applicable, the transaction is made in compliance with the covenant described under "—Limitation on sales of assets and subsidiary stock" (it being understood that only such portion of the Net Available Cash, if any, as is required to be applied on the date of such transaction in accordance with the terms of the Indenture needs to be applied in accordance therewith at such time), "—Limitation on the sale of capital stock of restricted subsidiaries" and this "—Merger and consolidation" covenant.

Future subsidiary guarantors

The Company will cause each Restricted Subsidiary (other than a Foreign Subsidiary) that Guarantees, on the Issue Date or any time thereafter, Indebtedness of the Company under the Senior Secured Credit Agreement to execute and deliver to the Trustee a supplemental indenture pursuant to which such Restricted Subsidiary will unconditionally Guarantee, on a joint and several basis, the full and prompt payment of the principal of, premium, if any, and interest in respect of the Notes on a senior unsecured basis and all other obligations under the Indenture on an unsecured basis. Notwithstanding the foregoing, in the event (a) a Subsidiary Guarantor is released and discharged in full from all of its obligations under its Guarantees of (1) the Senior Secured Credit Agreement and (2) all other Indebtedness of the Company and its Restricted Subsidiaries and (b) such Subsidiary Guarantor has not Incurred any Indebtedness in reliance on its status as a Subsidiary Guarantor under the covenant "—Limitation on indebtedness" or such Subsidiary Guarantor's obligations under such Indebtedness are satisfied in full and discharged or are otherwise permitted to be Incurred by a Restricted Subsidiary (other than a Subsidiary Guarantor) under the second paragraph of "—Limitation on indebtedness," then the Subsidiary Guarantee of such Subsidiary Guarantor shall be automatically and unconditionally released or discharged.

The obligations of each Subsidiary Guarantor will be limited to the maximum amount as will, after giving effect to all other contingent and fixed liabilities of such Subsidiary Guarantor (including, without limitation, any Guarantees under the Senior Secured Credit Agreement) and after giving effect to any collections from or payments made by or on behalf of any other Subsidiary Guarantor in respect of the obligations of such other Subsidiary Guarantor under its Subsidiary Guarantee or pursuant to its contribution obligations under the Indenture, result in the obligations of such Subsidiary Guarantor under its Subsidiary Guarantee not constituting a fraudulent conveyance or fraudulent transfer under federal or state law.

Each Subsidiary Guarantee shall also be released in accordance with the provisions of the Indenture described under "Subsidiary guarantees."

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Limitation on lines of business

The Company will not, and will not permit any Restricted Subsidiary to, engage in any material business other than the Oil and Gas Business.

Payments for consent

Neither the Company nor any of its Restricted Subsidiaries will, directly or indirectly, pay or cause to be paid any consideration, whether by way of interest, fees or otherwise, to any holder of any Notes for or as an inducement to any consent, waiver or amendment of any of the terms or provisions of the Indenture or the Notes unless such consideration is offered to be paid or is paid to all holders of the Notes that consent, waive or agree to amend in the time frame set forth in the solicitation documents relating to such consent, waiver or amendment.

Events of default

Each of the following is an Event of Default:

(1)

default in any payment of interest on any Note when due, continued for 30 days;

(2)

default in the payment of principal of or premium, if any, on any Note when due at its Stated Maturity, upon optional redemption, upon required repurchase, upon declaration or otherwise;

(3)

failure by the Company or any Subsidiary Guarantor to comply with its obligations under "—Certain covenants—Merger and consolidation;"

(4)

failure by the Company to comply for 30 days after notice as provided below with any of its obligations under the covenants described under "—Change of control" above or under the covenants described under "—Certain covenants" above (in each case, other than (a) a failure to purchase Notes which constitutes an Event of Default under clause (2) above, (b) a failure to comply with "—Certain covenants—Merger and consolidation" which constitutes an Event of Default under clause (3) above or (c) a failure to comply with "—Certain covenants—SEC reports" which constitutes an Event of Default under clause (5) below);

(5)

failure by the Company to comply for 60 days after notice as provided below with its other agreements contained in the Indenture (other than a failure to comply with "—Certain covenants—SEC reports"), or a failure by the Company to comply, for 90 days after notice as provided below, with its agreements under "—Certain covenants—SEC reports;"

(6)

default under any mortgage, indenture or instrument under which there is issued or by which there is secured or evidenced any Indebtedness for money borrowed by the Company or any of its Restricted Subsidiaries (or the payment of which is guaranteed by the Company or any of its Restricted Subsidiaries), other than Indebtedness owed to the Company or a Restricted Subsidiary, whether such Indebtedness or guarantee now exists, or is created after the Issue Date, which default:

(a): is caused by a failure to pay principal of, or interest or premium, if any, on such Indebtedness prior to the expiration of the grace period provided in such Indebtedness ("payment default"); or

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(b): results in the acceleration of such Indebtedness prior to its maturity (the "cross acceleration provision");

and, in each case, the principal amount of any such Indebtedness, together with the principal amount of any other such outstanding Indebtedness under which there is an outstanding uncured payment default or the maturity of which has been and remains so accelerated, aggregates $15.0 million or more;

(7): certain events of bankruptcy, insolvency or reorganization of the Company or a Significant Subsidiary or group of Restricted Subsidiaries that, taken together (as of the latest audited consolidated financial statements for the Company and its Restricted Subsidiaries), would constitute a Significant Subsidiary (the "bankruptcy provisions");
(8): failure by the Company or any Significant Subsidiary or group of Restricted Subsidiaries that, taken together (as of the latest audited consolidated financial statements for the Company and its Restricted Subsidiaries), would constitute a Significant Subsidiary to pay final judgments aggregating in excess of $15.0 million (net of any amounts that a reputable and creditworthy insurance company has acknowledged liability for in writing), which judgments are not paid, discharged or stayed for a period of 60 days after such judgment becomes final and no longer subject to appeal (the "judgment default provision"); or
(9): any Subsidiary Guarantee of a Significant Subsidiary or group of Restricted Subsidiaries that taken together as of the latest audited consolidated financial statements for the Company and its Restricted Subsidiaries would constitute a Significant Subsidiary ceases to be in full force and effect (except as contemplated by the terms of the Indenture) or is declared null and void in a judicial proceeding or any Subsidiary Guarantor that is a Significant Subsidiary or group of Subsidiary Guarantors that taken together as of the latest audited consolidated financial statements of the Company and its Restricted Subsidiaries would constitute a Significant Subsidiary denies or disaffirms its obligations under the Indenture or its Subsidiary Guarantee.

However, a default under clauses (4) and (5) of this paragraph will not constitute an Event of Default until the Trustee or the holders of 25% in principal amount of the outstanding Notes notify the Company in writing of the default and the Company does not cure such default within the time specified in clauses (4) and (5) of this paragraph after receipt of such notice. Such notice must specify the Default, demand that it be remedied and state that such notice is a "Notice of Default."

If an Event of Default (other than an Event of Default described in clause (7) above) has occurred and is continuing, the Trustee by written notice to the Company, or the holders of at least 25% in principal amount of the outstanding Notes by written notice to the Company and the Trustee, may, and the Trustee at the request of such holders shall, declare the principal of, premium, if any, and accrued and unpaid interest, if any, on all the Notes to be due and payable. Such notice must specify the Event of Default and state that such notice is a "Notice of Acceleration." Upon such a declaration, such principal, premium and accrued and unpaid interest will be due and payable immediately. In the event of a declaration of acceleration of the Notes because an Event of Default described in clause (6) under "—Events of default" has occurred and is continuing, the declaration of acceleration of the Notes shall be automatically annulled if the default triggering such Event of Default pursuant to clause (6) shall be remedied or cured by the Company or a Restricted Subsidiary or waived by the holders of the

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relevant Indebtedness within 20 days after the written notice of declaration of acceleration of the Notes with respect thereto is received by the Company and if (1) the annulment of the acceleration of the Notes would not conflict with any judgment or decree of a court of competent jurisdiction and (2) all existing Events of Default, except nonpayment of principal, premium or interest on the Notes that became due solely because of the acceleration of the Notes, have been cured or waived. If an Event of Default described in clause (7) above occurs and is continuing, the principal of, premium, if any, and accrued and unpaid interest on all the Notes will become and be immediately due and payable without any declaration or other act on the part of the Trustee or any holders. The holders of a majority in principal amount of the outstanding Notes may waive all past defaults (except with respect to nonpayment of principal, premium or interest) and rescind any such acceleration with respect to the Notes and its consequences if (1) rescission would not conflict with any judgment or decree of a court of competent jurisdiction and (2) all existing Events of Default, other than the nonpayment of the principal of, premium, if any, and interest on the Notes that have become due solely by such declaration of acceleration, have been cured or waived.

Subject to the provisions of the Indenture relating to the duties of the Trustee, if an Event of Default occurs and is continuing, the Trustee will be under no obligation to exercise any of the rights or powers under the Indenture at the request or direction of any of the holders unless such holders have offered to the Trustee reasonable indemnity or security against any loss, liability or expense. Except to enforce the right to receive payment of principal, premium, if any, or interest when due, no holder may pursue any remedy with respect to the Indenture or the Notes unless:

(1): such holder has previously given the Trustee notice that an Event of Default is continuing;
(2): holders of at least 25% in principal amount of the outstanding Notes have requested the Trustee to pursue the remedy;
(3): such holders have offered the Trustee reasonable security or indemnity against any loss, liability or expense;
(4): the Trustee has not complied with such request within 60 days after the receipt of the request and the offer of security or indemnity; and
(5): the holders of a majority in principal amount of the outstanding Notes have not given the Trustee a direction that, in the opinion of the Trustee, is inconsistent with such request within such 60 day period.

Subject to certain restrictions, the holders of a majority in principal amount of the outstanding Notes are given the right to direct the time, method and place of conducting any proceeding for any remedy available to the Trustee or of exercising any trust or power conferred on the Trustee. The Indenture provides that in the event an Event of Default has occurred and is continuing, the Trustee will be required in the exercise of its powers to use the degree of care that a prudent person would use in the conduct of its own affairs. The Trustee, however, may refuse to follow any direction that conflicts with law or the Indenture or that the Trustee determines is unduly prejudicial to the rights of any other holder or that would involve the Trustee in personal liability. Prior to taking any action under the Indenture, the Trustee will be entitled to indemnification satisfactory to it in its sole discretion against all losses and expenses caused by taking or not taking such action.

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The Indenture provides that if a Default occurs and is continuing and is known to the Trustee, the Trustee must mail to each holder notice of the Default within 90 days after it occurs. Except in the case of a Default in the payment of principal of, premium, if any, or interest on any Note, the Trustee may withhold notice if and so long as the board of directors or a committee of the board of directors of the Trustee or a committee of its Responsible Officers and/or a Responsible Officer of the Trustee in good faith determines that withholding notice is in the interests of the holders. In addition, the Company is required to deliver to the Trustee, within 120 days after the end of each fiscal year, a certificate indicating whether the signers thereof know of any Default that occurred during the previous year. The Company also is required to deliver to the Trustee, within 30 days after the occurrence thereof, written notice of any events which would constitute certain Defaults, their status and what action the Company is taking or proposing to take in respect thereof.

Amendments and waivers

Subject to certain exceptions, the Indenture and the Notes may be amended or supplemented with the consent of the holders of a majority in principal amount of the Notes then outstanding (including without limitation, consents obtained in connection with a purchase of, or tender offer or exchange offer for, Notes) and, subject to certain exceptions, any past default or compliance with any provisions may be waived with the consent of the holders of a majority in principal amount of the Notes then outstanding (including, without limitation, consents obtained in connection with a purchase of, or tender offer or exchange offer for, Notes). However, without the consent of each holder of an outstanding Note affected, no amendment, supplement or waiver may, among other things:

(1): reduce the amount of Notes whose holders must consent to an amendment;
(2): reduce the stated rate of or extend the stated time for payment of interest on any Note;
(3): reduce the principal of or extend the Stated Maturity of any Note;
(4): reduce the premium payable upon the redemption or repurchase of any Note or change the time at which any Note may be redeemed or repurchased as described above under "—Optional redemption," "—Change of control" or "—Certain covenants—Limitation on sales of assets and subsidiary stock" whether through an amendment or waiver of provisions in the covenants, definitions or otherwise (except amendments to the definition of "Change of Control");
(5): make any Note payable in money other than that stated in the Note;
(6): impair the right of any holder to receive payment of principal, premium, if any, and interest on such holder's Notes on or after the due dates therefor or to institute suit for the enforcement of any payment on or with respect to such holder's Notes;
(7): make any change in the amendment provisions which require each holder's consent or in the waiver provisions; or
(8): modify the Subsidiary Guarantees in any manner adverse to the holders of the Notes.

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Notwithstanding the foregoing, without the consent of any holder, the Company, the Subsidiary Guarantors and the Trustee may amend or supplement the Indenture, the Notes and the Subsidiary Guarantees to:

(1): cure any ambiguity, omission, defect or inconsistency;
(2): provide for the assumption by a successor of the obligations of the Company or any Subsidiary Guarantor under the Indenture;
(3): provide for uncertificated Notes in addition to or in place of certificated Notes (provided that the uncertificated Notes are issued in registered form for purposes of Section 163(f) of the Code, or in a manner such that the uncertificated Notes are described in Section 163(f) (2) (B) of the Code);
(4): add Guarantees with respect to the Notes;
(5): release a Subsidiary Guarantor from its obligations under its Subsidiary Guarantee or the Indenture in accordance with the applicable provisions of the Indenture;
(6): secure the Notes;
(7): add to the covenants of the Company, any Subsidiary Guarantor or other obligor under the Indenture, Notes or Subsidiary Guarantees, as the case may be, for the benefit of the holders or surrender any right or power conferred upon the Company, any Subsidiary Guarantor or other such obligor;
(8): make any change that does not adversely affect the legal or contractual rights of any holder under the Indenture, the Notes or the Subsidiary Guarantees;
(9): comply with any requirement of the SEC in connection with the qualification of the Indenture under the Trust Indenture Act;
(10): provide for the appointment of a successor trustee; provided that the successor trustee is otherwise qualified and eligible to act as such under the terms of the Indenture;
(11): provide for the issuance of Additional Notes under the Indenture in accordance with the limitations described in the Indenture;
(12): to comply with the rules of any applicable securities depositary; or
(13): conform the text of the Indenture, the Notes or the Subsidiary Guarantees to any provision of this "Description of notes."

The consent of the holders is not necessary under the Indenture to approve the particular form of any proposed amendment or supplement. It is sufficient if such consent approves the substance of the proposed amendment or supplement. A consent to any amendment, supplement or waiver under the Indenture by any holder of Notes given in connection with a tender of such holder's Notes will not be rendered invalid by such tender. After an amendment or supplement under the Indenture becomes effective, the Company is required to mail to the holders a notice briefly describing such amendment or supplement. However, the failure to give such notice to all the holders, or any defect in the notice will not impair or affect the validity of the amendment or supplement.

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Defeasance

The Company at any time may terminate all its obligations under the Notes and the Indenture ("legal defeasance"), except for certain obligations, including those respecting the defeasance trust and obligations to register the transfer or exchange of the Notes, to replace mutilated, destroyed, lost or stolen Notes and to maintain a registrar and paying agent in respect of the Notes. If the Company exercises its legal defeasance option, the Subsidiary Guarantees in effect at such time will terminate.

The Company at any time may terminate its obligations described under "—Change of control" and under the covenants described under "—Certain covenants" (other than "—Merger and consolidation"), the operation of the cross-default upon a payment default, cross acceleration provisions, the bankruptcy provisions with respect to Significant Subsidiaries, the judgment default provision described under "—Events of default" above and the limitations contained in clause (3) under "—Certain covenants—Merger and consolidation" above ("covenant defeasance").

The Company may exercise its legal defeasance option notwithstanding its prior exercise of its covenant defeasance option. If the Company exercises its legal defeasance option, payment of the Notes may not be accelerated because of an Event of Default with respect to the Notes. If the Company exercises its covenant defeasance option, payment of the Notes may not be accelerated because of an Event of Default specified in clause (4), (5), (6), (7) (with respect only to Significant Subsidiaries), (8) or (9) under "—Events of default" above or because of the failure of the Company to comply with clause (3) under "—Certain covenants—Merger and consolidation" above.

In order to exercise either defeasance option, the Company must irrevocably deposit in trust (the "defeasance trust") with the Trustee money or U.S. Government Obligations for the payment of principal, premium, if any, and interest on the Notes to redemption or maturity, as the case may be, and must comply with certain other conditions, including, without limitation, delivery to the Trustee of an Opinion of Counsel (subject to customary exceptions and exclusions) to the effect that holders of the Notes will not recognize income, gain or loss for Federal income tax purposes as a result of such deposit and defeasance and will be subject to Federal income tax on the same amount and in the same manner and at the same times as would have been the case if such deposit and defeasance had not occurred. In the case of legal defeasance only, such Opinion of Counsel must be based on a ruling of the Internal Revenue Service or other change in applicable Federal income tax law.

If the Company fails to comply with its remaining obligations under the Indenture with respect to the Notes following a covenant defeasance and the Notes are declared due and payable because of the occurrence of any undefeased Event of Default, the amount of money and U.S. Government Obligations on deposit with the Trustee may be insufficient to pay amounts due on the Notes at the time of the acceleration resulting from such Event of Default; however, the Company will remain liable in respect of such payments.

No personal liability of directors, officers, employees and stockholders

No director, officer, employee, manager, member, partner, incorporator or stockholder of the Company or any Subsidiary Guarantor, as such, shall have any liability for any obligations of

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the Company or any Subsidiary Guarantor under the Notes, the Indenture or the Subsidiary Guarantees or for any claim based on, in respect of, or by reason of, such obligations or their creation. Each holder by accepting a Note waives and releases all such liability. The waiver and release are part of the consideration for issuance of the Notes. Such waiver may not be effective to waive liabilities under the federal securities laws and it is the view of the SEC that such a waiver is against public policy.

Concerning the trustee

U.S. Bank National Association is the Trustee under the Indenture and has been appointed by the Company as Registrar and Paying Agent with regard to the Notes.

Governing law

The Indenture provides that it and the Notes will be governed by, and construed in accordance with, the laws of the State of New York.

Certain definitions

"Acquired Indebtedness" means Indebtedness (1) of a Person or any of its Subsidiaries existing at the time such Person becomes a Restricted Subsidiary or (2) assumed in connection with the acquisition of assets from such Person, in each case whether or not Incurred by such Person in connection with, or in anticipation or contemplation of, such Person becoming a Restricted Subsidiary or such acquisition. Acquired Indebtedness shall be deemed to have been Incurred, with respect to clause (1) of the preceding sentence, on the date such Person becomes a Restricted Subsidiary and, with respect to clause (2) of the preceding sentence, on the date of consummation of such acquisition of assets.

"Additional Assets" means:

(1): any property, plant, equipment or other asset (excluding current assets) to be used by the Company or a Restricted Subsidiary in the Oil and Gas Business;
(2): capital expenditures by the Company or a Restricted Subsidiary in the Oil and Gas Business;
(3): the Capital Stock of a Person that becomes a Restricted Subsidiary as a result of the acquisition of such Capital Stock by the Company or a Restricted Subsidiary; or
(4): Capital Stock constituting a minority interest in any Person that at such time is a Restricted Subsidiary;

provided, however, that, in the case of clauses (3) and (4), such Restricted Subsidiary is primarily engaged in the Oil and Gas Business.

"Adjusted Consolidated Net Tangible Assets" means (without duplication), as of the date of determination, the remainder of:

(a)

the sum of:

(i): the Company's good faith estimate of discounted future net revenues from proved oil and gas reserves of the Company and its Restricted Subsidiaries calculated in accordance with SEC guidelines before any provincial, territorial, state, Federal or foreign income taxes,

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as estimated by the Company in a reserve report prepared as of the end of the Company's most recently completed fiscal year for which audited financial statements are available, as increased by, as of the date of determination, the estimated discounted future net revenues from:

(A): estimated proved oil and gas reserves acquired since such year end, which reserves were not reflected in such year end reserve report, and
(B): estimated oil and gas reserves attributable to upward revisions of estimates of proved oil and gas reserves since such year end due to exploration, development, exploitation or other related activities, in each case calculated in accordance with SEC guidelines (utilizing the prices for the fiscal quarter ending prior to the date of determination),

and decreased by, as of the date of determination, the estimated discounted future net revenues from:

(C): estimated proved oil and gas reserves produced or disposed of since such year end, and
(D): estimated oil and gas reserves attributable to downward revisions of estimates of proved oil and gas reserves since such year end due to changes in geological conditions or other factors which would, in accordance with standard industry practice, cause such revisions, in each case calculated on a pre-tax basis and substantially in accordance with SEC guidelines (utilizing the prices for the fiscal quarter ending prior to the date of determination),

in each case as estimated by the Company's petroleum engineers or any independent petroleum engineers engaged by the Company for that purpose;

(ii)

the capitalized costs that are attributable to Oil and Gas Properties of the Company and its Restricted Subsidiaries to which no proved oil and gas reserves are attributable, based on the Company's books and records as of a date no earlier than the date of the Company's latest available annual or quarterly consolidated financial statements;

(iii)

the Net Working Capital on a date no earlier than the date of the Company's latest available annual or quarterly consolidated financial statements; and

(iv)

the greater of:

(A): the net book value of other tangible assets of the Company and its Restricted Subsidiaries, as of a date no earlier than the date of the Company's latest available annual or quarterly consolidated financial statements, and
(B): the appraised value, as estimated by independent appraisers, of other tangible assets of the Company and its Restricted Subsidiaries, as of a date no earlier than the date of the Company's latest available audited consolidated financial statements (provided that, the Company may rely on subclause (A) of this clause (iv) if no appraisal is available or has been obtained); minus

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(b)

the sum of:

(i): any amount included in (a)(i) through (a)(iv) above that is attributable to Minority Interests;
(ii): any net gas balancing liabilities of the Company and its Restricted Subsidiaries reflected in the Company's latest audited consolidated financial statements;
(iii): to the extent included in (a)(i) above, the Company's good faith estimate of discounted future net revenues, calculated in accordance with SEC guidelines (utilizing the prices utilized in the Company's year end reserve report), attributable to reserves which are required to be delivered to third parties to fully satisfy the obligations of the Company and its Restricted Subsidiaries with respect to Volumetric Production Payments (determined, if applicable, using the schedules specified with respect thereto); and
(iv): to the extent included in (a)(i) above, the Company's good faith estimate of discounted future net revenues, calculated in accordance with SEC guidelines, attributable to reserves subject to Dollar-Denominated Production Payments which, based on the estimates of production and price assumptions included in determining the discounted future net revenues specified in (a)(i) above, would be necessary to fully satisfy the payment obligations of the Company and its Restricted Subsidiaries with respect to Dollar-Denominated Production Payments (determined, if applicable, using the schedules specified with respect thereto).

If the Company changes its method of accounting from the full cost method of accounting to the successful efforts or a similar method, "Adjusted Consolidated Net Tangible Assets" will continue to be calculated as if the Company were still using the full cost method of accounting.

"Affiliate" of any specified Person means any other Person, directly or indirectly, controlling or controlled by or under direct or indirect common control with such specified Person. For the purposes of this definition, "control" when used with respect to any Person means the power to direct the management and policies of such Person, directly or indirectly, whether through the ownership of voting securities, by contract or otherwise; and the terms "controlling" and "controlled" have meanings correlative to the foregoing.

"Asset Disposition" means any direct or indirect sale, lease (other than an operating lease entered into in the ordinary course of business), transfer, issuance or other disposition, or a series of related sales, leases, transfers, issuances or dispositions that are part of a common plan, of shares of Capital Stock of a Subsidiary (other than directors' qualifying shares), property or other assets (each referred to for the purposes of this definition as a "disposition") by the Company or any of its Restricted Subsidiaries, including, without limitation, any disposition by means of a merger, consolidation or similar transaction.

Notwithstanding the preceding, the following items shall not be deemed to be Asset Dispositions:

(1): a disposition of property or other assets by a Restricted Subsidiary to the Company or by the Company or a Restricted Subsidiary to a Restricted Subsidiary; provided that in the case of a sale by a Restricted Subsidiary to another Restricted Subsidiary, the Company directly or

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indirectly owns an equal or greater percentage of the Common Stock of the transferee than of the transferor;

(2): the disposition of cash or Cash Equivalents in the ordinary course of business;
(3): a disposition of Hydrocarbons or mineral products inventory in the ordinary course of the Oil and Gas Business;
(4): a disposition of obsolete or worn out equipment or equipment that is no longer useful in the conduct of the business of the Company and its Restricted Subsidiaries and that is disposed of in each case in the ordinary course of business;
(5): transactions permitted under "—Certain covenants—Merger and consolidation;"
(6): an issuance of Capital Stock by a Restricted Subsidiary to the Company or to a Wholly Owned Subsidiary or on a pro rata basis to the holders of the Capital Stock of such Restricted Subsidiary immediately prior to such issuance;
(7): for purposes of "—Certain covenants—Limitation on sales of assets and subsidiary stock" only, the making of a Permitted Investment (other than a Permitted Investment to the extent such transaction is made in exchange for cash or Cash Equivalents to be received by the Company or its Restricted Subsidiaries) or a disposition subject to "—Certain covenants—Limitation on restricted payments;"
(8): an Asset Swap;
(9): dispositions of properties or assets with an aggregate fair market value not to exceed $5.0 million in any fiscal year of the Company;
(10): the creation of a Permitted Lien and dispositions in connection with Permitted Liens;
(11): dispositions of receivables in connection with the compromise, settlement or collection thereof in the ordinary course of business or in bankruptcy or similar proceedings and exclusive of factoring or similar arrangements;
(12): any surrender or waiver of contract rights or settlement, release or surrender of contract, tort or other claims in the ordinary course of business;
(13): the issuance by a Restricted Subsidiary of Preferred Stock that is permitted by the covenant described under the caption "—Certain covenants—Limitation on indebtedness;"
(14): the licensing or sublicensing of intellectual property or other general intangibles and licenses, sublicenses, leases or subleases of other property in the ordinary course of business which do not materially interfere with the business of the Company and its Restricted Subsidiaries;
(15): foreclosure on assets;
(16): any Production Payments and Reserve Sales, provided that any such Production Payments and Reserve Sales, other than incentive compensation programs on terms that are reasonably customary in the Oil and Gas Business for geologists, geophysicists and other providers of technical services to the Company or a Restricted Subsidiary, shall have been created, Incurred,

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issued, assumed or Guaranteed in connection with the acquisition or financing of, and within 60 days after the acquisition of, the property that is subject thereto;

(17): the disposition (whether or not in the ordinary course of the Oil and Gas Business) of oil and/or gas properties or direct or indirect interests in real property; provided, that at the time of such sale or transfer such properties do not have associated with them any proved reserves capable of being produced in material economic quantities;
(18): the sale or transfer (whether or not in the ordinary course of the Oil and Gas Business) of oil and/or gas properties or direct or indirect interests in real property; provided, that at the time of such sale or transfer such properties do not have associated with them any proved reserves capable of being produced in material economic quantities;
(19): the abandonment, farm-out, exchange, lease or sublease of developed or undeveloped oil and/or gas properties or interests therein in the ordinary course of business or in exchange for oil and/or gas properties or interests therein owned or held by another Person; and
(20): the disposition of Capital Stock in an Unrestricted Subsidiary.

"Asset Swap" means any trade or exchange by the Company or any Restricted Subsidiary of oil and gas properties or other properties or assets for oil and gas properties or other properties or assets owned or held by another Person; provided that the fair market value of the properties or assets traded or exchanged by the Company or such Restricted Subsidiary (together with any cash) is reasonably equivalent to the fair market value of the properties or assets (together with any cash) to be received by the Company or such Restricted Subsidiary, and provided further that any net cash received must be applied in accordance with "—Certain covenants—Limitations on sales of assets and subsidiary stock."

"Attributable Indebtedness" in respect of a Sale/Leaseback Transaction means, as at the time of determination, the present value (discounted at the interest rate implicit in the transaction) of the total obligations of the lessee for rental payments during the remaining term of the lease included in such Sale/Leaseback Transaction (including any period for which such lease has been extended), determined in accordance with GAAP; provided, however, that if such Sale/Leaseback Transaction results in a Capitalized Lease Obligation, the amount of Indebtedness represented thereby will be determined in accordance with the definition of "Capitalized Lease Obligations."

"Average Life" means, as of the date of determination, with respect to any Indebtedness or Preferred Stock, the quotient obtained by dividing (1) the sum of the products of the numbers of years from the date of determination to the dates of each successive scheduled principal payment of such Indebtedness or redemption or similar payment with respect to such Preferred Stock multiplied by the amount of such payment by (2) the sum of all such payments.

"Board of Directors" means, (i) as to any Person that is a corporation, the board of directors of such Person or any duly authorized committee thereof, (ii) as to any Person that is a partnership (general or limited), the Board of Directors of a general partner of such partnership or any duly authorized committee thereof, or (iii) with respect to any other Person, the Person or group of Persons serving a similar function or any duly authorized committee thereof;

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"Business Day" means each day that is not a Saturday, Sunday or other day on which banking institutions in New York, New York are authorized or required by law to close.

"Capital Stock" of any Person means any and all shares, interests, rights to purchase, warrants, options, participations or other equivalents of or interests in (however designated) equity of such Person, including, without limitation, any Preferred Stock and limited liability company or partnership interests (whether general or limited) of such Person, but excluding any debt securities (including, without limitation, the Company's floating rate convertible senior notes due 2023) convertible into such equity.

"Capitalized Lease Obligations" means an obligation that is required to be classified and accounted for as a capitalized lease for financial reporting purposes in accordance with GAAP, and the amount of Indebtedness represented by such obligation will be the capitalized amount of such obligation at the time any determination thereof is to be made as determined in accordance with GAAP, and the Stated Maturity thereof will be the date of the last payment of rent or any other amount due under such lease prior to the first date such lease may be terminated without penalty.

"Cash Equivalents" means:

(1): securities issued or directly and fully guaranteed or insured by the United States Government or any agency or instrumentality of the United States (provided that the full faith and credit of the United States is pledged in support thereof), having maturities of not more than one year from the date of acquisition;
(2): marketable general obligations issued by any state of the United States of America or any political subdivision of any such state or any public instrumentality thereof maturing within one year from the date of acquisition thereof and, at the time of acquisition, having a credit rating of at least "A" or the equivalent thereof by either Standard & Poor's or Moody's Investors Service, Inc. (or, if both such rating agencies cease publishing ratings of such investments, an equivalent rating from a nationally recognized rating agency);
(3): certificates of deposit, time deposits, eurodollar time deposits, overnight bank deposits or bankers' acceptances having maturities of not more than one year from the date of acquisition thereof issued by any commercial bank the long term debt of which is rated at the time of acquisition thereof at least "A" or the equivalent thereof by Standard & Poor's or Moody's Investors Service, Inc. (or, if both such rating agencies cease publishing ratings of such investments, an equivalent rating from a nationally recognized rating agency), and having combined capital and surplus in excess of $500 million;
(4): repurchase obligations with a term of not more than seven days for underlying securities of the types described in clauses (1), (2) and (3) entered into with any bank meeting the qualifications specified in clause (3) above;
(5): commercial paper rated at the time of acquisition thereof at least "A-2" or the equivalent thereof by Standard & Poor's or "P-2" or the equivalent thereof by Moody's Investors Service, Inc. (or carrying an equivalent rating by a nationally recognized rating agency, if both of the two named rating agencies cease publishing ratings of such investments), and in any case maturing within one year after the date of acquisition thereof;

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(6): interests in any investment company or money market fund which invests 95% or more of its assets in instruments of the type specified in clauses (1) through (5) above; and
(7): in the case of any Foreign Subsidiary that is a Restricted Subsidiary, such local currencies held by it from time to time in the ordinary course of business.

"Change of Control" means:

(1): any "person" or "group" of related persons (as such terms are used in Sections 13(d) and 14(d) of the Exchange Act) becomes the beneficial owner (as defined in Rules 13d-3 and 13d-5 under the Exchange Act, except that such person or group shall be deemed to have "beneficial ownership" of all shares that any such person or group has the right to acquire, whether such right is exercisable immediately or only after the passage of time), directly or indirectly, of more than 35% of the total voting power of the Voting Stock of the Company (or its successor by merger, consolidation or purchase of all or substantially all of its assets) (for the purposes of this clause, such person or group shall be deemed to beneficially own any Voting Stock of the Company held by a parent entity, if such person or group "beneficially owns" (as defined above), directly or indirectly, more than 35% of the voting power of the Voting Stock of such parent entity); provided, however, that a person or group shall not be deemed the beneficial owner of (a) any securities tendered pursuant to a tender or exchange offer made by or on behalf of such person or group until such tendered securities are accepted for purchase or exchange thereunder or (b) any securities the beneficial ownership of which (i) arises solely as a result of a revocable proxy delivered in response to a proxy or consent solicitation and (ii) is not then reportable on Schedule 13D (or any successor schedule) under the Exchange Act, if applicable; or
(2): during any period of two consecutive years, individuals who at the beginning of such period constituted the Company's Board of Directors (together with any new directors whose election or appointment by such Board or whose nomination for election by the shareholders of the Company was approved by a vote of a majority of the directors then still in office who were either directors at the beginning of such period or whose election or nomination for election was previously so approved) cease for any reason to constitute a majority of the Company's Board of Directors then in office; or
(3): the sale, lease, transfer, conveyance or other disposition (other than by way of merger or consolidation), in one or a series of related transactions, of all or substantially all of the assets of the Company and its Restricted Subsidiaries taken as a whole to any "person" (as such term is used in Sections 13(d) and 14(d) of the Exchange Act); or
(4): the adoption by the stockholders of the Company of a plan or proposal for the liquidation or dissolution of the Company.

"Code" means the Internal Revenue Code of 1986, as amended.

"Commodity Agreement" means any commodity futures contract, commodity swap, commodity option, commodity forward sale or other similar agreement or arrangement entered into by the Company or any Restricted Subsidiary in respect of Hydrocarbons or other commodities used, produced, processed or sold by such Person that are customary in the Oil and Gas Business designed to protect the Company or any of its Restricted Subsidiaries against fluctuations in the price of Hydrocarbons or other commodities.

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"Common Stock" means with respect to any Person, any and all shares, interests or other participations in, and other equivalents (however designated and whether voting or nonvoting) of such Person's common stock whether or not outstanding on the Issue Date, and includes, without limitation, all series and classes of such common stock.

"Consolidated Coverage Ratio" means as of any date of determination, with respect to any Person, the ratio of (x) the aggregate amount of Consolidated EBITDA of such Person for the period of the most recent four consecutive fiscal quarters ending prior to the date of such determination for which financial statements are in existence to (y) Consolidated Interest Expense for such four fiscal quarters, provided, however, that:

(1)

if the Company or any Restricted Subsidiary:

(a): has Incurred any Indebtedness since the beginning of such period that remains outstanding on such date of determination or if the transaction giving rise to the need to calculate the Consolidated Coverage Ratio is an Incurrence of Indebtedness, Consolidated EBITDA and Consolidated Interest Expense for such period will be calculated after giving effect on a pro forma basis to such Indebtedness as if such Indebtedness had been Incurred on the first day of such period (except that in making such computation, the amount of Indebtedness under any revolving credit facility outstanding on the date of such calculation will be deemed to be (i) the average daily balance of such Indebtedness during such four fiscal quarters or such shorter period for which such facility was outstanding or (ii) if such facility was created after the end of such four fiscal quarters, the average daily balance of such Indebtedness during the period from the date of creation of such facility to the date of such calculation) and the discharge of any other Indebtedness repaid, repurchased, defeased or otherwise discharged with the proceeds of such new Indebtedness as if such discharge had occurred on the first day of such period; or
(b): has repaid, repurchased, defeased or otherwise discharged any Indebtedness since the beginning of the period that is no longer outstanding on such date of determination or if the transaction giving rise to the need to calculate the Consolidated Coverage Ratio involves a discharge of Indebtedness (in each case, other than Indebtedness Incurred under any revolving credit facility unless such Indebtedness has been (or will be with the proceeds of such transaction) permanently repaid and the related commitment terminated), Consolidated EBITDA and Consolidated Interest Expense for such period will be calculated after giving effect on a pro forma basis to such discharge of such Indebtedness, including with the proceeds of such new Indebtedness, as if such discharge had occurred on the first day of such period;

(2)

if since the beginning of such period the Company or any Restricted Subsidiary will have made any Asset Disposition or disposed of any company, division, operating unit, segment, business, group of related assets or line of business or if the transaction giving rise to the need to calculate the Consolidated Coverage Ratio is such an Asset Disposition:

(a): the Consolidated EBITDA for such period will be reduced by an amount equal to the Consolidated EBITDA (if positive) directly attributable to the assets which are the subject of such disposition for such period or increased by an amount equal to the Consolidated EBITDA (if negative) directly attributable thereto for such period; and

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(b): Consolidated Interest Expense for such period will be reduced by an amount equal to the Consolidated Interest Expense directly attributable to any Indebtedness of the Company or any Restricted Subsidiary repaid, repurchased, defeased or otherwise discharged with respect to the Company and its continuing Restricted Subsidiaries in connection with such disposition for such period (or, if the Capital Stock of any Restricted Subsidiary is sold, the Consolidated Interest Expense for such period directly attributable to the Indebtedness of such Restricted Subsidiary to the extent the Company and its continuing Restricted Subsidiaries are no longer liable for such Indebtedness after such sale);

(3): if since the beginning of such period the Company or any Restricted Subsidiary (by merger or otherwise) will have made an Investment in any Restricted Subsidiary (or any Person which becomes a Restricted Subsidiary or is merged with or into the Company) or an acquisition of assets, including, without limitation, any acquisition of assets occurring in connection with a transaction giving rise to the need to calculate the Consolidated Coverage Ratio, which constitutes all or substantially all of a company, division, operating unit, segment, business, group of related assets or line of business, Consolidated EBITDA and Consolidated Interest Expense for such period will be calculated after giving pro forma effect thereto (including, without limitation, the Incurrence of any Indebtedness) as if such Investment or acquisition occurred on the first day of such period; and
(4): if since the beginning of such period any Person (that subsequently became a Restricted Subsidiary or was merged with or into the Company or any Restricted Subsidiary since the beginning of such period) will have Incurred any Indebtedness or discharged any Indebtedness, made any disposition or any Investment or acquisition of assets that would have required an adjustment pursuant to clause (1), (2) or (3) above if made by the Company or a Restricted Subsidiary during such period, Consolidated EBITDA and Consolidated Interest Expense for such period will be calculated after giving pro forma effect thereto as if such transaction occurred on the first day of such period.

For purposes of this definition, whenever pro forma effect is to be given to any calculation under this definition, the pro forma calculations will be determined in good faith by a responsible financial or accounting officer of the Company (including, without limitation, pro forma expense and cost reductions calculated on a basis consistent with Regulation S-X under the Securities Act). If any Indebtedness bears a floating rate of interest and is being given pro forma effect, the interest expense on such Indebtedness will be calculated as if the rate in effect on the date of determination had been the applicable rate for the entire period (taking into account any Interest Rate Agreement applicable to such Indebtedness if such Interest Rate Agreement has a remaining term in excess of 12 months). If any Indebtedness that is being given pro forma effect bears an interest rate at the option of the Company, the interest rate shall be calculated by applying such optional rate chosen by the Company.

"Consolidated EBITDA" for any period means, without duplication, the Consolidated Net Income for such period, plus the following to the extent deducted in calculating such Consolidated Net Income or, in the case of clause (7), added in calculating such Consolidated Net Income:

(1): Consolidated Interest Expense; plus
(2): Consolidated Income Taxes; plus

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(3): consolidated depletion and depreciation expense; plus
(4): consolidated amortization expense or impairment charges recorded in connection with the application of Financial Accounting Standard No. 142, Goodwill and Other Intangibles, and Financial Accounting Standard No. 144, Accounting for the Impairment or Disposal of Long Lived Assets; plus
(5): other non-cash charges reducing Consolidated Net Income (excluding any such non-cash charge to the extent it represents an accrual of or reserve for cash charges in any future period or amortization of a prepaid cash expense that was paid in a prior period not included in the calculation); plus
(6): consolidated exploration expense; less
(7): non-cash items increasing Consolidated Net Income of such Person for such period (excluding any items which represent the reversal of any accrual of, or reserve for, anticipated cash charges made in any prior period).

Notwithstanding the preceding sentence, clauses (2) through (7) relating to amounts of a Restricted Subsidiary of a Person will be added to or deducted from, as the case may be, Consolidated Net Income to compute Consolidated EBITDA of such Person only to the extent (and in the same proportion) that the net income (loss) of such Restricted Subsidiary was included in calculating the Consolidated Net Income of such Person and, to the extent the amounts set forth in clauses (2) through (7) relating to any Non-Guarantor Restricted Subsidiary are in excess of those necessary to offset a net loss of such Non-Guarantor Restricted Subsidiary or if such Non-Guarantor Restricted Subsidiary has net income for such period included in Consolidated Net Income, only if a corresponding amount would be permitted at the date of determination to be dividended to the Company by such Non-Guarantor Restricted Subsidiary without prior approval (that has not been obtained), pursuant to the terms of its charter and all agreements, instruments, judgments, decrees, orders, statutes, rules and governmental regulations applicable to that Non-Guarantor Restricted Subsidiary or its stockholders.

"Consolidated Income Taxes" means, with respect to any Person for any period, taxes imposed upon such Person or other payments required by any governmental authority to be made by such Person which taxes or other payments are calculated by reference to the income or profits of such Person or such Person and its Restricted Subsidiaries (to the extent such income or profits were included in computing Consolidated Net Income for such period), regardless of whether such taxes or payments are required to be remitted to any governmental authority.

"Consolidated Interest Expense" means, for any period, the total interest expense of the Company and its consolidated Restricted Subsidiaries, whether paid or accrued, plus, to the extent not included in such interest expense and without duplication:

(1): interest expense attributable to Capitalized Lease Obligations and the interest portion of rent expense associated with Attributable Indebtedness in respect of a Sale/Leaseback Transaction in respect of the relevant lease giving rise thereto, determined as if such lease were a capitalized lease in accordance with GAAP and the interest component of any deferred payment obligations;
(2): amortization of debt discount and debt issuance cost; provided, however, that any amortization of bond premium will be credited to reduce Consolidated Interest Expense unless,

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pursuant to GAAP, such amortization of bond premium has otherwise reduced Consolidated Interest Expense;

(3): non-cash interest expense;
(4): commissions, discounts and other fees and charges owed with respect to letters of credit and bankers' acceptance financing;
(5): the interest expense on Indebtedness of another Person that is Guaranteed by the Company or one of its Restricted Subsidiaries or secured by a Lien on assets of the Company or one of its Restricted Subsidiaries;
(6): net costs pursuant to Hedging Obligations (including amortization of fees) provided, however, that if Hedging Obligations result in net benefits rather than net costs, such benefits shall be credited to reduce Consolidated Interest Expense unless, pursuant to GAAP, such net benefits are otherwise reflected in Consolidated Net Income;
(7): the consolidated interest expense of such Person and its Restricted Subsidiaries that was capitalized during such period;
(8): the product of (a) all dividends paid or payable, in cash, Cash Equivalents or Indebtedness or accrued during such period on any series of Disqualified Stock of such Person or on Preferred Stock of its Restricted Subsidiaries that are not Subsidiary Guarantors payable to a party other than the Company or a Wholly Owned Subsidiary, times (b) a fraction, the numerator of which is one and the denominator of which is one minus the then current combined federal, state, provincial and local statutory tax rate of such Person, expressed as a decimal, in each case, on a consolidated basis and in accordance with GAAP;
(9): Receivables Fees; and
(10): the cash contributions to any employee stock ownership plan or similar trust to the extent such contributions are used by such plan or trust to pay interest or fees to any Person (other than the Company and its Restricted Subsidiaries) in connection with Indebtedness Incurred by such plan or trust.

For purposes of the foregoing, total interest expense will be determined (i) after giving effect to any net payments made or received by the Company and its Subsidiaries with respect to Interest Rate Agreements and (ii) exclusive of amounts classified as other comprehensive income in the balance sheet of the Company. Notwithstanding anything to the contrary contained herein, commissions, discounts, yield and other fees and charges Incurred in connection with any securitization transaction, factoring agreement or similar transaction pursuant to which the Company or its Restricted Subsidiaries may sell, convey or otherwise transfer any accounts receivable or related assets or interests therein shall be included in Consolidated Interest Expense.

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"Consolidated Net Income" means, for any period, the net income (loss) of the Company and its consolidated Restricted Subsidiaries determined in accordance with GAAP; provided, however, that there will not be included in such Consolidated Net Income:

(1)

any net income (loss) of any Person if such Person is not the Company or a Restricted Subsidiary, except that:

(a): subject to the limitations contained in clauses (3), (4) and (5) below, the Company's equity in the net income of any such Person for such period will be included in such Consolidated Net Income up to the aggregate amount of cash actually distributed by such Person during such period to the Company or a Restricted Subsidiary as a dividend or other distribution (subject, in the case of a dividend or other distribution to a Non-Guarantor Restricted Subsidiary, to the limitations contained in clause (2) below); and
(b): the Company's equity in a net loss of any such Person (other than an Unrestricted Subsidiary) for such period will be included in determining such Consolidated Net Income to the extent such loss has been funded with cash from the Company or a Restricted Subsidiary;

(2)

any net income (but not loss) of any Non-Guarantor Restricted Subsidiary if such Non-Guarantor Restricted Subsidiary is subject to restrictions, directly or indirectly, on the payment of dividends or the making of distributions by such Non-Guarantor Restricted Subsidiary, directly or indirectly, to the Company, except that:

(a): subject to the limitations contained in clauses (3), (4) and (5) below, the Company's equity in the net income of any such Non-Guarantor Restricted Subsidiary for such period will be included in such Consolidated Net Income up to the aggregate amount of cash that could have been distributed by such Non-Guarantor Restricted Subsidiary during such period to the Company or another Restricted Subsidiary as a dividend or other distribution (subject, in the case of a dividend or other distribution to another Non-Guarantor Restricted Subsidiary, to the limitation contained in this clause); and
(b): the Company's equity in a net loss of any such Non-Guarantor Restricted Subsidiary for such period will be included in determining such Consolidated Net Income;

(3)

any gain (loss) realized upon the sale or other disposition of any property, plant or equipment of the Company or its consolidated Restricted Subsidiaries (including, without limitation, pursuant to any Sale/Leaseback Transaction) which is not sold or otherwise disposed of in the ordinary course of business and any gain (loss) realized upon the sale or other disposition of any Capital Stock of any Person;

(4)

any extraordinary gain or loss;

(5)

any unrealized non-cash gains or losses on charges in respect of Hedging Obligations (including those resulting from the application of SFAS 133);

(6)

the cumulative effect of a change in accounting principles; and

(7)

any asset (including goodwill) impairment or writedown on or related to Oil and Gas Properties under applicable GAAP or SEC guidelines.

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"Credit Facility" means, with respect to the Company or any Restricted Subsidiary, one or more credit facilities (including, without limitation, the Senior Secured Credit Agreement) or commercial paper facilities providing for revolving credit loans, term loans, receivables financing (including, without limitation, through the sale of receivables to such lenders or to special purpose entities formed to borrow from such lenders against such receivables), letters of credit or other debt obligations, in each case, as amended, restated, modified, renewed, restructured, supplemented, extended, substituted, refunded, replaced or refinanced in whole or in part from time to time (and whether or not with the original administrative agent and lenders or another administrative agent or agents or other lenders and whether provided under the original Senior Secured Credit Agreement or any other credit or other agreement or indenture). For the avoidance of doubt, the term "Credit Facility" does not include the Company's floating rate convertible senior notes due 2023.

"Currency Agreement" means in respect of a Person any foreign exchange contract, currency swap agreement, currency futures contract, currency option contract or other similar agreement as to which such Person is a party or a beneficiary.

"Default" means any event which is, or after notice or passage of time or both would be, an Event of Default.

"Designated Officer" means, with respect to any Person, the Chief Executive Officer, President or Chief Financial Officer of such Person.

"Disqualified Stock" means, with respect to any Person, any Capital Stock of such Person which by its terms (or by the terms of any security into which it is convertible or for which it is exchangeable, in each case, at the option of the holder thereof) or upon the happening of any event:

(1): matures or is mandatorily redeemable pursuant to a sinking fund obligation or otherwise;
(2): is convertible or exchangeable for Indebtedness or Disqualified Stock (excluding Capital Stock which is convertible or exchangeable solely at the option of the Company or a Restricted Subsidiary); or
(3): is redeemable at the option of the holder of the Capital Stock in whole or in part,

in each case on or prior to the date that is 91 days after the earlier of (a) the date of the Stated Maturity of the Notes or (b) the first date after the Issue Date on which there are no Notes outstanding, provided that only the portion of Capital Stock which so matures or is mandatorily redeemable, is so convertible or exchangeable or is so redeemable at the option of the holder thereof prior to such date will be deemed to be Disqualified Stock; provided, further that any Capital Stock that would constitute Disqualified Stock solely because the holders thereof have the right to require the Company to repurchase such Capital Stock upon the occurrence of a change of control or asset disposition (each defined substantially consistent with the corresponding definitions in the Indenture) shall not constitute Disqualified Stock if the terms of such Capital Stock (and all such securities into which it is convertible or for which it is ratable or exchangeable) provide that the Company may not repurchase or redeem any such Capital Stock (and all such securities into which it is convertible or for which it is ratable or exchangeable) pursuant to such provision prior to compliance by the Company with the provisions of the Indenture described under the captions "—Change of control" and "—Certain

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covenants—Limitation on sales of assets and subsidiary stock" and such repurchase or redemption complies with "—Certain covenants—Limitation on restricted payments."

"Dollar-Denominated Production Payments" means production payment obligations recorded as liabilities in accordance with GAAP, together with all undertakings and obligations in connection therewith.

"Equity Offering" means a public offering for cash by the Company of its Common Stock, or options, warrants or rights with respect to its Common Stock, other than (x) public offerings with respect to the Company's Common Stock, or options, warrants or rights, registered on Form S-4 or S-8, (y) an issuance to any Subsidiary or (z) any offering of Common Stock issued in connection with a transaction that constitutes a Change of Control.

"Exchange Act" means the Securities Exchange Act of 1934, as amended, and the rules and regulations of the SEC promulgated thereunder.

"Fair Market Value" means the value that would be paid by a willing buyer to an unaffiliated willing seller in a transaction not involving distress or necessity of either party, determined in good faith by the Board of Directors or management of the Company (unless otherwise provided in the indenture) as of the date of contractually agreeing to any transaction that triggers the requirement to determine the Fair Market Value, which determination will be conclusive for all purposes under the indenture.

"Foreign Subsidiary" means any Restricted Subsidiary of the Company that (a) is not organized under the laws of the United States of America or any state thereof or the District of Columbia, or (b) was organized under the laws of the United States of America or any state thereof or the District of Columbia that has no material assets other than Capital Stock of or other interests in one or more foreign entities of the type described in clause (a) above and is not a guarantor of Indebtedness under the Senior Secured Credit Agreement.

"GAAP" means generally accepted accounting principles in the United States of America as in effect as of the Issue Date, including those set forth in the opinions and pronouncements of the Accounting Principles Board of the American Institute of Certified Public Accountants and statements and pronouncements of the Financial Accounting Standards Board or in such other statements by such other entity as approved by a significant segment of the accounting profession. All ratios and computations based on GAAP contained in the Indenture will be computed in conformity with GAAP, except that in the event the Company is acquired in a transaction that is accounted for using purchase accounting, the effects of the application of purchase accounting shall be disregarded in the calculation of such ratios and other computations contained in the Indenture.

"Guarantee" means any obligation, contingent or otherwise, of any Person directly or indirectly guaranteeing any Indebtedness of any other Person of the type described in clauses (1) through (7), (9) and (10) of the definition of "Indebtedness" and any obligation, direct or indirect, contingent or otherwise, of such Person:

(1): to purchase or pay (or advance or supply funds for the purchase or payment of) such Indebtedness of such other Person (whether arising by virtue of partnership arrangements, or by agreement to keep-well, to purchase assets, goods, securities or services, to take-or-pay, or to maintain financial statement conditions or otherwise); or

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(2): entered into for purposes of assuring in any other manner the obligee of such Indebtedness of the payment thereof or to protect such obligee against loss in respect thereof (in whole or in part); provided, however, that the term "Guarantee" will not include endorsements for collection or deposit in the ordinary course of business. The term "Guarantee" used as a verb has a corresponding meaning.

"Guarantor Pari Passu Indebtedness" means Indebtedness of a Subsidiary Guarantor that ranks equally in right of payment to such Subsidiary Guarantor's Subsidiary Guarantee, except as a result of any collateral arrangements in connection with such Indebtedness.

"Guarantor Subordinated Obligation" means, with respect to a Subsidiary Guarantor, any Indebtedness of such Subsidiary Guarantor (whether outstanding on the Issue Date or thereafter Incurred) which is expressly subordinated in right of payment to the obligations of such Subsidiary Guarantor under its Subsidiary Guarantee pursuant to a written agreement.

"Hedging Obligations" of any Person means the obligations of such Person pursuant to any Interest Rate Agreement, Currency Agreement or Commodity Agreement.

"holder" means a Person in whose name a Note is registered on the Registrar's books.

"Hydrocarbons" means oil, gas, casinghead gas, drip gasoline, natural gasoline, condensate, distillate, liquid hydrocarbons, gaseous hydrocarbons and all constituents, elements or compounds thereof and all products, by-products, and all other substances (whether or not hydrocarbon in nature) produced in connection therewith or refined, separated, settled or derived therefrom or the processing thereof.

"Incur" means issue, create, assume, Guarantee, incur or otherwise become liable for; provided, however, that any Indebtedness or Capital Stock of a Person existing at the time such person becomes a Restricted Subsidiary (whether by merger, consolidation, acquisition or otherwise) will be deemed to be Incurred by such Restricted Subsidiary at the time it becomes a Restricted Subsidiary; and the terms "Incurred" and "Incurrence" have meanings correlative to the foregoing.

"Indebtedness" means, with respect to any Person on any date of determination (without duplication):

(1): the principal of and premium (if any) in respect of indebtedness of such Person for borrowed money;
(2): the principal of and premium (if any) in respect of obligations of such Person evidenced by bonds, debentures, notes or other similar instruments;
(3): the principal component of all obligations of such Person in respect of letters of credit, bankers' acceptances or other similar instruments (including reimbursement obligations with respect thereto except to the extent such reimbursement obligation relates to a trade payable and such obligation is satisfied within 30 days of Incurrence and excluding obligations in respect of letters of credit securing obligations (other than the Indebtedness described in clauses (1), (2), (4), (5), (7), (8) or (9) of this definition) entered into in the ordinary course of business to the extent such letters of credit are not drawn upon or, if and to the extent drawn upon, to the extent such drawing is reimbursed within 10 days following payment on the letter of credit);

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(4): the principal component of all obligations of such Person to pay the deferred and unpaid purchase price of property (except trade payables), which purchase price is due more than six months after the date of placing such property in service or taking delivery and title thereto;
(5): Capitalized Lease Obligations and all Attributable Indebtedness of such Person;
(6): the principal component or liquidation preference of all obligations of such Person with respect to the redemption, repayment or other repurchase of any Disqualified Stock or, with respect to any Subsidiary that is not a Subsidiary Guarantor, any Preferred Stock (but excluding, in each case, any accrued dividends);
(7): the principal component of all Indebtedness of other Persons secured by a Lien on any asset of such Person, whether or not such Indebtedness is assumed by such Person; provided, however, that the amount of such Indebtedness will be the lesser of (a) the fair market value of such asset at such date of determination and (b) the amount of such Indebtedness of such other Persons;
(8): the principal component of Indebtedness of other Persons to the extent Guaranteed by such Person;
(9): to the extent not otherwise included in this definition, net obligations of such Person under Hedging Obligations (the amount of any such obligations to be equal at any time to the termination value of such agreement or arrangement giving rise to such obligation that would be payable by such Person at such time); and
(10): to the extent not otherwise included in this definition, the amount of obligations outstanding under the legal documents entered into as part of a securitization transaction or series of transactions that would be characterized as principal if such transaction were structured as a secured lending transaction rather than as a purchase outstanding relating to a securitization transaction or series of transactions.

The amount of Indebtedness of any Person at any date will be the outstanding balance at such date of all unconditional obligations as described above and the maximum liability, upon the occurrence of the contingency giving rise to the obligation, of any contingent obligations at such date. Notwithstanding the foregoing, money borrowed and set aside at the time of the Incurrence of any Indebtedness in order to pre-fund the payment of interest on such Indebtedness shall not be deemed to be "Indebtedness", provided that such money is held to secure the payment of such interest.

In addition, "Indebtedness" of any Person shall include Indebtedness described in the preceding paragraph that would not appear as a liability on the balance sheet of such Person if:

(1): such Indebtedness is the obligation of a partnership or joint venture that is not a Restricted Subsidiary (a "Joint Venture");
(2): such Person or a Restricted Subsidiary of such Person is a general partner of the Joint Venture (a "General Partner"); and

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(3)

there is recourse, by contract or operation of law, with respect to the payment of such Indebtedness to property or assets of such Person or a Restricted Subsidiary of such Person; and then such Indebtedness shall be included in an amount not to exceed:

(a): the lesser of (i) the net assets of the General Partner and (ii) the amount of such obligations to the extent that there is recourse, by contract or operation of law, to the property or assets of such Person or a Restricted Subsidiary of such Person; or
(b): if less than the amount determined pursuant to clause (a) immediately above, the actual amount of such Indebtedness that is recourse to such Person or a Restricted Subsidiary of such Person, if the Indebtedness is evidenced by a writing and is for a determinable amount.

"Interest Rate Agreement" means, with respect to any Person any interest rate protection agreement, interest rate future agreement, interest rate option agreement, interest rate swap agreement, interest rate cap agreement, interest rate collar agreement, interest rate hedge agreement or other similar agreement or arrangement as to which such Person is party or a beneficiary.

"Investment" means, with respect to any Person, all investments by such Person in other Persons (including Affiliates) in the form of any direct or indirect advance, loan (other than advances or extensions of credit to customers in the ordinary course of business) or other extensions of credit (including by way of Guarantee or similar arrangement, but excluding any debt or extension of credit represented by a bank deposit other than a time deposit) or capital contribution to (by means of any transfer of cash or other property (valued at the fair market value thereof as of the date of transfer) to others or any payment for property or services for the account or use of others), or any purchase or acquisition of Capital Stock, Indebtedness or other similar instruments issued by, such other Person and all other items that are or would be classified as investments on a balance sheet prepared in accordance with GAAP; provided that none of the following will be deemed to be an Investment:

(1): Hedging Obligations entered into in the ordinary course of business and in compliance with the Indenture;
(2): endorsements of negotiable instruments and documents in the ordinary course of business; and
(3): an acquisition of assets, Capital Stock or other securities by the Company or a Subsidiary for consideration to the extent such consideration consists of Capital Stock of the Company (other than Disqualified Stock).

For purposes of "—Certain covenants—Limitation on restricted payments,"

(1): "Investment" will include the portion (proportionate to the Company's equity interest in a Restricted Subsidiary to be designated as an Unrestricted Subsidiary) of the fair market value of the net assets of such Restricted Subsidiary at the time that such Restricted Subsidiary is designated an Unrestricted Subsidiary, unless such Restricted Subsidiary, at the time of such designation, has total assets of $1,000 or less, in which case no Investment shall be deemed to occur as a result of such designation; provided, however, that upon a redesignation of such Subsidiary as a Restricted Subsidiary, the Company will be deemed to continue to have a permanent "Investment" in an Unrestricted Subsidiary in an amount (if positive) equal to

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(a) the Company's "Investment" in such Subsidiary at the time of such redesignation less (b) the portion (proportionate to the Company's equity interest in such Subsidiary) of the fair market value of the net assets (as conclusively determined by the Board of Directors of the Company in good faith) of such Subsidiary at the time that such Subsidiary is so re-designated a Restricted Subsidiary;

(2): any property transferred to or from an Unrestricted Subsidiary will be valued at its fair market value at the time of such transfer, in each case as determined in good faith by the Board of Directors of the Company; and
(3): the amount of any Investment shall not be adjusted for increases or decreases in value, or write-ups, write-downs or write-offs with respect to such Investment.

"Investment Grade Rating" means a rating equal to or higher than (1) Baa3 (or the equivalent) with a stable or better outlook by Moody's Investors Service, Inc. and (2) BBB- (or the equivalent) with a stable or better outlook by Standard & Poor's; or if either such entity ceases to rate Notes for reasons outside of the Company's control, the equivalent investment grade rating from another nationally recognized statistical rating agency or agencies, as the case may be, selected by the Company.

"Issue Date" means May 1, 2007.

"Lien" means any mortgage, pledge, security interest, encumbrance, lien or charge of any kind (including, without limitation, any conditional sale or other title retention agreement or lease in the nature thereof).

"Minority Interest" means the percentage interest represented by any shares of stock of any class of Capital Stock of a Restricted Subsidiary that are not owned by the Company or a Restricted Subsidiary.

"Net Available Cash" from an Asset Disposition means cash payments received by the Company or any Restricted Subsidiary of the Company (including, without limitation, any cash payments received by way of deferred payment of principal pursuant to a note or installment receivable or otherwise and net proceeds from the sale or other disposition of any securities received as consideration, but only as and when received, but excluding any other consideration received in the form of assumption by the acquiring Person of Indebtedness or other obligations relating to the properties or assets that are the subject of such Asset Disposition or received in any other non-cash form) therefrom, in each case net of:

(1): all legal, accounting, investment banking, title and recording tax expenses, commissions and other fees and expenses Incurred, and all Federal, state, provincial, foreign and local taxes required to be paid or accrued as a liability under GAAP (after taking into account any available tax credits or deductions and any tax sharing agreements), as a consequence of such Asset Disposition;
(2): all payments made on any Indebtedness which is secured by any assets subject to such Asset Disposition, in accordance with the terms of any Lien upon such assets, or which must by its terms, or in order to obtain a necessary consent to such Asset Disposition, or by applicable law be repaid out of the proceeds from such Asset Disposition;

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(3): all distributions and other payments required to be made to minority interest holders in Subsidiaries or joint ventures or to holders of royalty or similar interests as a result of such Asset Disposition;
(4): the deduction of appropriate amounts to be provided by the seller as a reserve, in accordance with GAAP, against any liabilities associated with the assets disposed of in such Asset Disposition and retained by the Company or any Restricted Subsidiary after such Asset Disposition; and
(5): any portion of the purchase price from an Asset Disposition placed in escrow, whether as a reserve for adjustment of the purchase price, for satisfaction of indemnities in respect of such Asset Disposition or otherwise in connection with that Asset Disposition; provided, however, that upon the termination of that escrow, Net Available Cash will be increased by any portion of funds in the escrow that are released to the Company or any Restricted Subsidiary.

"Net Cash Proceeds," with respect to any issuance or sale of Capital Stock, means the cash proceeds of such issuance or sale net of attorneys' fees, accountants' fees, underwriters' or placement agents' fees, listing fees, discounts or commissions and brokerage, consultant and other fees and charges actually Incurred in connection with such issuance or sale and net of taxes paid or payable as a result of such issuance or sale (after taking into account any available tax credit or deductions and any tax sharing arrangements).

"Net Working Capital" means (a) all current assets of the Company and its Restricted Subsidiaries except current assets from Commodity Agreements, less (b) all current liabilities of the Company and its Restricted Subsidiaries, except current liabilities included in Indebtedness and any current liabilities from Commodity Agreements, in each case as set forth in the consolidated financial statements of the Company prepared in accordance with GAAP.

"Non-Guarantor Restricted Subsidiary" means any Restricted Subsidiary that is not a Subsidiary Guarantor.

"Non-Recourse Debt" means Indebtedness of a Person:

(1): as to which neither the Company nor any Restricted Subsidiary (a) provides any Guarantee or credit support of any kind (including any undertaking, guarantee, indemnity, agreement or instrument that would constitute Indebtedness) or (b) is directly or indirectly liable (as a guarantor or otherwise);
(2): no default with respect to which (including any rights that the holders thereof may have to take enforcement action against an Unrestricted Subsidiary) would permit (upon notice, lapse of time or both) any holder of any other Indebtedness of the Company or any Restricted Subsidiary to declare a default under such other Indebtedness or cause the payment thereof to be accelerated or payable prior to its Stated Maturity; and
(3): the explicit terms of which provide there is no recourse against any of the assets of the Company or its Restricted Subsidiaries.

"Officer" means the Chairman of the Board, the Chief Executive Officer, the President, the Chief Financial Officer, any Vice President, the Treasurer or the Secretary of the Company. Officer of any Subsidiary Guarantor has a correlative meaning.

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"Officers' Certificate" means a certificate signed by two Officers or by an Officer and either an Assistant Treasurer or an Assistant Secretary of the Company.

"Oil and Gas Business" means (a) the business of acquiring, exploring, exploiting, developing, producing, operating, hedging, swapping and disposing of interests in oil, gas, liquid natural gas and other Hydrocarbon properties and assets, (b) the business of gathering, marketing, treating, processing, storage, refining, selling, hedging, swapping and transporting of any production from such interests, properties or assets (or interests, properties or assets of others) and products produced in association therewith, (c) any business or activity relating to, arising from, or necessary, appropriate, incidental, ancillary or complementary to the activities described in the foregoing clauses (a) and (b) of this definition.

"Oil and Gas Properties" means all properties, including equity or other ownership interests therein, owned by such Person which contain "proved oil and gas reserves" as defined in Rule 4-10 of Regulation S-X of the Securities Act.

"Opinion of Counsel" means a written opinion from legal counsel who is acceptable to the Trustee. The counsel may be an employee of or counsel to the Company or the Trustee.

"Pari Passu Indebtedness" means Indebtedness that ranks equally in right of payment to the Notes without regard to any collateral arrangements in connection with such Indebtedness.

"Permitted Business Investment" means any Investment made in the ordinary course of the business of the Company or any Restricted Subsidiary or that is of a nature that is or shall have become customary in, the Oil and Gas Business including, without limitation, investments or expenditures for exploiting, exploring for, acquiring, developing, producing, processing, refining, gathering, marketing or transporting Hydrocarbons through agreements, transactions, interests or arrangements which permit one to share or transfer risks or costs, comply with regulatory requirements regarding local ownership or satisfy other objectives customarily achieved through the conduct of the Oil and Gas Business jointly with third parties, including, without limitation:

(1): ownership interests in oil, gas or other Hydrocarbon or mineral properties and interests therein, liquid natural gas facilities, drilling operations, processing facilities, refineries, gathering systems, pipelines, storage facilities, related systems or facilities, ancillary real property interests, and interests therein;
(2): Investments in the form of or pursuant to oil and/or gas leases, mineral leases, overriding royalty agreements, net profits agreements, production payment agreements, royalty trust agreements, incentive compensation programs on terms that are reasonably customary in the Oil and Gas Business for geologists, geophysicists and other providers of technical services to the Company or any Restricted Subsidiary, operating agreements, farm-in agreements, farm-out agreements, division orders, participation agreements, master limited partnership agreements, limited liability company agreements, contracts for the sale, purchase, exchange, transportation, gathering, processing, marketing or storage of Hydrocarbons, communitizations, declarations, orders and agreements, production sales contracts, gas balancing or deferred production agreements, injection, repressuring and recycling agreements, salt water or other disposal agreements, seismic or geophysical permits or agreements, development agreements, area of mutual interest agreements, unitization agreements, pooling agreements, joint bidding agreements, service contracts, joint venture agreements, partnership agreements (whether

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general or limited), subscription agreements, stock purchase agreements and other similar agreements (including for limited liability companies) with third parties, working interest, royalty interests and mineral leases, and other agreements which are customary in the Oil and Gas Business;

(3): Investments of operating funds on behalf of co-owners of properties pursuant to operating agreements; and
(4): direct or indirect ownership interests in drilling rigs and related equipment, including, without limitation, transportation equipment.

"Permitted Investment" means an Investment by the Company or any Restricted Subsidiary in or pursuant to:

(1): the Company, a Restricted Subsidiary or a Person which will, upon the making of such Investment, become a Restricted Subsidiary; provided, however, that the primary business of such Restricted Subsidiary is the Oil and Gas Business;
(2): another Person if as a result of such Investment such other Person is merged or consolidated with or into, or transfers or conveys all or substantially all its assets to, the Company or a Restricted Subsidiary; provided, however, that such Person's primary business is the Oil and Gas Business;
(3): cash and Cash Equivalents;
(4): receivables owing to the Company or any Restricted Subsidiary created or acquired in the ordinary course of business and payable or dischargeable in accordance with customary trade terms; provided, however, that such trade terms may include such concessionary trade terms as the Company or any such Restricted Subsidiary deems reasonable under the circumstances;
(5): payroll, travel and similar advances to cover matters that are expected at the time of such advances ultimately to be treated as expenses for accounting purposes and that are made in the ordinary course of business;
(6): relocation allowances for, and loans or advances to, employees, officers or directors of the Company or any Restricted Subsidiary in the ordinary course of business consistent with past practices in an aggregate amount not in excess of $2.0 million with respect to all loans or advances made since the Issue Date (without giving effect to the forgiveness of any such loan);
(7): Capital Stock, obligations or securities received in settlement or compromise of debts created in the ordinary course of business and owing to the Company or any Restricted Subsidiary, in settlement or compromise of litigation, arbitration or other disputes with Persons that are not Affiliates of the Company or any Restricted Subsidiary, in satisfaction of judgments or arbitration awards, or pursuant to any plan of reorganization or similar arrangement upon the bankruptcy or insolvency of a debtor;
(8): Investments made as a result of the receipt of non-cash consideration from an Asset Disposition that was made pursuant to and in compliance with "—Certain covenants—Limitation on sales of assets and subsidiary stock" or from a disposition of assets permitted under the Indenture and not constituting an Asset Disposition;

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(9): any Person to the extent such Investments consist of prepaid expenses, negotiable instruments held for collection on behalf of the Company or any Restricted Subsidiary and lease, utility and workers' compensation, performance and other similar deposits made in the ordinary course of business by the Company or any Restricted Subsidiary;
(10): Investments in existence on the Issue Date or made pursuant to agreements or commitments in effect on the Issue Date, and any amendment, modification, restatement, supplement, extension, renewal, refunding, replacement or refinancing, in whole or in part thereof;
(11): Currency Agreements, Interest Rate Agreements, Commodity Agreements and related Hedging Obligations, which transactions or obligations are Incurred in compliance with "—Certain covenants—Limitation on indebtedness;"
(12): Investments by the Company or any of its Restricted Subsidiaries, together with all other Investments pursuant to this clause (12) outstanding on the date such Investment is made, in an aggregate amount at the time of such Investment not to exceed the greater of (i) $10.0 million, and (ii) 0.5% of Adjusted Consolidated Net Tangible Assets (determined as of the date of the making of any such Investment), outstanding at any one time (with the fair market value of such Investment being measured at the time made and without giving effect to subsequent changes in value);
(13): Guarantees issued in accordance with "—Certain covenants—Limitations on indebtedness;"
(14): any Asset Swap; and
(15): Investments in property, plant and equipment used in the ordinary course of business of the Company or any Restricted Subsidiary and Permitted Business Investments.

In order to be a Permitted Investment, an Investment need not be permitted solely by one subsection of this definition but may be permitted in part by one such subsection and in part by one or more other subsections of this definition.

"Permitted Liens" means, with respect to any Person:

(1): Liens securing Indebtedness and other obligations under, and related Hedging Obligations and Liens on property and assets of Restricted Subsidiaries securing Guarantees of Indebtedness and other obligations of the Company under, any Credit Facility permitted to be Incurred under the Indenture under the provisions described in clause (1) of the second paragraph under "Certain covenants—Limitation on Indebtedness";
(2): pledges or deposits or other security made or provided by such Person under workers' compensation laws, unemployment insurance laws or similar legislation, or good faith deposits in connection with bids, tenders, contracts (other than for the payment of Indebtedness) or leases to which such Person is a party, or deposits to secure public, regulatory or statutory obligations of such Person or deposits of cash or Cash Equivalents to secure performance, surety, appeal or similar bonds to which such Person is a party, or deposits as security for contested taxes or import or customs duties or for the payment of rent, or any Lien securing letters of credit, bankers' acceptances or completion guarantees described in clause (8) of the second paragraph under "Certain covenants—Limitation on Indebtedness", in each case Incurred in the ordinary course of business;

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(3)

Liens imposed by law, including, without limitation, carriers', warehousemen's, suppliers', mechanics', materialmen's, repairmen's and similar Liens arising in the ordinary course of business;

(4)

Liens for taxes, assessments or other governmental charges not yet subject to penalties for non-payment or which are being contested in good faith by appropriate negotiations or proceedings provided appropriate reserves required pursuant to GAAP have been made in respect thereof;

(5)

Liens in favor of issuers of surety or performance bonds or letters of credit or bankers' acceptances issued pursuant to the request of and for the account of such Person in the ordinary course of its business; provided, however, that such letters of credit do not constitute Indebtedness;

(6)

survey exceptions, encumbrances, ground leases, easements or reservations of, or rights of others for, licenses, rights of way, sewers, electric lines, telegraph and telephone lines, gathering systems, pipelines and other similar purposes, or zoning, building codes, surface leases or surface access agreements and other similar rights in respect of surface operations, or other restrictions (including, without limitation, minor defects or irregularities in title and similar encumbrances) as to the use of real properties or liens incidental to the conduct of the business of such Person or to the ownership of its properties which do not in the aggregate materially impair the use of such properties in the operation of the business of such Person or the value of such property for the purpose of such business;

(7)

Liens securing Hedging Obligations so long as the related Indebtedness is, and is permitted under the Indenture to be, secured by a Lien;

(8)

leases, licenses, subleases and sublicenses of property and assets (including, without limitation, real property, personal property and intellectual property rights) which do not materially interfere with the ordinary conduct of the business of the Company or any of its Restricted Subsidiaries;

(9)

judgment Liens; provided that any such judgment Lien (i) has not and does not, together with other judgment Liens, give rise to an Event of Default and (ii) is adequately bonded (or any reserve or other appropriate provision as is required in conformity with GAAP has been made therefor) and any appropriate legal proceedings which may have been duly initiated for the review of such judgment have not been finally terminated or the period within which such proceedings may be initiated has not expired;

(10)

Liens for the purpose of securing Indebtedness represented by Capitalized Lease Obligations, mortgage financings, purchase money obligations or other payments Incurred to finance all or any part of the purchase price or cost of construction or improvement of assets or property (other than Capital Stock or other Investments) acquired, constructed or improved in the ordinary course of business; provided that:

(a): the aggregate principal amount of Indebtedness secured by such Liens is otherwise permitted to be Incurred under the Indenture and does not exceed the cost of the assets or property so acquired, constructed or improved; and
(b): such Liens are created within 180 days of construction, acquisition or improvement of such assets or property and do not encumber any other assets or property of the Company

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or any Restricted Subsidiary other than such assets or property and assets affixed or appurtenant thereto;

(11)

Liens arising solely by virtue of any statutory or common law provisions relating to banker's Liens, rights of set-off or similar rights and remedies as to deposit accounts or other funds maintained with a depositary institution; provided that:

(a): such deposit account is not a dedicated cash collateral account and is not subject to restrictions against access by the Company in excess of those set forth by regulations promulgated by the Federal Reserve Board; and
(b): such deposit account is not intended by the Company or any Restricted Subsidiary to provide collateral to the depository institution;

(12)

Liens arising from Uniform Commercial Code financing statement filings regarding operating leases entered into by the Company and its Restricted Subsidiaries in the ordinary course of business;

(13)

Liens existing on the Issue Date (other than Liens permitted under clause (1));

(14)

Liens on property, assets or Capital Stock of a Person at the time such Person becomes a Restricted Subsidiary; provided, however, that such Liens are not created, Incurred or assumed in connection with, or in contemplation of, such other Person becoming a Restricted Subsidiary; provided further, however, that any such Lien may not extend to any other property or assets owned by the Company or any Restricted Subsidiary;

(15)

Liens on property, assets or Capital Stock of a Person at the time the Company or a Restricted Subsidiary acquired the property, asset or Capital Stock, including any acquisition by means of a merger or consolidation with or into the Company or any Restricted Subsidiary; provided, however, that such Liens are not created, Incurred or assumed in connection with, or in contemplation of, such acquisition; provided further, however, that such Liens may not extend to any other property or asset owned by the Company or any Restricted Subsidiary;

(16)

Liens securing Indebtedness or other obligations of a Restricted Subsidiary owing to the Company or a Wholly Owned Subsidiary;

(17)

Liens securing the Notes and Subsidiary Guarantees;

(18)

Liens securing Refinancing Indebtedness Incurred to refinance, refund, replace, amend, extend or modify, as a whole or in part, Indebtedness that was previously so secured pursuant to clauses (10), (13), (14), (15), (17) and (18) of this definition, provided that any such Lien is limited to all or part of the same property or assets (plus improvements, accessions, proceeds or dividends or distributions in respect thereof) that secured (or, under the written arrangements under which the original Lien arose, could secure) the Indebtedness being refinanced, refunded, replaced, amended, extended or modified or is in respect of any Capital Stock, property or asset that is the security for a Permitted Lien hereunder;

(19)

any interest or title of a lessor under any Capitalized Lease Obligation or operating lease;

(20)

Liens under industrial revenue, municipal or similar bonds;

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(21): Liens in respect of Production Payments and Reserve Sales, which Liens shall be limited to the property or interest that is the subject of such Production Payments and Reserve Sales;
(22): Liens arising under or in connection with oil and/or gas leases, mineral leases, overriding royalty agreements, net profits agreements, production payment agreements, royalty trust agreements, incentive compensation programs on terms that are reasonably customary in the Oil and Gas Business for geologists, geophysicists and other providers of technical services to the Company or any Restricted Subsidiary, farm-out agreements, farm-in agreements, division orders, participation agreements, partnership agreements (general and limited), master limited partnership agreements, limited liability company agreements, joint venture agreements, contracts for the sale, purchase, exchange, transportation, gathering, processing, marketing or storage of Hydrocarbons, unitizations, communitizations, and pooling designations, declarations, orders and agreements, development agreements, operating agreements, production sales contracts, area of mutual interest agreements, gas balancing or deferred production agreements, injection, repressuring and recycling agreements, salt water or other disposal agreements, seismic or geophysical permits or agreements, and other agreements which are customary in the Oil and Gas Business; provided, however, in all instances that such Liens are limited to the property or assets that are the subject of the relevant agreement, program, designation, declaration, order or contract;
(23): Liens on pipelines or pipeline facilities that arise by operation of law;
(24): Liens on funds held in trust for or on behalf of third parties;
(25): Liens in respect of rights of netting, offset and setoff Incurred in the ordinary course of business;
(26): deposits, escrows or pledges to secure obligations under purchase and sale agreements and Liens arising under contracts for the sale, purchase or exchange of any Capital Stock, property or asset pending the closing of such transaction;
(27): Liens in respect of the financing of insurance premiums and deposits as security for the payment of insurance-related obligations (including, without limitation, in respect of deductibles, self-insured retention amounts and premiums and adjustments thereto);
(28): conditional sale, title retention, consignment or similar arrangements for the sale of goods or services entered into in the ordinary course of business;
(29): Liens on property of an Unrestricted Subsidiary at the time that it is designated as a Restricted Subsidiary pursuant to the definition of "Unrestricted Subsidiary;" provided that such Liens were not incurred in connection with, or contemplation of, such designation;
(30): encumbrances and restrictions permitted to exist under "Certain Covenants—Limitation on restrictions on distributions from restricted subsidiaries;" and
(31): Liens securing Indebtedness (other than Subordinated Obligations and Guarantor Subordinated Obligations) in an aggregate principal amount at any time outstanding not to exceed $15.0 million.

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"Person" means any individual, corporation, partnership, joint venture, association, joint-stock company, trust, unincorporated organization, limited liability company, government or any agency or political subdivision thereof or any other entity.

"Preferred Stock," as applied to the Capital Stock of any Person, means Capital Stock of any class or classes (however designated) which is preferred as to the payment of dividends, or as to the distribution of assets upon any voluntary or involuntary liquidation or dissolution of such Person, over shares of Capital Stock of any other class of such Person.

"Production Payments and Reserve Sales" means the grant or transfer by the Company or a Restricted Subsidiary to any Person of a royalty, overriding royalty, revenue interest, net revenue interest, net profits interest, reversionary interest, production payment (including, without limitation, Volumetric Production Payments and Dollar-Denominated Production Payments), partnership or other interest in oil and gas properties or the right to receive all or a portion of the production or the proceeds from the sale of production attributable to such properties where the holder of such interest has recourse solely to such production or proceeds of production, subject to the obligation of the grantor or transferor to operate and maintain, or cause the subject interests to be operated and maintained in a reasonably prudent manner or other customary standard or subject to the obligation of the grantor or transferor to indemnify for environmental, title or other matters customary in the Oil and Gas Business, including, without limitation, any such grants or transfers pursuant to incentive compensation programs on terms that are reasonably customary in the Oil and Gas Business for geologists, geophysicists or other providers of technical services to the Company or a Restricted Subsidiary.

"Rating Agencies" means Standard & Poor's and Moody's Investors Service, Inc. or if Standard & Poor's or Moody's Investors Service, Inc. or both shall not make a rating on the Notes publicly available, a nationally recognized statistical rating agency or agencies, as the case may be, selected by the Company (as evidenced by a resolution of the Board of Directors) which shall be substituted for Standard & Poor's or Moody's Investors Service, Inc. or both, as the case may be.

"Receivable" means a right to receive payment arising from a sale or lease of goods or the performance of services by a Person pursuant to an arrangement with another Person pursuant to which such other Person is obligated to pay for goods or services under terms that permit the purchase of such goods and services on credit and shall include, in any event, any items of property that would be classified as an "account," "chattel paper," "payment intangible" or "instrument" under the Uniform Commercial Code as in effect in the State of New York and any "supporting obligations" as so defined.

"Receivables Fees" means any fees or interest paid to purchasers or lenders providing the financing in connection with a securitization transaction, factoring agreement or other similar agreement, including, without limitation, any such amounts paid by discounting the face amount of Receivables or participations therein transferred in connection with a securitization transaction, factoring agreement or other similar arrangement, regardless of whether any such transaction is structured as on-balance sheet or off-balance sheet or through a Restricted Subsidiary or an Unrestricted Subsidiary.

"Refinancing Indebtedness" means Indebtedness that is Incurred to refund, refinance, replace, exchange, renew, prepay, purchase, redeem, retire, repay or extend (including, without

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limitation, pursuant to any defeasance or discharge mechanism) (collectively, "refinance," "refinances" and "refinanced" shall each have a correlative meaning) any Indebtedness existing on the Issue Date or Incurred in compliance with the Indenture (including, without limitation, Indebtedness of the Company that refinances Indebtedness of any Restricted Subsidiary and Indebtedness of any Restricted Subsidiary that refinances Indebtedness of another Restricted Subsidiary) including, without limitation, Indebtedness that refinances Refinancing Indebtedness, provided, however, that:

(1): (a) if the Stated Maturity of the Indebtedness being refinanced is earlier than the Stated Maturity of the Notes, the Refinancing Indebtedness has a Stated Maturity no earlier than the Stated Maturity of the Indebtedness being refinanced or (b) if the Stated Maturity of the Indebtedness being refinanced is later than the Stated Maturity of the Notes, the Refinancing Indebtedness has a Stated Maturity at least 91 days later than the Stated Maturity of the Notes;
(2): the Refinancing Indebtedness has an Average Life at the time such Refinancing Indebtedness is Incurred that is equal to or greater than the Average Life of the Indebtedness being refinanced;
(3): such Refinancing Indebtedness is Incurred in an aggregate principal amount (or if issued with original issue discount, an aggregate issue price) that is equal to or less than the sum of the aggregate principal amount (or if issued with original issue discount, the aggregate accreted value) then outstanding or committed of the Indebtedness being refinanced (plus, without duplication, any additional Indebtedness Incurred to pay accrued interest and fees and expenses Incurred in connection therewith, including, without limitation, any premium and defeasance costs); and
(4): if the Indebtedness being refinanced is subordinated in right of payment to the Notes or the Subsidiary Guarantee, such Refinancing Indebtedness is subordinated in right of payment to the Notes or the Subsidiary Guarantee on terms that, in the good faith reasonable determination of the Company or the applicable Restricted Subsidiary, are at least as favorable to the holders as those contained in the documentation governing the Indebtedness being refinanced.

"Responsible Officer" shall mean, when used with respect to the Trustee, any officer within the corporate trust department of the Trustee, including any vice president, assistant vice president, assistant secretary, assistant treasurer, trust officer or any other officer of the Trustee who customarily performs functions similar to those performed by the persons who at the time shall be such officers, respectively, or to whom any corporate trust matter is referred because of such person's knowledge of and familiarity with the particular subject and who shall have direct responsibility for the administration of the Indenture.

"Restricted Investment" means any Investment other than a Permitted Investment.

"Restricted Subsidiary" means any Subsidiary of the Company other than an Unrestricted Subsidiary.

"Sale/Leaseback Transaction" means an arrangement relating to property now owned or hereafter acquired whereby the Company or a Restricted Subsidiary transfers such property to

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a Person and the Company or a Restricted Subsidiary leases it from such Person within 90 days after the date of the transfer to such Person.

"SEC" means the United States Securities and Exchange Commission.

"Securities Act" means the Securities Act of 1933, as amended, and the rules and regulations of the SEC promulgated thereunder.

"Senior Secured Credit Agreement" means the Amended and Restated Credit Agreement dated as of June 13, 2005 among the Company, the lenders from time to time party thereto, JPMorgan Chase Bank, N.A., as an LC Issuer and as Administrative Agent, U.S. Bank National Association and Bank of America, N.A., as Co-Syndication Agents, and Wells Fargo Bank, N.A., as Documentation Agent, including, without limitation, any related notes, guarantees, collateral documents, instruments and agreements entered into in connection therewith, in each case, as the same may be amended, restated, modified, renewed, restructured, supplemented, extended, substituted, refunded, replaced or refinanced in whole or in part from time to time (including, without limitation, increasing the amount loaned thereunder, provided that such additional Indebtedness is Incurred in accordance with the covenant described under "—Certain covenants—Limitation on indebtedness", extending the maturity of any Indebtedness Incurred thereunder or contemplated thereby or deleting, adding or substituting one or more parties thereto (whether or not such added or substituted parties are banks or other institutional lenders)); provided that a Senior Secured Credit Agreement shall not (1) include Indebtedness issued, created or Incurred pursuant to a registered offering of securities under the Securities Act or a private placement of securities (including under Rule 144A or Regulation S) pursuant to an exemption from the registration requirements of the Securities Act or (2) relate to Indebtedness that does not consist exclusively of Pari Passu Indebtedness or Guarantor Pari Passu Indebtedness.

"Significant Subsidiary" means any Restricted Subsidiary that would be a "Significant Subsidiary" of the Company within the meaning of Rule 1-02 under Regulation S-X promulgated by the SEC.

"Standard & Poor's" means Standard & Poor's, a division of the McGraw-Hill Companies, Inc.

"Stated Maturity" means, with respect to any security or Indebtedness, the date specified in such security or Indebtedness as the fixed date on which the payment of principal of such security or Indebtedness is due and payable, including, without limitation, pursuant to any mandatory redemption provision, but shall not include any contingent obligations to repay, redeem or repurchase any such principal prior to the date originally scheduled for the payment thereof.

"Subordinated Obligation" means any Indebtedness of the Company (whether outstanding on the Issue Date or thereafter Incurred) which is subordinated or junior in right of payment to the Notes pursuant to a written agreement.

"Subsidiary" of any Person means (a) any corporation, association or other business entity (other than a partnership, joint venture, limited liability company or similar entity) of which more than 50% of the total ordinary voting power of shares of Capital Stock entitled (without regard to the occurrence of any contingency) to vote in the election of directors, managers or trustees thereof (or persons performing similar functions) or (b) any partnership, joint venture,

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limited liability company or similar entity of which more than 50% of the capital accounts, distribution rights, total equity and voting interests or general partnership interests of a general partnership or general and limited partnership interests, taken together, of a limited partnership, as applicable, is, in the case of clauses (a) and (b), at the time owned or controlled, directly or indirectly, by (1) such Person, (2) such Person and one or more Subsidiaries of such Person or (3) one or more Subsidiaries of such Person. Unless otherwise specified herein, each reference to a Subsidiary will refer to a Subsidiary of the Company.

"Subsidiary Guarantee" means, individually, any Guarantee of payment of the Notes by a Subsidiary Guarantor pursuant to the terms of the Indenture and any supplemental indenture thereto, and, collectively, all such Guarantees. Each such Subsidiary Guarantee will be in the form prescribed by the Indenture.

"Subsidiary Guarantor" means each Restricted Subsidiary (other than a Foreign Subsidiary) in existence on the Issue Date that provides a Subsidiary Guarantee on the Issue Date and any other Restricted Subsidiary (other than a Foreign Subsidiary) that provides a Subsidiary Guarantee in accordance with the Indenture; provided that upon release or discharge of any such Restricted Subsidiary from its Subsidiary Guarantee in accordance with the Indenture, such Restricted Subsidiary shall cease to be a Subsidiary Guarantor.

"Unrestricted Subsidiary" means:

(1): any Subsidiary of the Company that at the time of determination shall be designated an Unrestricted Subsidiary by the Board of Directors of the Company in the manner provided below; and
(2): any Subsidiary of an Unrestricted Subsidiary.

The Board of Directors of the Company may designate any Subsidiary of the Company (including, without limitation, any newly acquired or newly formed Subsidiary or a Person becoming a Subsidiary through merger or consolidation or Investment therein) to be an Unrestricted Subsidiary only if on the date such Subsidiary is designated an Unrestricted Subsidiary:

(1): such Subsidiary or any of its Subsidiaries does not own any Capital Stock or Indebtedness of or have any Investment in, or own or hold any Lien on any property of, any other Subsidiary of the Company which is not a Subsidiary of the Subsidiary to be so designated or otherwise an Unrestricted Subsidiary or simultaneously being designated an Unrestricted Subsidiary;
(2): all the Indebtedness of such Subsidiary and its Subsidiaries shall, at the date of designation, and will at all times thereafter, consist of Non-Recourse Debt;
(3): such designation and the Investment of the Company in such Subsidiary complies with "—Certain covenants—Limitation on restricted payments;"
(4): such Subsidiary, either alone or in the aggregate with all other Unrestricted Subsidiaries, does not operate, directly or indirectly, all or substantially all of the business of the Company and its Subsidiaries;

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(5)

such Subsidiary is a Person with respect to which neither the Company nor any of its Restricted Subsidiaries has any direct or indirect obligation:

(a): to subscribe for additional Capital Stock of such Person; or
(b): to maintain or preserve such Person's financial condition or to cause such Person to achieve any specified levels of operating results; and

(6)

such Subsidiary is not a party to any agreement, contract, arrangement or understanding with the Company or any Restricted Subsidiary with terms materially less favorable to the Company or such Restricted Subsidiary, as the case may be, than those that could be obtained in a comparable transaction at the time of such transaction in arm's-length dealings with a Person who is not an Affiliate of the Company.

Any such designation by the Board of Directors of the Company shall be evidenced to the Trustee by filing with the Trustee a resolution of the Board of Directors of the Company giving effect to such designation and an Officers' Certificate certifying that such designation complies with the foregoing conditions. If, at any time, any Unrestricted Subsidiary would fail to meet the foregoing requirements as an Unrestricted Subsidiary, it shall thereafter cease to be an Unrestricted Subsidiary for purposes of the Indenture and any Indebtedness of such Subsidiary shall be deemed to be Incurred as of such date.

The Board of Directors of the Company may designate any Unrestricted Subsidiary to be a Restricted Subsidiary; provided that immediately after giving effect to such designation, no Default or Event of Default shall have occurred and be continuing or would occur as a consequence thereof and the Company could Incur at least $1.00 of additional Indebtedness pursuant to the first paragraph of the "—Certain covenants—Limitation on indebtedness" covenant on a pro forma basis taking into account such designation.

"U.S. Government Obligations" means securities that are (a) direct obligations of the United States of America for the timely payment of which its full faith and credit is pledged or (b) obligations of a Person controlled or supervised by and acting as an agency or instrumentality of the United States of America the timely payment of which is unconditionally guaranteed as a full faith and credit obligation of the United States of America, which, in either case, are not callable or redeemable at the option of the issuer thereof, and shall also include a depositary receipt issued by a bank (as defined in Section 3(a)(2) of the Securities Act), as custodian with respect to any such U.S. Government Obligations or a specific payment of principal of or interest on any such U.S. Government Obligations held by such custodian for the account of the holder of such depositary receipt; provided that (except as required by law) such custodian is not authorized to make any deduction from the amount payable to the holder of such depositary receipt from any amount received by the custodian in respect of the U.S. Government Obligations or the specific payment of principal of or interest on the U.S. Government Obligations evidenced by such depositary receipt.

"Volumetric Production Payments" means production payment obligations recorded as deferred revenue in accordance with GAAP, together with all undertakings and obligations in connection therewith.

"Voting Stock" of a Person means all classes of Capital Stock of such Person then outstanding and normally entitled to vote in the election of directors, managers or trustees, as applicable.

"Wholly Owned Subsidiary" means a Restricted Subsidiary, all of the Capital Stock of which (other than directors' qualifying shares) is owned by the Company or one or more other Wholly Owned Subsidiaries.

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United States federal income and estate tax considerations

The following general discussion summarizes material U.S. federal income and, for certain non-U.S. persons, estate tax aspects of the purchase, ownership and disposition of the notes. This discussion is a summary for general information only and does not consider all aspects of U.S. federal income and, as applicable, estate taxes that may be relevant to the purchase, ownership and disposition of the notes. This discussion also does not address the U.S. federal income or estate tax consequences of ownership of notes not held as capital assets within the meaning of Section 1221 of the Internal Revenue Code of 1986, as amended, which we refer to as the Code, or the U.S. federal income or estate tax consequences to investors subject to special treatment under the U.S. federal income or estate tax laws, such as:

•: dealers in securities or foreign currency;
•: tax-exempt entities, including retirement plans and pension funds;
•: banks;
•: thrifts;
•: regulated investment companies;
•: real estate investment trusts;
•: traders in securities that have elected the mark-to-market method of accounting for their securities;
•: controlled foreign corporations;
•: passive foreign investment companies;
•: insurance companies;
•: persons that hold the notes as part of a "straddle," a "hedge" or a "conversion transaction";
•: U.S. holders liable for alternative minimum tax;
•: expatriates;
•: persons that have a "functional currency" other than the U.S. dollar; and
•: pass-through entities (e.g., partnerships) or investors who hold the notes through pass-through entities.

In addition, this discussion is limited to the U.S. federal income tax aspects (and, as applicable, estate tax consequences) to initial holders that purchase the notes for cash, at their original issue price, pursuant to the offering. It does not describe any tax consequences arising out of the tax laws of any state, local or foreign jurisdiction, and does not address alternative minimum tax consequences.

If a partnership, including any entity that is treated as a partnership for U.S. federal income tax purposes, is a beneficial owner of the notes, the treatment of a partner in the partnership will generally depend on the status of the partner and the activities of the partnership. If you are a

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partner in a partnership that is considering purchasing the notes, you should consult with your tax advisor.

This discussion is based upon the Code, regulations of the Treasury Department, rulings and pronouncements of the Internal Revenue Service, which we refer to as the IRS, and judicial decisions, each as now in effect, and all of which are subject to change (possibly on a retroactive basis). We have not and will not seek any rulings from the IRS regarding the matters discussed below. There can be no assurance that the IRS will not take positions concerning the tax consequences of the purchase, ownership or disposition of the notes which are different from those discussed below.

If you are considering buying notes, we urge you to consult your tax advisor about the particular federal, state, local and foreign tax consequences of the purchase, ownership and disposition of the notes, and the application of the U.S. federal income and estate tax laws to your particular situation.

U.S. holders

This section summarizes the material U.S. federal income tax aspects of the purchase, ownership and disposition of the notes by "U.S. holders." A "U.S. holder" is a beneficial owner of notes that, for U.S. federal income tax purposes, is:

•: an individual citizen or resident of the United States;
•: a corporation or other entity taxable as a corporation created or organized under the laws of the United States, any of its states or the District of Columbia;
•: an estate if its income is subject to U.S. federal income taxation regardless of its sources; or
•: a trust if a U.S. court is able to exercise primary supervision over administration of the trust and one or more U.S. persons have authority to control all substantial decisions of the trust, or if the trust existed on August 20, 1996 and has validly elected to continue to be treated as a domestic trust under applicable Treasury regulations.

Taxation of interest

Subject to the rules concerning original issue discount, payments of interest on the notes are generally taxable to you as ordinary income:

•: when the interest accrues, if you use the accrual method of accounting for U.S. federal income tax purposes; or
•: when you receive the payments, if you use the cash method of accounting for U.S. federal income tax purposes.

In general, if the terms of a debt instrument entitle a holder to receive payments other than fixed periodic interest, and the sum of such payments exceeds the issue price of the instrument, the excess is treated under the Code as "original issue discount." The holder may be required to recognize any original issue discount on a constant yield basis as additional interest over the term of the instrument, without regard to when the payments are received, to the extent the

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original issue discount is not de minimis. We expect that the notes will not be issued with more than a de minimis amount of original issue discount.

Sale or other disposition of notes

You generally must recognize taxable gain or loss on the sale, exchange, redemption, retirement or other taxable disposition of a note. The amount of your gain or loss equals the difference between the amount of cash proceeds and the fair market value of any property you receive for the note (to the extent such amount does not represent accrued but unpaid interest, which will be treated as interest income), minus your adjusted tax basis in the note. Your initial tax basis in a note generally is the price you paid for the note. Any such gain or loss on a taxable disposition of a note as described above will generally constitute capital gain or loss and will be long-term capital gain or loss if you hold such note for more than one year. The maximum tax rate on long-term capital gains to non-corporate U.S. Holders is generally 15% (for taxable years through December 31, 2010, and 20% thereafter). The deductibility of capital losses is subject to limitations.

Non-U.S. holders

This section summarizes the material U.S. federal income and estate tax aspects of the purchase, ownership and disposition of the notes by non-U.S. holders. A non-U.S. holder is a beneficial owner of notes that is for U.S. federal income tax purposes an individual, corporation, estate or trust and is not a U.S. holder.

Income or withholding tax on payments on the notes

Subject to the discussion of backup withholding below, payments of interest on a note to any non-U.S. holder will generally not be subject to U.S. federal income or withholding tax, provided that:

•

the holder is not:

•: an actual or constructive owner of 10% or more of the total voting power of all our voting stock;
•: a controlled foreign corporation related (directly or indirectly) to us through stock ownership; or
•: a bank which receives the interest in connection with an extension of credit made pursuant to a loan agreement entered into in the ordinary course of business;

•

such interest payments are not effectively connected with the conduct by the non-U.S. holder of a trade or business within the United States; and

•

we or our paying agent receives:

•: from the non-U.S. holder, a properly completed Form W-8BEN (or substitute Form W-8BEN or the appropriate successor form) under penalties of perjury, which provides the non-U.S. holder's name and address, certifies that the non-U.S. holder of the note is a non-U.S. holder; or

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•: from a security clearing organization, bank or other financial institution that holds the notes in the ordinary course of its trade or business (a "financial institution") on behalf of the non-U.S. holder, certification under penalties of perjury that such a Form W-8BEN (or substitute Form W-8BEN or the appropriate successor form) has been received by it, or by another such financial institution, from the non-U.S. holder, and a copy of the Form W-8BEN (or substitute Form W-8BEN or the appropriate successor form) is furnished to the payor.

Special rules may apply to holders who hold notes through "qualified intermediaries" within the meaning of U.S. federal income tax laws.

If interest on a note is effectively connected with the conduct by a non-U.S. holder of a trade or business in the United States (and, if required by an applicable tax treaty, is treated as attributable to a permanent establishment or a fixed base in the United States) then such interest generally will be subject to U.S. federal income tax on a net basis at the rates applicable to U.S. persons generally (and, if realized by corporate holders, may also be subject to a branch profits tax at a 30% rate or such lower rate as may be available pursuant to an applicable income tax treaty). If interest is subject to U.S. federal income tax on a net basis in accordance with the rules described in the preceding sentence, payments of such interest will not be subject to U.S. withholding tax so long as the holder provides us or the paying agent with a properly completed Form W-8ECI.

A non-U.S. holder that does not qualify for exemption from withholding under the preceding paragraphs generally will be subject to withholding of U.S. federal income tax at the rate of 30% on payments of interest on the notes, unless the holder provides us or the paying agent with a properly completed Form W-8BEN (or other applicable form) claiming an exemption from or reduction in withholding under the benefit of an applicable income tax treaty.

Non-U.S. holders should consult their tax advisors about any applicable income tax treaties, which may provide for an exemption from or a lower rate of withholding tax, exemption from or reduction of branch profits tax, or other rules different from those described above.

Sale or other disposition of notes

Subject to the discussion of backup withholding below, any gain realized by a non-U.S. holder on the sale, exchange, redemption, retirement or other disposition of a note generally will not be subject to U.S. federal income tax, unless:

•: such gain is effectively connected with the non-U.S. holder's conduct of a trade or business in the United States (and, if required by an applicable tax treaty, is treated as attributable to a permanent establishment or a fixed base in the United States); or
•: the non-U.S. holder is an individual who is present in the United States for 183 days or more in the taxable year of the disposition and certain other conditions are satisfied.

If the first bullet point applies, the non-U.S holder generally will be subject to U.S. federal income tax with respect to such gain in the same manner as U.S. holders, as described above, unless an applicable income tax treaty provides otherwise. In addition, if such non-U.S holder is a corporation, such non-U.S. holder may also be subject to the branch profits tax described above. If the second bullet point applies, the non-U.S holder generally will be subject to U.S. federal income tax at a rate of 30% (or at a reduced rate under an applicable income tax

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treaty) on the amount by which capital gains from U.S. sources (including gains from the sale, exchange, redemption, retirement or other disposition of the notes) exceed capital losses allocable to U.S. sources.

U.S. federal estate tax

A note held or treated as held by an individual who is a non-U.S. holder at the time of his or her death will not be subject to U.S. federal estate tax provided that (1) the individual does not actually or constructively own 10% or more of the total voting power of all our voting stock and (2) interest on the note, if received by the non-U.S. holder at death, would not have been effectively connected with the conduct by such non-U.S. holder of a trade or business within the United States.

Information reporting and backup withholding

Payments of principal and interest made by us on, or the proceeds of the sale or other disposition of, the notes may be subject to information reporting. In addition, if you are a U.S. holder, such payments generally will be subject to U.S. federal backup withholding tax unless you supply a taxpayer identification number, certified under penalties of perjury, as well as certain other information or otherwise establish an exemption from backup withholding. If you are a non-U.S. holder, you may be required to comply with certification procedures to establish that you are not a U.S. person in order to avoid backup withholding tax with respect to our payments on, or the proceeds from the disposition of, notes. The backup withholding tax rate is currently 28%. Any amounts withheld under the backup withholding rules may be allowable as a refund or a credit against the holder's U.S. federal income tax liability, provided required information is furnished to the IRS.

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Underwriting

Subject to the terms and conditions in the underwriting agreement between us and the underwriters, we have agreed to sell to each underwriter, and each underwriter has severally agreed to purchase from us, the principal amount of notes that appears opposite its name in the table below:

Underwriter	Principal amount


J.P. Morgan Securities Inc.	$	183,750,000
Lehman Brothers Inc.		87,500,000
Deutsche Bank Securities Inc.		21,000,000
Merrill Lynch, Pierce, Fenner & Smith Incorporated		21,000,000
Calyon Securities (USA) Inc.		12,250,000
Raymond James & Associates, Inc.		12,250,000
UBS Securities LLC		12,250,000

Total	$	350,000,000

The underwriters have agreed to purchase all of the notes if any of them are purchased.

The underwriters initially propose to offer the notes to the public at the public offering price that appears on the cover page of this prospectus. The underwriters may offer the notes to selected dealers at the public offering price minus a concession of up to 0.375% of the principal amount. In addition, the underwriters may allow, and those selected dealers may reallow, a concession of up to 0.25% of the principal amount to certain other dealers. After the initial offering, the underwriters may change the public offering price and any other selling terms. The underwriters may offer and sell notes through certain of their affiliates.

In the underwriting agreement, we have agreed that:

•: We will not offer or sell any of our debt securities (other than the notes) for a period of 90 days after the date of this prospectus without the prior consent of J.P. Morgan Securities Inc.
•: We will indemnify the underwriters against certain liabilities, including liabilities under the Securities Act of 1933, or contribute to payments that the underwriters may be required to make in respect of those liabilities.

The notes are a new issue of securities with no established trading market. We do not intend to apply for the notes to be listed on any securities exchange or to arrange for the notes to be quoted on any quotation system. The underwriters have advised us that they intend to make a market in the notes. However, they are not obligated to do so and they may discontinue any market making at any time in their sole discretion. Therefore, we cannot assure you that a liquid trading market will develop for the notes, that you will be able to sell your notes at a particular time or that the prices that you receive when you sell will be favorable.

In connection with this offering of the notes, the underwriters may engage in overallotments, stabilizing transactions and short covering transactions in accordance with Regulation M under the Securities Exchange Act of 1934. Overallotment involves sales in excess of the offering size,

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which creates a short position for the underwriters. Stabilizing transactions involve bids to purchase the notes in the open market for the purpose of pegging, fixing or maintaining the price of the notes, as applicable. Short covering transactions involve purchases of the notes in the open market after the distribution has been completed in order to cover short positions. Stabilizing transactions and short covering transactions may cause the price of the notes to be higher than it would otherwise be in the absence of those transactions. If either underwriter engages in stabilizing or short covering transactions, it may discontinue them at any time.

We expect to deliver the notes against payment for the notes on or about the date specified in the penultimate paragraph of the cover page of this prospectus, which will be the tenth business day following the date of the pricing of the notes. Since trades in the secondary market generally settle in three business days, purchasers who wish to trade notes on the date of pricing or the next succeeding business day will be required, by virtue of the fact that the notes initially will settle in T+10, to specify alternative settlement arrangements to prevent a failed settlement.

Certain of the underwriters and their affiliates have in the past and may in the future provide investment banking, commercial banking and financial advisory services to us and our affiliates in the ordinary course of business. In particular, an affiliate of J.P. Morgan Securities Inc. is a lender to us under our senior revolving credit facility. We intend to use a portion of the net proceeds of the offering to repay amounts outstanding under the senior revolving credit facility. See "Use of proceeds." Affiliates of J.P. Morgan Securities Inc., Calyon Securities (USA) Inc. and Deutsche Bank Securities Inc. are agents and lenders under our senior revolving credit facility and will receive customary fees related thereto.

143

Legal matters

The validity of the notes offered hereby will be passed upon for us by Holme Roberts & Owen LLP, Denver, Colorado. Certain legal matters will be passed upon for the underwriters by Simpson Thacher & Bartlett LLP, New York, New York.

Experts

The consolidated financial statements of Cimarex and subsidiaries as of December 31, 2006 and 2005, and for each of the years in the three-year period ended December 31, 2006, and management's assessment of the effectiveness of internal control over financial reporting as of December 31, 2006 have been included and incorporated by reference herein in reliance upon the reports of KPMG LLP, independent registered public accounting firm, incorporated by reference herein, and upon authority of said firm as experts in accounting and auditing. Their reports refer to the adoption of Statement of Financial Accounting Standards No. 123(R), Share Based Payments, as of January 1, 2005.

The financial statements and the related financial statement schedule incorporated in this prospectus by reference from the Magnum Hunter Resources, Inc. Annual Report on Form 10-K for the year ended December 31, 2004 have been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report (which report expresses an unqualified opinion on the financial statements and financial statement schedule and includes an explanatory paragraph referring to changes in methods of accounting for asset retirement obligations and employee stock based compensation in 2003 as required by Statement of Financial Accounting Standards No. 143, "Accounting for Asset Retirement Obligations" and Statement of Financial Accounting Standards No. 148, "Accounting for Stock-Based Compensation-Transition and Disclosure, an Amendment to FASB Statement No. 123," respectively), which is incorporated herein by reference, and has been so incorporated in reliance upon the report of such firm given upon their authority as experts in accounting and auditing.

DeGolyer and MacNaughton, independent petroleum engineers, reviewed the proved reserve estimates associated with at least 80 percent of the discounted future net cash flows before income taxes for the year ended December 31, 2006. Ryder Scott Company, L.P., independent petroleum engineers, and DeGolyer and MacNaughton collectively reviewed the proved reserve estimates associated with at least 80 percent of the discounted future net cash flows before income taxes for the year ended December 31, 2005. Ryder Scott Company, L.P. reviewed the proved reserve estimates associated with at least 80 percent of the discounted future net cash flows before income taxes for the year ended December 31, 2004. Estimated quantities of Cimarex's oil and gas reserves and the net present value of such reserves have been included and incorporated by reference in this prospectus in reliance on the authority of said firms as experts in petroleum engineering.

Where you can find more information

We file annual, quarterly and special reports, proxy statements and other information with the SEC. You may read and copy this information at the SEC's public reference room, which is located at 100 F Street, N.E., Washington, DC 20549. Please call the SEC at 1-800-SEC-0330 for

144

further information on its public reference room. This information is also available on-line through the SEC's Electronic Data Gathering, Analysis, and Retrieval System (EDGAR), located on the SEC's web site (http://www.sec.gov). Our SEC filings are also available through the New York Stock Exchange, on which our common stock is listed, at 20 Broad Street, New York, N.Y. 10005. Our internet address is http://www.cimarex.com. The information on our website is not incorporated into this prospectus.

Incorporation by reference

We have filed a registration statement with the SEC on Form S-3 with respect to this offering. This prospectus is a part of the registration statement. As allowed by SEC rules, this prospectus does not contain all the information you can find in the registration statement or the exhibits to the registration statement. The SEC allows us to "incorporate by reference" other documents filed with the SEC, which means that we can disclose important information to you by referring you to other documents. The information that is incorporated by reference is an important part of this prospectus and information that we file later with the SEC will automatically update and may replace information in this prospectus and information previously filed with the SEC. The documents listed below and any future filings made with the SEC pursuant to Sections 13(a), 13(c), 14 or 15(d) of the Securities Exchange Act of 1934, as amended, are incorporated by reference in this prospectus until the termination of this offering, excluding any information furnished under Item 7.01 or Item 2.02 of any Current Report on Form 8-K.

Filing		Period


Annual Report on Form 10-K		Year ended December 31, 2006
Audited consolidated financial statements of Magnum Hunter as of December 31, 2004 and the related notes and financial statement schedule contained in Magnum Hunter's Annual Report on Form 10-K (file no. 001-12508)		Year ended December 31, 2004
Definitive Proxy Statement on Schedule 14A		Filed March 30, 2007

As you read the above documents, you may find some inconsistencies in information from one document to another. If you find inconsistencies between the documents, or between a document and this prospectus, you should rely on the statements made in the most recent document.

No action is being taken in any jurisdiction outside the United States to permit a public offering of our securities or possession or distribution of this prospectus in any such jurisdiction. Persons who come into possession of this prospectus in jurisdictions outside the United States must inform themselves about and observe any restrictions as to this offering and the distribution of this prospectus applicable in those jurisdictions.

You may request a copy of any document incorporated by reference in this prospectus, at no cost, by writing or calling us at the following address:

Mary Kay Rohrer
Corporate Secretary
Cimarex Energy Co.
1700 Lincoln Street, Suite 1800
Denver, Colorado 80203-4518
tel.: (303) 295-3995

145

Index to financial statements and supplemental schedules


Independent Auditors' Report for the years ended December 31, 2006, 2005 and 2004
Consolidated balance sheets as of December 31, 2006 and 2005
Consolidated statements of operations for the years ended December 31, 2006, 2005 and 2004
Consolidated statements of cash flows for the years ended December 31, 2006, 2005 and 2004
Consolidated statements of stockholders' equity and comprehensive income for the years ended December 31, 2006, 2005 and 2004
Notes to consolidated financial statements

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.

F-1

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 as of December 31, 2006 and 2005, 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, 2006. 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, 2006 and 2005, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2006, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Company's internal control over financial reporting as of December 31, 2006, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of the Sponsoring Organizations of the Treadway Commission, and our report dated February 27, 2007 expressed an unqualified opinion on management's assessment of, and the effective operation of, internal control over financial reporting.

As discussed in Note 4 to the Consolidated Financial Statements, Cimarex Energy Co. adopted Statement of Financial Accounting Standards No. 123(R), Share Based Payment, as of January 1, 2005.

KPMG LLP

Denver, Colorado
February 27, 2007

F-2

Cimarex Energy Co.
Consolidated balance sheets
(in thousands, except share and per share information)

				December 31,

				2006			2005

Assets
Current assets:
	Cash and cash equivalents			$	5,048		$	61,647
	Accounts receivable:
		Trade, net of allowance			62,866			66,723
		Oil and gas sales, net of allowance			189,906			191,748
		Gas gathering, processing, and marketing, net of allowance			8,083			30,471
		Other			45,603			242
	Inventories				39,397			34,784
	Deferred income taxes				1,498			17,959
	Derivative instruments				41,945			—
	Other current assets				22,411			25,454

			Total current assets		416,757			429,028

Oil and gas properties at cost, using the full cost method of accounting:
	Proved properties				4,656,854			3,602,797
	Unproved properties and properties under development, not being amortized				425,173			388,839

					5,082,027			3,991,636
	Less—accumulated depreciation, depletion and amortization				(1,494,317	)		(1,114,677	)

			Net oil and gas properties		3,587,710			2,876,959

Fixed assets, less accumulated depreciation of $33,273 and $17,171					88,924			86,916
Goodwill					691,432			717,391
Derivative instruments					7,051			—
Other assets, net					37,876			70,041

				$	4,829,750		$	4,180,335

Liabilities and Stockholders' Equity
Current liabilities:
	Accounts payable:
		Trade		$	40,735		$	50,529
		Gas gathering, processing, and marketing			15,506			31,418
	Accrued liabilities:
		Exploration and development			94,403			76,725
		Taxes other than income			25,376			15,978
		Other			82,384			86,373
	Derivative instruments				—			41,926
	Revenue payable				96,184			94,469

			Total current liabilities		354,588			397,418
Long-term debt					443,667			352,451
Deferred income taxes					921,665			717,790
Asset retirement obligation					124,821			97,558
Deferred compensation					—			13,881
Other liabilities					8,866			5,784

			Total liabilities		1,853,607			1,584,882

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, 83,962,132 and 83,524,285 shares issued, respectively				840			835
	Treasury stock, at cost, 1,078,822 shares held				(40,628	)		(43,554	)
	Paid-in capital				1,867,448			1,865,597
	Unearned compensation				—			(15,862	)
	Retained earnings				1,117,402			788,356
	Accumulated other comprehensive income				31,081			81

					2,976,143			2,595,453

				$	4,829,750		$	4,180,335

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

F-3

Cimarex Energy Co.
Consolidated statements of operations
(in thousands, except per share data)

		For the years ended December 31,

		2006			2005			2004

Revenues:
	Gas sales	$	810,894		$	807,007		$	366,260
	Oil sales		404,517			265,415			106,129
	Gas gathering and processing		47,879			44,238			101
	Gas marketing, net of related costs of $144,702, $213,749 and $193,041 respectively		3,854			1,962			2,674

			1,267,144			1,118,622			475,164

Costs and expenses:
	Depreciation, depletion and amortization		396,394			258,287			124,251
	Asset retirement obligation accretion		7,018			3,819			1,241
	Production		176,833			104,067			37,476
	Transportation		21,157			15,338			10,003
	Gas gathering and processing		27,410			31,890			284
	Taxes other than income		91,066			73,360			37,761
	General and administrative		42,288			33,497			22,483
	Stock compensation, net		8,243			4,959			1,957
	(Gain) loss on derivative instruments		(22,970	)		67,800			—
	Other operating, net		2,064			15,897			(3,394	)

			749,503			608,914			232,062

	Operating income		517,641			509,708			243,102
Other (income) and expense:
	Interest expense net of capitalized interest of $24,248, $11,686 and $0, respectively		5,692			7,921			1,075
	Amortization of fair value of debt		(3,784	)		(2,132	)		—
	Other, net		(28,591	)		(12,536	)		(4,291	)

Income before income tax expense			544,324			516,455			246,318
Income tax expense			198,605			188,130			92,726

	Net income	$	345,719		$	328,325		$	153,592

Earnings per share:
	Basic	$	4.21		$	5.07		$	3.70

	Diluted	$	4.11		$	4.90		$	3.59

Weighted average shares outstanding:
	Basic		82,066			64,761			41,466

	Diluted		84,090			67,000			42,763

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

F-4

Cimarex Energy Co.
Consolidated statements of cash flows
(in thousands)

					Years ended December 31,

					2006			2005			2004

Cash flows from operating activities:
	Net income				$	345,719		$	328,325		$	153,592
	Adjustments to reconcile net income to net cash provided by operating activities:
		Depreciation, depletion and amortization				396,394			258,287			124,251
		Asset retirement obligation accretion				7,018			3,819			1,241
		Deferred income taxes				220,539			112,890			66,849
		Stock compensation, net				8,243			4,959			1,957
		Derivative instruments				(41,926	)		3,483			—
		Gain on liquidation of equity investees				(19,785	)		—			—
		Other				1,540			12,844			798
		Changes in operating assets and liabilities, net of effects of the acquisition of Magnum Hunter:
			(Increase) in receivables, net			(9,811	)		(45,787	)		(35,696	)
			(Increase) in inventory and other current assets			(11,812	)		(27,293	)		(1,703	)
			Increase (decrease) in accounts payable and accrued liabilities			(18,293	)		52,488			42,918
			Increase in other noncurrent liabilities			593			719			1,646

				Net cash provided by operating activities		878,419			704,734			355,853

Cash flows from investing activities:
	Oil and gas expenditures					(1,030,791	)		(631,549	)		(281,407	)
	Acquisition of oil and gas properties					(23,790	)		(1,973	)		(324	)
	Merger related costs					(439	)		(13,740	)		—
	Cash received in connection with acquisition					—			33,407			—
	Proceeds from sale of assets					10,705			141,842			926
	Distributions received from equity investees					59,823			302			—
	Other expenditures					(25,310	)		(25,742	)		(12,296	)

				Net cash used by investing activities		(1,009,802	)		(497,453	)		(293,101	)

Cash flows from financing activities:
	Borrowing (payments) on long-term debt, net					95,000			(273,501	)		—
	Treasury stock acquired and retired					(11,016	)		—			—
	Dividends paid					(13,358	)		—			—
	Proceeds from issuance of common stock and other					4,158			12,121			12,574

				Net cash provided by (used in) financing activities		74,784			(261,380	)		12,574

				Net change in cash and cash equivalents		(56,599	)		(54,099	)		75,326
Cash and cash equivalents at beginning of period						61,647			115,746			40,420

Cash and cash equivalents at end of period					$	5,048		$	61,647		$	115,746

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

F-5

Cimarex Energy Co.
Consolidated statements of stockholders' equity and comprehensive income
(in thousands)

			Common stock

																Accumulated other comprehensive income						Total stockholders equity
								Paid-in capital			Unearned compensation			Retained earnings					Treasury stock
			Shares		Amount			Paid-in capital			Unearned compensation			Retained earnings					Treasury stock

Balance, December 31, 2003			41,064		$	411		$	237,430		$	(9,540	)	$	306,439	$	—		$	—		$	534,740
	Issuance of restricted stock awards		15			—			400			(400	)		—		—			—			—
	Issuance of restricted stock unit awards		—			—			—			(2,809	)		—		—			—			(2,809	)
	Common stock reacquired and retired		(35	)		—			(1,254	)		—			—		—			—			(1,254	)
	Amortization of unearned compensation		—			—			—			2,677			—		—			—			2,677
	Exercise of stock options, net of tax benefit of $4,805 recorded in paid-in capital		691			6			13,822			—			—		—			—			13,828
	Shares of restricted stock exchanged for restricted stock units		(6	)		—			(150	)		—			—		—			—			(150	)
	Comprehensive income:
		Net income	—			—			—			—			153,592		—			—			153,592
		Unrealized gain on marketable securities of investments, net of tax	—			—			—			—			—		88			—			88

		Total comprehensive income																					153,680

Balance, December 31, 2004			41,729		$	417		$	250,248		$	(10,072	)	$	460,031	$	88		$	—		$	700,712
	Issuance of common stock, net of offering costs		42,185			422			1,587,775			—			—		—			—			1,588,197
	Issuance of restricted stock awards		249			2			9,913			(9,915	)		—		—			—			—
	Issuance of restricted stock unit awards		—			—			—			(2,856	)		—		—			—			(2,856	)
	Treasury Stock		—			—			—			—			—		—			(96,161	)		(96,161	)
	Common stock reacquired and retired		(1,450	)		(14	)		(54,723	)		—			—		—			52,607			(2,130	)
	Restricted stock forfeited and retired		(2	)		—			(80	)		78			—		—			—			(2	)
	Amortization of unearned compensation		—			—			—			4,259			—		—			—			4,259
	Exercise of stock options, net of tax benefit of $6,442 recorded in paid-in capital		659			7			15,761			—			—		—			—			15,768
	Stock Option Compensation Expense		—			—			2,348			—			—		—			—			2,348
	Accelerated vesting of stock options, restricted stock and restricted stock units		154			1			4,713			2,644			—		—			—			7,358
	Equity attributable to Floating rate convertible notes		—			—			49,642			—			—		—			—			49,642
	Comprehensive income:
		Net income	—			—			—			—			328,325		—			—			328,325
		Unrealized loss on marketable securities of investments, net of tax	—			—			—			—			—		(7	)		—			(7	)

Total comprehensive income																							328,318

F-6

Balance, December 31, 2005			83,524		$	835		$	1,865,597		$	(15,862	)	$	788,356		$	81	$	(43,554	)	$	2,595,453
	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	—			—			—			—			345,719			—		—			345,719
		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																					376,719

Balance, December 31, 2006			83,962		$	840		$	1,867,448		$	—		$	1,117,402		$	31,081	$	(40,628	)	$	2,976,143

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

F-7

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

In June 2005, Cimarex acquired Magnum Hunter Resources, Inc. Terms of the merger agreement provided that Magnum Hunter stockholders receive 0.415 shares of Cimarex common stock for each share of Magnum Hunter common stock. As a result of the merger, Cimarex issued 39.7 million common shares to Magnum Hunter's common stockholders. The merger was accounted for as a purchase of Magnum Hunter by Cimarex.

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 4 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 2006 financial statement presentation.

2. Description of business

Cimarex Energy Co. is an independent oil and gas exploration and production company. Our operations are presently focused primarily in Oklahoma, Texas, New Mexico, Kansas, Louisiana, and the Gulf of Mexico.

3. Business combination

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

F-8

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

The purchase price of Magnum Hunter's assets was based on the value of Cimarex common stock issued to the Magnum Hunter stockholders and the fair value of assumed liabilities. The value of the common stock issued is based on the weighted average price of Cimarex's common stock for the period beginning two days before and ending two days after the announcement of the merger, or $37.66 per share. The purchase price also includes merger costs incurred, which include investment banking expenses, legal and accounting fees, printing expenses, and other related costs. Below is the final purchase price allocation:


Purchase Price (in millions):
	Shares of Cimarex common stock issued to Magnum Hunter stockholders		39.7
	Average Cimarex stock price	$	37.66
	Fair value of common stock issued	$	1,495.4
	Plus: Merger costs incurred		7.4
	Cash issued for fractional shares		0.1
	Total purchase price		1,502.9
	Plus: Liabilities assumed by Cimarex:
	Current liabilities		170.5
	Fair value of long-term debt		627.3
	Other non-current liabilities		78.5
	Deferred income taxes		402.1
	Value of common stock associated with convertible debt		49.6

	Total purchase price plus liabilities assumed	$	2,830.9

Allocation of Purchase Price:
	Current assets	$	197.3
	Proved oil and gas properties		1,514.2
	Unproved oil and gas properties		308.0
	Investments		61.2
	Other property and equipment		57.0
	Other non-current assets		46.8
	Goodwill		646.4

		$	2,830.9

Included in current assets on the acquisition date of June 7, 2005 were assets available for sale of approximately $8.5 million acquired in the Magnum Hunter merger. These assets were sold during the third quarter of 2005 for approximately $8.1 million.

The following unaudited pro forma information has been prepared to give effect to the Magnum Hunter acquisition as if it had occurred at the beginning of the periods presented. The unaudited pro forma data is presented for illustrative purposes only, based on estimates and assumptions deemed appropriate by management, including the preliminary purchase allocation and interest on Magnum Hunter debt assumed, and should not be relied upon as an indication of the operating results that Cimarex would have achieved if the transaction had

F-9

occurred on January 1, 2004. The pro forma information also should not be used as an indication of future results or trends.

		Years ended December 31,

(Thousands of dollars, except per share data)		2005		2004

Pro Forma Statement of Operations Data
Revenues		$	1,393,715	$	969,177
Net income			403,925		212,207
Net income per share:
	Basic	$	6.24	$	2.61
	Diluted		6.03		2.57

4. Summary of significant accounting policies

Cash and cash equivalents

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.

Inventories

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

Oil and gas properties

At the end of each quarter, a full cost ceiling limitation calculation is made whereby net capitalized costs related to proved properties less associated deferred income taxes may not exceed an amount equal to the present value discounted at ten percent of estimated future net revenues from proved reserves less estimated future production and development costs and related income tax expense. Future net revenues used in the calculation of the full cost ceiling limitation are determined based on current oil and gas prices and is adjusted for designated cash flow hedges if it is determined that net capitalized costs exceed the full cost ceiling limit. If net capitalized costs subject to amortization were to exceed this limit, the excess would be charged to expense.

However, if commodity prices increase subsequent to period end and prior to issuance of the financial statements, these higher commodity prices will be used to determine if the capital costs are in fact impaired as of the end of the period. 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

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total estimated proved reserves. The costs of wells in progress and certain unevaluated properties are not being amortized. 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.

Proceeds from the sale of oil and gas properties are credited against capitalized costs, unless such proceeds would significantly alter the amortization base. Expenditures for maintenance and repairs are charged to production expense in the period incurred.

Goodwill

We account for goodwill in accordance with Statement of Financial Accounting Standards (SFAS) No. 142, Goodwill and Other Intangible Assets. SFAS No. 142 requires an annual impairment assessment. A more frequent assessment is required if certain events occur that reasonably indicate an impairment may have occurred. The volatility of oil and gas prices may cause more frequent assessments. The impairment assessment requires us to make estimates regarding the fair value of goodwill. The estimated fair value is based on numerous factors, including future net cash flows of our estimates of proved reserves as well as the success of future exploration for and development of unproved reserves. If the estimated fair value exceeds its carrying amount, goodwill is considered not impaired. If the carrying amount exceeds the estimated fair value, then a measurement of the loss must be performed, with any deficiency recorded as an impairment. To date, no related impairment has been recorded.

Revenue recognition

Oil and gas sales

Revenue from the sale of oil and gas is recognized when title passes, net of royalties. This is known as the sales method (versus the entitlement method). Under the sales method, revenue is recognized on actual volumes sold to purchasers. There is a ready market for oil and gas, with sales occurring soon after production.

Marketing sales

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

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, 2006 and 2005 was $3.2 million and $2.7 million, respectively. At December 31, 2006 we are also in an under-produced position relative to certain other third parties.

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Oil and gas reserves

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

Transportation costs

Cimarex accounts 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 not netted against gas sales.

Derivatives

In connection with the Magnum Hunter merger, Cimarex recognized a $39.3 million net liability associated with Magnum Hunter's existing commodity derivatives at the merger date (June 7, 2005). These derivative instruments have not been designated for hedge accounting treatment. As a result, Cimarex recognized a net gain for the year ended December 31, 2006 of $23.0 million. Activity included both non-cash mark-to-market derivative gains and losses as well as cash settlements. Cash payments related to these contracts that settled in the year ended December 31, 2006 was $19.0 million. As of December 31, 2006, all derivative contracts assumed with the Magnum Hunter merger had matured.

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In the third quarter of 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, 2006, this represented approximately 51% and 31% of our current anticipated Mid-Continent gas production for 2007 and 2008, respectively.

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

For the year ended December 31, 2006, we recorded an unrealized loss of $13 thousand related to the ineffective portion of the hedges. At December 31, 2006, $41.9 million and $7.1 million of the contracts were recorded as current and long-term assets, respectively, and an unrealized gain (net of deferred income taxes) of $31.0 million was recorded in other comprehensive income.

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. In July 2006, the FASB issued Interpretation 48, Accounting for Uncertainty in Income Taxes, which clarifies the accounting for uncertainty in income taxes recognized in the Company's financial statements in accordance with SFAS 109, Accounting for Income Taxes. The Interpretation also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition. The Interpretation is effective as of the beginning of the first fiscal year beginning after December 15, 2006 (January 1, 2007 for calendar-year companies). We are currently evaluating the effects of implementing this interpretation and do not believe the adoption of this interpretation will have a material impact on our financial statements.

Contingencies

A provision for contingencies is charged to expense when the loss is probable and the cost can be reasonably estimated. Determining when expenses should be recorded for these contingencies and the appropriate amounts for accrual is a complex estimation process that includes subjective judgment. In many cases, this judgment is based on interpretation of laws and regulations, which can be interpreted differently by regulators and/or courts of law. We closely monitor known and potential legal, environmental, and other contingencies and periodically determine when we should record losses for these items based on information available to us. As of December 31, 2006, we have accrued $7.1 million for a mediated litigation settlement pertaining to post-production deductions on properties operated by Cimarex. We have also accrued an additional $1.5 million for a mediated litigation settlement pertaining to oil and gas property title issues. We anticipate payment of both settlements during 2007.

F-13

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.

Earnings per share

Basic earnings per share includes no dilution and is computed by dividing net income available to common stockholders by the weighted average number of common shares outstanding for the period. Diluted earnings per share reflect the impact of potentially dilutive securities on weighted average number of shares.

Fair value of financial instruments

The carrying amounts of our 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, 2006, the allowance for doubtful accounts for trade, oil and gas sales, and gas gathering, processing, and marketing receivables was $5.7 million, $0.3 million, and $0.0 million, respectively. At December 31, 2005, the allowance for doubtful accounts for trade, oil and gas sales, and gas gathering, processing, and marketing receivables was $3.9 million, $1.2 million, and $0.7 million, respectively. The fair value of our variable and fixed rate debt at December 31, 2006 and 2005 was $457.6 million and $405.8 million, respectively.

Comprehensive income

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

F-14

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

	Net unrealized gain on derivative instruments(1)		Net unrealized gain (loss) on marketable securities of investments(1)			Accumulated other comprehensive income


Balance at January 1, 2004	$	—	$	—		$	—
2004 activity		—		88			88

Balance at December 31, 2004		—		88			88
2005 activity		—		(7	)		(7	)

Balance at December 31, 2005				81			81
2006 activity		30,954		46			31,000

Balance at December 31, 2006	$	30,954	$	127		$	31,081

(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 in 2006 (in 000's):


Unrealized derivative gain (loss) in comprehensive income, at January 1, 2006	$	—
Change in fair value		48,996
Reclassification of net (gains) losses to income
Net ineffectiveness		13

		49,009
Related income tax effect		(18,055	)

Unrealized derivative gain in comprehensive income at December 31, 2006	$	30,954

Segment information

Cimarex has one reportable segment (exploration and production).

Recent issued accounting standards

In September 2006 the Securities and Exchange Commission issued Staff Accounting Bulletin No. 108 regarding the process of quantifying misstatements within a financial statement, addressing in particular materiality analysis related to the correction of errors. The impact on the current year financial statements of correcting all misstatements, including both the carryover and reversing effects of prior year misstatements, must be quantified. Adjustment would be required if the misstatement is deemed material, after considering all relevant quantitative and qualitative factors. The periods in which the correction would be recorded would be dependent on the materiality considerations for each affected period. This did not have a material impact on our financial statements.

5. Derivatives

In connection with the Magnum Hunter merger, Cimarex recognized a $39.3 million liability associated with Magnum Hunter's existing commodity derivatives at the merger date (June 7,

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2005). These derivative instruments were not designated for hedge accounting treatment. As a result, Cimarex recognized a net gain during 2006 of $23.0 million. In 2005, we recorded a total net loss of $67.8 million. Activity includes both 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, and $83.3 million from the date of the merger through the fourth quarter of 2006. There is no derivative liability at December 31, 2006 related to these contracts as all derivative instruments have expired.

To mitigate a portion of the potential exposure to adverse market changes in an environment of volatile gas prices, we entered into additional derivative contracts in July 2006. These derivatives have been designated for hedge accounting treatment as cash flow hedges.

During the quarter ended December 31, 2006, we recognized an unrealized gain of $47 thousand related to the ineffective portion of the derivative contracts. The following table sets forth the terms of the related derivative contracts at December 31, 2006:

Commodity	Type	Volume/day	Duration	Mid-continent weighted average price		Fair value (000's)


Natural Gas	Collars	80,000 MMBTU	Jan 07-Dec 07	$	7.00-$10.17	$	41,945
Natural Gas	Collars	40,000 MMBTU	Jan 08-Dec 08	$	7.00-$9.90		7,051

						$	48,996

At December 31, 2006 the $49.0 million fair value of the derivative contracts was recorded as a current asset of $41.9 million and a long term asset of $7.1 million on our consolidated balance sheet. An unrealized gain (net of deferred income taxes) of $31.0 million was recorded in other comprehensive income. Based on the estimated fair values of the derivative contracts at December 31, 2006, the amount of unrealized gain (net of deferred income taxes) to be reclassified from accumulated other comprehensive income to gas revenue in the next twelve months would be approximately $26.5 million; however, actual gains and losses recognized may differ significantly. At December 31, 2006, the weighted average Mid-Continent prices for the 2007 and 2008 contracts approximated $6.13 and $7.02, respectively. We believe that we have sufficient production volumes such that the hedge contract transactions will occur as expected.

6. Asset retirement obligations

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The following table reflects the components of the change in the carrying amount of the asset retirement obligation for the years ended December 31, 2006 and 2005 (in thousands):

		2006			2005


Asset retirement obligation at January 1		$	101,128		$	19,762
	Liabilities incurred		15,318			5,735
	Liabilities assumed in the Magnum Hunter merger		—			68,908
	Liabilities settled		(4,337	)		(2,810	)
	Accretion expense		6,391			3,699
	Revisions of estimated liabilities		10,641			5,834

Asset retirement obligation at December 31			129,141			101,128
Less: Current asset retirement obligation			4,320			3,570

Long-term asset retirement obligation		$	124,821		$	97,558

7. Long-term debt

Debt at December 31, 2005 consisted of the following (in thousands):


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

Total long-term debt	$	352,451

Debt at December 31, 2006 consisted of the following (in thousands):


Bank debt	$	95,000
9.6% Notes due 2012 (face value $195,000)		210,746	(1)
Floating rate convertible notes due 2023, 5.36% at December 31, 2006 (face value $125,000)		137,921	(2)

Total long-term debt	$	443,667

(1): Fair market value at June 7, 2005 (date of acquisition of Magnum Hunter) equaled $215.5 million. The subsequent noted balances represent the fair market value at date of acquisition less amortization of the premium of fair market value over face value.
(2): Fair market value at June 7, 2005 equaled $144.75 million. The subsequent noted balances represent the fair market value at date of acquisition less amortization of the premium of fair market value over face value.

Cimarex's Revolving Credit Facility provides for $500 million of long-term committed credit. The facility is scheduled to mature on July 1, 2010 and is secured by mortgages on certain oil and gas properties and the stock of certain wholly-owned operating subsidiaries. At December 31, 2006, there were outstanding borrowings of $95 million under the Revolving Credit Facility at a weighted average interest rate of approximately 6.75%. We also had letters of credit for approximately $5 million posted against the borrowing base, leaving an unused borrowing amount of approximately $400 million at December 31, 2006.

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

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

Year		Percentage


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

The floating rate convertible senior notes were assumed in the Magnum Hunter merger and mature on December 15, 2023. The notes are senior unsecured obligations and bear interest at an annual rate equal to three-month LIBOR, reset quarterly. On December 31, 2006, the interest rate equaled 5.36%.

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

F-18

8. Income taxes

Federal income tax expense for the years ended December 31, 2006, 2005 and 2004 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,

		2006			2005		2004

Current taxes:
	Federal	$	(20,672	)	$	66,994	$	23,255
	State		(1,262	)		8,246		2,622

			(21,934	)		75,240		25,877
Deferred taxes:
	Federal		211,534			108,487		61,571
	State		9,005			4,403		5,278

			220,539			112,890		66,849

		$	198,605		$	188,130	$	92,726

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

	Years ended December 31,

	2006		2005			2004

Provision at statutory rate	$	190,513	$	180,759		$	86,212
Effect of state taxes		7,564		9,301			6,472
Domestic Production Activities deduction		—		(2,095	)		—
Other		528		165			42

Income tax expense	$	198,605	$	188,130		$	92,726

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

			December 31,

			2006			2005

Long-term:
	Assets:
		Net operating loss carryforwards	$	24,176		$	38,836
		Credit carryforwards		1,627			1,207
		Merger related accruals		25,762			40,124
		Other		23,723			3,996

				75,288			84,163
	Liabilities:
		Property, plant and equipment		(996,953	)		(801,953	)

		Net, long-term deferred tax liability		(921,665	)		(717,790	)
Current:
	Assets:
		Derivative instruments		—			15,273
		Other		1,498			2,686

				1,498			17,959

Net deferred tax liabilities			$	(920,167	)	$	(699,831	)

The company has a net tax operating loss (NOL) carryforward of approximately $66.3 million at December 31, 2006. The NOL carryforward expires from 2017 through 2022. The NOL carryforward was acquired as part of an acquisition, and therefore, is subject to annual limitations on its use. We believe that the carryforward will be utilized before it expires. The Company has an alternative minimum tax credit carryforward of approximately $1.6 million at December 31, 2006.

We have recorded deferred tax assets of $76.8 million of which $24.2 million is attributable to the NOL carryforward. Realization is dependent on generating sufficient taxable income in the future. Although realization is not assured, we believe it is more likely than not all of the deferred tax assets will be realized.

In July 2006, the Financial Accounting Standards Board issued Interpretation 48, Accounting for Uncertainty in Income Taxes (FIN 48), which clarifies the accounting for uncertain income tax positions recognized in the financial statements. The Interpretation also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. The effective date of this Interpretation is for fiscal years beginning after December 15, 2006. Cimarex is currently evaluating the effects of implementing FIN 48 and does not believe it will have a material impact on its financial statements.

9. 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.

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Restricted stock and units

During 2006 we issued a total of 600,589 restricted shares and 4,954 restricted units to non-employee directors, officers, and other employees. Included in that amount are 228,000 shares issued to certain executives that are subject to market condition-based vesting determined by Cimarex's stock price performance relative to a defined peer group's stock price performance. After three years of continued service, the executive will be entitled to and vest in 50% to 100% of the award. The market condition performance goals applicable to these awards were approved by stockholders in May 2006. The remainder of the shares and units granted in 2006 has requisite service-based vesting ranging from one to five years.

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

		Years ended December 31,

		2006		2005		2004

Outstanding beginning of period		249,905		14,145		24,086
	Vested	(7,915	)	(11,248	)	(19,086	)
	Granted	600,589		249,008		9,145
	Canceled	(49,800	)	(2,000	)	—

Outstanding end of period		792,779		249,905		14,145

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

		Years ended December 31,

		2006		2005		2004

Outstanding beginning of period		697,937		780,787		693,600
	Converted to Stock	—		(154,600	)	—
	Granted	4,954		71,750		87,187
	Canceled	(6,250	)	—		—

Outstanding end of period		696,641		697,937		780,787

Vested included in outstanding		172,617		128,550		84,480

Vesting of restricted stock and units granted in years prior to 2006 is exclusively related to continued service of the grantee for one to five years. In certain cases, there is also a three year required holding period subsequent to vesting. 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, net of an estimated forfeiture rate. 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. For the years ended December 31, 2006, 2005, and 2004, we recorded compensation expense of $5.9 million, $5.2 million, and $2.7 million, respectively. Stock-based compensation costs

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capitalized to oil and gas properties during 2006, 2005 and 2004 were $3.3 million, $1.7 million, and $0.7 million, respectively.

In accordance with SFAS No 123R, all deferred compensation and the unearned compensation amounts associated with restricted stock and unit grants have been reclassified to paid-in-capital.

Stock options

During 2006 we issued 60,600 non-qualified stock options. Options granted under our plan expire ten years from the grant date and vest in one-fifth increments on each of the first five anniversaries of the grant date. The plan provides that all grants have an exercise price equal to 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 stock options granted after October 1, 2002, grantee's are required to hold at least 50 percent of the profit shares, as defined in the plan, until the eighth anniversary of the grant date.

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, 2006		2,023,388		$	15.64
	Exercised	(170,459	)		15.83
	Granted	60,600			34.63
	Canceled	—			—

Outstanding as of December 31, 2006		1,913,529		$	16.23	4.7 Years	$	39,127

Exercisable as of December 31, 2006(1)		1,607,249		$	14.93	4.2 Years	$	34,758

(1): Does not include 6,060 vested options that have an exercise price exceeding our December 31, 2006 stock price.

The total intrinsic value of stock options exercised during 2006 was $4.4 million. In 2005 and 2004 the intrinsic value of stock options exercised was $17.7 million and $12.6 million, respectively.

During 2006 compensation expense related to stock options was approximately $2.3 million, or $1.5 million after tax ($0.02 per basic and diluted share). In 2005 compensation expense was $3.4 million, or $2.2 million after tax. Included in 2005 is $1.1 million, or $0.7 after tax, related to acceleration of vesting due to the Magnum Hunter merger. Compensation expense 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.

The weighted-average grant-date fair value of stock options granted during the years ended December 31, 2006, 2005, and 2004 was $15.75, $17.20, and $12.24, 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.

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

	Years ended December 31,

	2006	2005	2004

Expected years until exercise	7.5	7.5	7.5
Expected stock volatility	32.2%	25.5%	25.4%
Dividend yield	0.1%	0.0%	0.0%
Risk-free interest rate	4.8%	4.1%	3.4%

Cash received from option exercises during the years ended December 31, 2006, 2005, and 2004 was approximately $2.7 million, $9.3 million, and $9.0 million, respectively. The related tax benefits realized from option exercises totaled approximately $1.6 million, $6.4 million, and $4.8 million, respectively, and was recorded against paid-in capital.

The following summary reflects the status of non-vested stock options granted to employees and directors as of December 31, 2006 and changes during the year:

		Shares		Weighted average grant date fair value


Non-vested as of January 1, 2006		456,260		$	8.75
	Vested	(216,640	)		8.41
	Granted	60,600			15.75
	Forfeited	—			—

Non-vested as of December 31, 2006		300,220		$	10.41

As of December 31, 2006 there was $2.9 million of unrecognized compensation cost related to non-vested stock options granted under our stock incentive plan. That cost is expected to be recognized pro rata over a weighted-average period of 3.8 years. The weighted average exercise price of the non-vested stock options is $22.62.

The total grant-date fair value of options that vested during 2006 was $1.8 million. The grant-date fair value of options that vested in 2005 and 2004 was $3.6 million and $3.5 million, respectively.

For periods prior to January 1, 2005, we applied Accounting Principles Board (APB) Opinion 25, Accounting for Stock Issued to Employees, and related interpretations to account for all stock option grants. Prior to 2005, we did not recognize compensation expense for stock options because the exercise prices were equal to the grant-date fair market value of the underlying common stock.

Had compensation expense for stock options been determined based on amortization of the grant-date fair value of the awards, consistent with SFAS No. 123R, such compensation expense would have been $2.1 million for 2004.

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Pro forma net income for 2004 would have been as indicated below (in thousands except per share amounts).

		2004


Net income, as reported		$	153,592
Less: Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects			2,121

Pro forma net income		$	151,471

Earnings per share:
	Basic—as reported	$	3.70
	Basic—pro forma	$	3.65
	Diluted—as reported	$	3.59
	Diluted—pro forma	$	3.54

Stockholder rights plan

Cimarex has 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 of the Company. The Rights will become exercisable only in the event a person or group acquires beneficial ownership of 15 percent 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 percent or more of our common stock. The purchase price for each one one-hundredth of a share of Preferred Stock pursuant to the exercise of a Right is $60.00, subject to adjustment in certain cases to prevent dilution.

Cimarex generally will be entitled to redeem the Rights under certain circumstances at $0.01 per Right at any time prior to the close of business on the tenth business day after there has been a public announcement of the acquisition of the beneficial ownership by any person or group of 15 percent 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 the Company's first quarterly cash dividend of $.04 per share. A $.04 per share cash dividend was also declared to shareholders in every quarter of 2006. 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 common stock. Through December 31, 2005, 68,000 shares had been repurchased at an average price of $43.03. In 2006, an additional 182,100 shares were repurchased at an average price of $44.43 per share. All repurchased shares have been cancelled.

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

		Number of shares

(in thousands)		Issued		Treasury		Outstanding

December 31, 2003		41,064		—		41,064
	Shares issued under compensation plans, net of cancellations	5		—		5
	Option exercises, net of cancellations	660		—		660

	December 31, 2004	41,729		—		41,729
	Shares issued for Magnum Hunter acquisition	42,185		(2,476	)	39,709
	Shares issued under compensation plans, net of cancellations	401		—		401
	Option exercises, net of cancellations	606		—		606
	Treasury shares purchased	—		(68	)	(68	)
	Treasury shares cancelled	(1,397	)	1,397		—

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

10. Earnings per share

The calculations of basic and diluted net earnings per common share for the years ended December 31, 2006, 2005 and 2004 are presented in the table below (in thousands, except per share data):

		December 31,

		2006		2005		2004

Basic earnings per share:
	Income available to common stockholders	$	345,719	$	328,325	$	153,592
	Weighted average basic share outstanding		82,066		64,761		41,466

	Basic earnings per share	$	4.21	$	5.07	$	3.70

Diluted earnings per share:
	Income available to common stockholders	$	345,719	$	328,325	$	153,592

	Weighted average basic shares outstanding		82,066		64,761		41,466
	Incremental shares assuming the exercise of stock options, vesting of restricted stock units and conversion of the floating rate convertible notes		2,024		2,239		1,297

	Weighted average diluted shares outstanding		84,090		67,000		42,763

	Diluted earnings per share	$	4.11	$	4.90	$	3.59

There were stock options outstanding for 1,913,529, 2,023,388 and 2,657,082 shares of Cimarex common stock at December 31, 2006, 2005 and 2004, respectively.

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11. Employee benefit plans

Cimarex maintains and sponsors contributory health care plans and a contributory 401(k) plan. Cimarex employees participate in these plans and costs related to these plans were $12.1 million, $6.8 million and $4.7 million in the years ended December 31, 2006, 2005 and 2004, respectively.

12. Related party transactions

Helmerich & Payne, Inc. provides contract drilling services to Cimarex. Drilling costs of approximately $20.5 million, $15.4 million and $10.4 million were incurred by Cimarex related to such services for the years ended December 31, 2006, 2005 and 2004, respectively. Hans Helmerich, a director of Cimarex, is President and Chief Executive Officer of Helmerich & Payne, Inc.

13. Major customers

During 2006, sales to one purchaser represented approximately 11 percent of our revenues. No individual purchasers represented more than 10 percent of our revenues for the years ended December 31, 2005 and 2004.

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.

14. Supplemental disclosure of cash flow information (in thousands)

		For the years ended December 31,

		2006		2005		2004

Cash paid during the period for:
	Interest (net of amounts capitalized)	$	5,268	$	2,367	$	972
	Income taxes (net of refunds received)	$	36,767	$	49,824	$	20,932

15. Commitments and contingencies

Litigation

As of December 31, 2006, we have accrued $7.1 million for a mediated litigation settlement pertaining to post-production deductions on properties operated by Cimarex. We have also accrued an additional $1.5 million for a mediated litigation settlement pertaining to oil and gas property title issues. We anticipate payment of both settlements during 2007. Cimarex has other various litigation related matters in the normal course of business, none of which that can be estimated are deemed to be material, individually or in aggregate. We are also party to certain litigation as plaintiffs that could result in potential gains. Net settlements of $3.4 million were received during 2004 related to litigation in which we were plaintiffs. Litigation settlements are recorded in other operating, net in the Consolidated Statements of Operations.

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Shown below are the five year debt maturities and five year lease commitments as of December 31, 2006:

	Payments due by period

(In thousands)	Total		Less than 1 year		1-3 years		3-5 years		More than 5 years

Long term debt (face value)(1)	$	415,000	$	—	$	—	$	95,000	$	320,000
Operating leases	$	31,278	$	5,158	$	10,074	$	7,868	$	8,178

(1): In the next five years, $95 million of debt related to our credit facility is due in 2010.

Cimarex has other various delivery commitments in the normal course of business, none of which are individually material. In aggregate these commitments have a maximum amount that would be payable, if no gas is delivered, of approximately $2.8 million.

Cimarex has 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 $5.2 million, $3.5 million, and $2.5 million for the years ended December 31, 2006, 2005, and 2004, respectively.

The Company has contractual commitments for drilling rigs and on oil and gas wells approved for drilling or in the process of being drilled at December 31, 2006 of approximately $55.3 million.

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

16. Property sales

The Company's limited partnership affiliates, Teal Hunter L.P. and Mallard Hunter L.P., sold all of their interests in oil and gas properties during the quarter ended September 30, 2006. Cimarex's investments in these partnerships had been reflected in other assets, net. The net consideration received to date via distributions from the partnerships equaled $59.3 million. The excess distributions of $19.8 million have been recorded in other income.

Various interests in oil and gas properties were sold during 2006 and 2005, with net consideration equaling $4.5 million and $149.3 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.

17. 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

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we act as producer. Income taxes related to our oil and gas operations are computed using the effective tax rate for the period (in thousands):

		Years ended December 31

		2006		2005		2004

Oil and gas revenues from production		$	1,215,411	$	1,072,422	$	472,389
Less operating costs and income taxes:
	Depletion		379,640		248,017		120,499
	Asset retirement obligation accretion		7,018		3,819		1,241
	Production		176,833		104,067		37,476
	Transportation		21,157		15,338		10,003
	Taxes other than income		91,066		73,360		37,761
	Income taxes		196,935		228,527		99,794

			872,649		673,128		306,774

Results of operations from oil and gas producing activities		$	342,762	$	399,294	$	165,615

Amortization rate per Mcfe		$	2.32	$	1.92	$	1.52

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,

			2006			2005			2004

Costs incurred during the year:
	Acquisition of properties
		Proved	$	25,970		$	1,523,356		$	324
		Unproved		64,421			338,557			17,177
	Exploration			292,336			225,297			57,485
	Development			691,946			375,616			222,105

		Oil and gas expenditures		1,074,673			2,462,826			297,091
	Property sales			(4,459	)		(149,262	)		(662	)
	Asset retirement obligation, net			20,177			9,118			2,059

			$	1,090,391		$	2,322,682		$	298,488

Aggregate capitalized costs—The table below reflects the aggregate capitalized costs relating to our oil and gas producing activities at December 31, 2006 (in thousands):


Proved properties	$	4,656,854
Unproved properties and properties under development, not being amortized		425,173

		5,082,027
Less-accumulated depreciation, depletion and amortization		(1,494,317	)

Net oil and gas properties	$	3,587,710

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Costs not being amortized—The following table summarizes oil and gas property costs not being amortized at December 31, 2006, by year that the costs were incurred (in thousands):


2006	$	146,918
2005		271,924
2004		5,329
2003 and prior		1,002

	$	425,173

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 (unaudited)—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 percent of the discounted future net cash flows before income taxes for the year ended December 31, 2006. Ryder Scott Company, L.P., independent petroleum engineers, and DeGolyer and MacNaughton collectively reviewed the proved reserve estimates associated with at least 80 percent of the discounted future net cash flows before income taxes for the year ended December 31, 2005. Ryder Scott Company, L.P. reviewed the proved reserve estimates associated with at least 80 percent of the discounted future net cash flows before income taxes for the year ended December 31, 2004.

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 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, 2006, 2005

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and 2004 represents estimates only 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, 2006

		December 31, 2006				December 31, 2005				December 31, 2004
		Gas				December 31, 2005				December 31, 2004
		Gas		Oil		Gas		Oil		Gas		Oil

		(MMcf)		(MBbl)		(MMcf)		(MBbl)		(MMcf)		(MBbl)
Total proved reserves—Developed and undeveloped
	Beginning of year	1,004,482		64,710		364,641		14,063		337,344		14,137
	Revisions of previous estimates	(14,498	)	(3,684	)	9,534		270		20,068		1,154
	Extensions, discoveries & improved recovery	170,933		5,018		209,758		4,477		70,748		1,443
	Purchases of reserves	55,046		551		531,862		59,288		134		2
	Production	(124,733	)	(6,529	)	(100,272	)	(4,804	)	(63,611	)	(2,641	)
	Sales of properties	(868	)	(269	)	(11,041	)	(8,584	)	(42	)	(32	)

	End of year	1,090,362		59,797		1,004,482		64,710		364,641		14,063

Proved developed reserves		851,213		50,202		820,244		51,521		364,566		13,372

Standardized Measure of future net cash flows (unaudited)—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.

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

	December 31,

	2006			2005			2004

Cash inflows	$	9,397,265		$	11,502,690		$	2,570,347
Production costs		(2,760,771	)		(2,957,911	)		(658,658	)
Development costs		(581,855	)		(504,686	)		(9,246	)
Income tax expense		(1,943,773	)		(2,682,075	)		(641,485	)

Net cash flow		4,110,866			5,358,018			1,260,958
10% annual discount rate		(1,909,977	)		(2,329,918	)		(462,925	)

Standardized measure of discounted future net cash flow	$	2,200,889		$	3,028,100		$	798,033

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

	December 31,

	2006			2005			2004

Standardized measure, beginning of period	$	3,028,100		$	798,033		$	711,581
Sales, net of production costs		(929,638	)		(879,657	)		(387,150	)
Net change in sales prices, net of production costs		(1,168,787	)		629,462			45,614
Extensions, discoveries and improved recovery, net of future production and development costs		468,854			988,001			313,417
Net change in future development costs		193,280			17,777			16,380
Revision of quantity estimates		(88,023	)		45,895			71,374
Accretion of discount		435,888			117,223			103,034
Change in income taxes		445,073			(956,585	)		(55,438	)
Purchases of reserves in place		64,538			2,379,099			221
Sales of properties		(7,216	)		(136,102	)		(289	)
Change in production rates and other		(241,180	)		24,954			(20,711	)

Standardized measure, end of period	$	2,200,889		$	3,028,100		$	798,033

Impact of pricing (unaudited)—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,

	2006		2005		2004

Price per Mcf	$	5.54	$	7.89	$	5.58
Price per Bbl	$	56.91	$	57.65	$	40.76

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

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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.

18. Unaudited supplemental quarterly financial data

2006 (in thousands, except for per share data)		First		Second		Third		Fourth


Revenues		$	335,250	$	313,381	$	322,882	$	295,631
Expenses, net			225,099		230,515		228,925		236,886

	Net income	$	110,151	$	82,866	$	93,957	$	58,745

Earnings per common share:
	Basic	$	1.33	$	1.01	$	1.15	$	0.72
	Diluted	$	1.29	$	0.98	$	1.11	$	0.70

2005 (in thousands, except for per share data)		First		Second		Third		Fourth


Revenues		$	137,944	$	188,058	$	363,094	$	429,526
Expenses, net			94,579		135,581		299,019		261,118

	Net income	$	43,365	$	52,477	$	64,075	$	168,408

Earnings per common share:
	Basic	$	1.04	$	1.01	$	0.78	$	2.04

	Diluted	$	1.00	$	0.98	$	0.76	$	1.98

The sum of the individual quarterly net income per common share amounts may not agree with year-to-date net income per common share because each period's computation is based on the weighted average number of shares outstanding during that period.

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