UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

þ		ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Magnum Hunter Resources Corporation

(Name of registrant as specified in its charter)

DELAWARE		86-0879278
(State or other jurisdiction of		(I.R.S. Employer
incorporation or organization)		Identification No.)

777 Post Oak Boulevard, Suite 910, Houston, Texas 77056
(Address of principal executive offices, including zip code)

Title of each class		Name of each exchange on which registered
$0.01 par value Common Stock 10.25% Series C Cumulative Perpetual Preferred Stock		NYSE Amex NYSE Amex

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o No þ

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Exchange Act. Yes o No þ

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes o No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company (as defined in Rule 12b-2 of the Act):

Large accelerated filer o		Accelerated filer o		Non-accelerated filer o		Smaller reporting company þ

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No þ

State the aggregate market value of voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of the registrant’s most recently completed second fiscal quarter: $21,172,701.

As of March 29, 2010, 57,979,111 shares of the registrant’s common stock were issued and outstanding.

Portions of the registrant’s definitive proxy statement for its Annual Meeting of Stockholders for 2010 to be filed with the Commission within 120 days after the close of its fiscal year are incorporated by reference into Part III hereof.

 

 

FORM 10-K ANNUAL REPORT
FISCAL YEAR ENDED DECEMBER 31, 2009
MAGNUM HUNTER RESOURCES CORPORATION

Item		Page
PART I
1. Business			5
1A. Risk Factors			15
1B. Unresolved Staff Comments			28
2. Properties			29
3. Legal Proceedings			38
4. Submission of Matters to a Vote of Security Holders			39
PART II
5. Market for Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities			46
6. Selected Financial Data			47
7. Management’s Discussion and Analysis of Financial Condition and Results of Operations			48
7A. Quantitative and Qualitative Disclosures About Market Risk			62
8. Financial Statements and Supplementary Data			63
9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure			66
9A(T). Controls and Procedures			66
9B. Other Information			67
PART III
10. Directors, Executive Officers and Corporate Governance			68
11. Executive Compensation			68
12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters			68
13. Certain Relationships and Related Transactions, and Director Independence			68
14. Principal Accountant Fees and Services			68
15. Exhibits and Financial Statement Schedules			68
Exhibit 21.1
Exhibit 23.1
Exhibit 23.2
Exhibit 23.3
Exhibit 23.4
Exhibit 31.1
Exhibit 31.2
Exhibit 32

CAUTIONARY NOTICE

The statements and information contained in this annual report on Form 10-K that are not statements of historical fact, including all of the estimates and assumptions contained herein, are “forward looking statements” as defined in Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. These forward looking statements include, among others, statements, estimates and assumptions relating to our business and growth strategies, our oil and gas reserve estimates, our ability to successfully and economically explore for and develop oil and gas resources, our exploration and development prospects, future inventories, projects and programs, expectations relating to availability and costs of drilling rigs and field services, anticipated trends in our business or industry, our future results of operations, our liquidity and ability to finance our exploration and development activities, market conditions in the oil and gas industry and the impact of environmental and other governmental regulation. Forward-looking statements generally can be identified by the use of forward-looking terminology such as “may”, “will”, “could”, “should”, “expect”, “intend”, “estimate”, “anticipate”, “believe”, “project”, “pursue”, “plan” or “continue” or the negative thereof or variations thereon or similar terminology.

These forward-looking statements are subject to numerous assumptions, risks, and uncertainties. Factors that may cause our actual results, performance, or achievements to be materially different from those anticipated in forward-looking statements include, among others, the following:

	•		adverse economic conditions in the United States and globally;
	•		difficult and adverse conditions in the domestic and global capital and credit markets;
	•		changes in domestic and global demand for oil and natural gas;
	•		volatility in the prices we receive for our oil and natural gas;
	•		the effects of government regulation, permitting, and other legal requirements;
	•		future developments with respect to the quality of our properties, including, among other things, the existence of reserves in economic quantities;
	•		uncertainties about the estimates of our oil and natural gas reserves;
	•		our ability to increase our production and oil and natural gas income through exploration and development;
	•		our ability to successfully apply horizontal drilling techniques and tertiary recovery methods;
	•		the number of well locations to be drilled, the cost to drill, and the time frame within which they will be drilled;
	•		drilling and operating risks;
	•		the availability of equipment, such as drilling rigs and transportation pipelines;
	•		changes in our drilling plans and related budgets;
	•		the adequacy of our capital resources and liquidity including, but not limited to, access to additional borrowing capacity;
	•		other factors discussed under “Risk Factors” in Item 1A of this report.

These factors are in addition to the risks described in the “Risk Factors” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” sections of this document. Most of these factors are difficult to anticipate and beyond our control. Because forward-looking statements are subject to risks and uncertainties, actual results may differ materially from those expressed or implied by such statements. You are cautioned not to place undue reliance on forward-looking statements, contained herein, which speak only as of the date of this document. Other unknown or unpredictable factors may cause actual results to differ materially from those projected by the forward-looking statements. Unless otherwise required by law, we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events, or otherwise. We urge readers to review and consider disclosures we make in this and other reports that discuss factors germane to our business. See in particular our reports on Forms 10-K, 10-Q, and 8-K subsequently filed from time to time with the Securities and Exchange Commission.

All forward-looking statements attributable to us are expressly qualified in their entirety by these cautionary statements.

SPECIAL NOTE REGARDING THE REGISTRANT

In this Annual Report on Form 10-K, the words “Magnum Hunter”, “Company”, “we”, “our”, and “us” refer to Magnum Hunter Resources Corporation and its consolidated subsidiaries unless stated or the context otherwise requires.

We file Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on form 8-K, registration statements and other items with the Securities and Exchange Commission (“SEC”). We provide access free of charge to all of these SEC filings, as soon as reasonably practicable after filing, on our Internet site located at www.MagnumHunterResources.com. In addition, the public may read and copy any materials we file with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. Also, the SEC maintains an internet website that contains reports, proxy and information statements, and other information regarding issuers, including Magnum Hunter Resources Corporation, that file electronically with the SEC. The public can obtain any document we file with the SEC at www.sec.gov. Information contained on or connected to our website is not incorporated by reference into this Form 10-K and should not be considered part of this report or any other filing that we make with the SEC.

Industry terms used in this report are defined in the Glossary of Oil and Natural Gas Term located at the end of Part 1.

PART I

Item 1. BUSINESS

Overview

We are an independent oil and gas company engaged in the acquisition, development and production of oil and natural gas, primarily in West Virginia, North Dakota, Texas and Louisiana. The Company is presently active in three of the four most prolific shale resource plays in the United States, including the Marcellus Shale, Eagle Ford Shale and Williston Basin / Bakken Shale. The Company is a Delaware corporation and was incorporated in 1997. In 2005, the Company began oil and gas operations under the name Petro Resources Corporation. In May of 2009, the Company restructured its management team and refocused its business strategy, and in July of 2009, changed its name to Magnum Hunter Resources Corporation (“MHR”). The restructured management team includes Gary C. Evans, former Founder, Chairman and Chief Executive Officer of Magnum Hunter Resources, Inc.,¹ as Chairman and Chief Executive Officer, Ronald D. Ormand as Executive Vice President and Chief Financial Officer, H.C. “Kip” Ferguson as Executive Vice President of Exploration and M. Bradley Davis as Senior Vice President of Capital Markets. Our management has implemented a new business strategy consisting of exploiting our inventory of lower-risk drilling locations and the acquisition of long-lived proved reserves with significant exploitation and development opportunities. As a result of this new strategy, the Company has substantially increased its assets and production through three acquisitions and ongoing development efforts, the percentage of operated properties has increased significantly, its inventory of acreage and drilling locations in resource plays have grown and its management team has been expanded.

At December 31, 2009, our estimated proved reserves of 6.2 MMboe were approximately 75% oil, had a standardized measure of $47.4 million and an SEC PV-10 value of $65.6 million. This represents a 97% increase in proved reserves from the level at year ended 2008. Our average daily production volumes for 2009 were 703 Boepd, which represents a 22% increase from those levels experienced in 2008. Our average daily production volumes were approximately 900 Boe per day at December 31, 2009.

Significant Developments and Achievements

Triad Acquisition. On February 12, 2010, the Company closed the acquisition of substantially all of the assets of privately-held Triad Energy Corporation and certain of its affiliates (collectively, “Triad”), a 23-year old Appalachian Basin focused oil and gas production company. The Company acquired the assets of Triad in connection with Triad’s reorganization under Chapter 11 of the United States Bankruptcy Code. Triad’s operations are located in the states of Ohio, West Virginia and Kentucky, in the Appalachian Basin. The assets acquired from Triad include (i) conventional, mature oil fields currently under primary and secondary development with approximately 5.1 MMboe of proved reserves (65% oil); and over 2,000 producing wells (99% of which are operated by Triad) with a production exit rate on December 31, 2009 of approximately 830 Boepd; (ii) over 87,000 net acres including approximately 46,000 net acres in the prolific Marcellus Shale; (iii) 182 miles of gas pipeline and rights-of-way that will allow for the construction of new larger diameter pipeline that will provide Magnum Hunter with significant take-away capacity for our Marcellus Shale gas as well as revenue from transporting third-party gas; (iv) service equipment including three drilling rigs; and (v) commercial salt water disposal facilities. These assets are now held by our wholly-owned subsidiaries Triad Hunter, LLC, Alpha Hunter Drilling, LLC, Eureka Hunter Pipeline, LLC, Hunter Disposal, LLC and Hunter Real Estate, LLC. Consideration for the assets acquired from Triad totaled $81 million consisting of:

	•		$55 million for the repayment of Triad’s senior debt, which $55 million was borrowed by the Company pursuant to the terms of the new Restated Credit Agreement discussed below;
	•		$15 million of our Series B Redeemable Convertible Preferred Stock, issued to certain banks that were secured creditors of Triad;
	•		$8 million in cash; and
	•		Assumption of approximately $3 million of equipment indebtedness.
	•		The Fair Value of the consideration approximated its $81 million face value.

As a result of the Triad acquisition, on a SEC basis, the Company had pro forma reserves of 11.3 MMboe with PV-10 of $122 million (70% oil) at December 31, 2009. On a NYMEX strip basis, our reserves were 12.3 MMboe with a PV-10 of $237.5 million.

Bank of Montreal Credit Facilities. On November 23, 2009, we entered into a $150 million Credit Agreement (the “Credit Agreement”) with Bank of Montreal. The Credit Agreement provided for an asset-based, three-year senior secured revolving credit facility (the “Revolving Facility”), with an initial borrowing base availability of $25 million. On February 12, 2010 we amended and restated the Credit Agreement (the “Restated Credit Agreement”) with Bank of Montreal and Capital One, NA, providing for a borrowing base of $70 million.

Acquisition of Sharon Resources, Inc. On September 30, 2009, we acquired Sharon Resources, Inc., a wholly-owned subsidiary of Calgary-based Sharon Energy Ltd., bringing an inventory of drilling locations focused in the Eagle Ford Shale located in South Texas. Additionally, the Sharon acquisition enhanced the Company’s technical expertise with the addition of experienced geologists and land professionals.

Equity Financings. Throughout the fourth quarter of 2009, the Company raised substantial cash through equity transactions. Those transactions included:

	•		$15.2 million of common equity financings throughout the course of the fourth quarter.
	•		$5.4 million in gross proceeds from the issuance of our 10.25% Series C Cumulative Perpetual Preferred Stock, (“Series C Preferred Stock”) at a price of $25.00 per share in the fourth quarter of 2009

Summary of Proved Reserves, Wells and Production

SEC Case Reserve Summary (1)

		At December 31, 2009
																						2009 Average
		Proved								%				Productive Wells								Daily Production
Area		Reserves (a)				PV10% (b)(c)				Oil				Gross				Net				Volumes (d)
		(MMboe)				($MMs)																(boe)
North Dakota			3.098			$	45.70				96	%			146				65.7				335
West Texas			2.199				12.20				62	%			87				8.7				302
South Texas / Gulf Coast			0.841				7.50				33	%			10				2.9				33
Other			0.031				0.20				0	%			5				0.5				33
Total			6.169			$	65.60				74	%			248				77.8				703

Pro Forma SEC Case Reserve Summary (2)

		Pro Forma At December 31, 2009 *
																						2009 Average
		Proved								%				Productive Wells								Daily Production
Area		Reserves (a)				PV10% (b)(c)				Oil				Gross				Net				Volumes (d)
		(MMboe)				($MMs)																(boe)
Appalachian Basin			5.129			$	56.40				65	%			2,074				1,970.3				1,000
North Dakota			3.098				45.70				96	%			146				65.7				335
West Texas			2.199				12.20				62	%			87				8.7				302
South Texas / Gulf Coast			0.841				7.50				32	%			10				2.9				33
Other			0.031				0.20				0	%			5				0.5				33
Total			11.298			$	122.00				70	%			2,322				2,048.1				1,703

NYMEX Futures Strip Case Reserve Summary

		At December 31, 2009
																						2009 Average
		Proved								%				Productive Wells								Daily Production
Area		Reserves (e)				PV10% (f)				Oil				Gross				Net				Volumes (g)
		(MMboe)				($MMs)																(boe)
North Dakota			3.339			$	81.5				95	%			146				66				335
West Texas			2.337			$	27.7				62	%			87				9				302
South Texas / Gulf Coast			0.896			$	9.0				32	%			10				3				30
Other			0.038			$	0.3				0	%			5				1				36
Total			6.610			$	118.5				75	%			248				79				703

Pro Forma NYMEX Futures Strip Case Reserve Summary (2) *

																						2009 Average
		Proved								%				Productive Wells								Daily Production
Area		Reserves (e)				PV10% (f)				Oil				Gross				Net				Volumes (g)
		(MMboe)				($MMs)																(boe)
Appalachian Basin			5.725			$	119.0				66	%			2,074				1,970				1,000
North Dakota			3.339				81.5				95	%			146				66				335
West Texas			2.337				27.7				62	%			87				9				302
South Texas / Gulf Coast			0.896				9.0				32	%			10				3				30
Other			0.038				0.3				0	%			5				1				36
Total			12.335			$	237.5				70	%			2,322				2,049				1,703

Business Strategy

Our business strategy is to create value for our stockholders by growing reserves, production volumes and cash flow through cost effective development of our properties and through strategic acquisitions. The Company employs many of the elements that have proved successful for our management team in the past. Key elements of our business strategy include:

Focus on Unconventional Resource Plays —We intend to focus on the development and expansion of our properties in the Marcellus Shale, Eagle Ford Shale and Williston / Bakken Shale. As of March 29, 2010, the Company currently had over 95,200 gross acres in these three areas and over 125 identified drilling locations. The Company intends to commence its initial drilling efforts on these locations in 2010. With recent improvements in drilling and completion technologies, the development of unconventional resources has become highly economic.

Strategic Acquisitions — The Company intends to opportunistically acquire additional acreage and reserves. Since the restructuring of the Company’s management in May of 2009, we have completed three significant acquisitions, including Sharon, East Chalkley and Triad. We believe that our acquisition related and operational track record, as well as our extensive industry relationships will provide for continued growth opportunities in the future.

Focus on Acquisition and Development of Oil Assets — We plan to focus our development and acquisition efforts primarily on oil reserves, as we believe they currently present the most attractive returns on capital employed, as compared to natural gas. At March 29, 2010, 75% of our proved reserves and 65% of current production were oil.

Operating Control — We believe that operatorship provides the ability to maximize the value of our assets, including timing of drilling expenditures, enhanced controls on operational costs and the ability to enhance production volumes. We have significantly increased the number of wells that we operate. Pro Forma for the Triad acquisition, we operated 95% of our net wells in production and 53% of proved reserves at March 29, 2010.

Employment of Advanced Technologies — We utilize state of the art, advanced technologies, allowing us to achieve the best opportunity for drilling success. Our technical team continually reviews the most current technologies and applies them to our reserve base for the effective development of our project inventory.

Leveraging the Experience of our Management Team — Management will actively utilize its track record and relationships with industry partners, commercial banks, investment banks, institutional equity investors and private equity investors to assist us in rapidly building and developing the Company’s asset base and financing the Company’s growth on a cost effective basis.

Development of Pipeline and Infrastructure Assets — We are actively pursuing the completion of our 182-mile pipeline asset to support the development of our Marcellus acreage. We have allocated $10 million in our 2010 capital budget to complete the initial 12 mile phase of our pipeline. The Company is actively pursuing joint venture and other financing structures to support the expansion of the pipeline, and anticipates ultimately increasing throughput capacity to approximately 200 MMcf/d. We anticipate the initial pipeline expansion to be completed in the third quarter of 2010.

Competitive Strengths

We believe that our key competitive strengths include:

Experienced Management Team — Our management team, on average, has over 25 years of experience in the oil and gas industry. Senior management has extensive experience in managing, financing and operating public oil and gas companies. Magnum Hunter Resources, Inc., (“MHRI”), founded by Gary C. Evans in 1985 and unrelated to the Company, achieved an average annual internal rate of return of 38% to shareholders during the 15 years it was publicly traded. Additionally, our management team has collectively completed over $30 billion in financing transactions and acquisitions in the oil and gas industry and our personnel have extensive expertise in key operational disciplines.

Balanced Long-Lived Asset Base with Substantial Oil Reserves — As of December 31, 2009, we owned interests in 248 gross (77.8 net) productive wells across approximately 28,000 gross (8,500 net) mineral acres. We believe this geographic mix of properties and drilling opportunities, combined with our continuing business strategy of acquiring and exploiting properties in these areas, presents us with multiple opportunities in executing our strategy. Our proved reserve life is approximately 14 years based on year-end 2009 pro forma proved reserves and estimated production for 2010. Approximately 75% of our proved reserves as of December 31, 2009 were oil and an estimated 71% of production was oil.

Acreage Position and Drilling Inventory in Core Resource Areas — As of March 29, 2010, we had significant acreage of over 68,600 net acres in our core shale areas, including approximately 46,000 net acres in the Marcellus Shale, 15,000 net acres in Eagle Ford Shale and 7,600 net acres in the Williston/Bakken Shale. We have identified an inventory of over 125 drillable locations in these core areas.

Marcellus Infrastructure Assets — The Company controls approximately 182 miles of pipeline, gathering systems and rights-of-way to provide critical takeaway capacity and third party transportation in the capacity-constrained Marcellus Shale area of West Virginia. Following our planned expansion, we estimate our natural gas pipeline system will have throughput capacity of approximately 200 MMcf/d. In addition, we own and operate a 2,200-5,000 barrel per day commercial salt water disposal facility that was acquired in the Triad acquisition, which is important to the efficient operation and development of our assets in the Marcellus Shale area. We also maintain an inventory of drilling rigs and various oilfield service equipment to be used to develop our oil and gas assets located in the Appalachian region.

2010 Capital Budget

As of the date of this report, we estimate our capital budget for fiscal year 2010 to be approximately $25 million, including:

•

Approximately $17.1 million to be deployed for activities in the Appalachian Basin, including $10 million to complete the initial phase of the Eureka Hunter Pipeline project and approximately $7.1 million to drill two horizontal wells targeting the Marcellus Shale formation.

•

Approximately $6.95 million towards operations in the Eagle Ford Shale of South Texas, including the leasing of additional acreage and the drilling of two horizontal wells in the Eagle Ford Shale formation.

•

Approximately $950,000 for other projects including Cinco Terry.

•

Because of the volatility of commodity prices and the risks involved in our industry, we believe in remaining flexible in our capital budgeting process. When appropriate, we may defer existing capital projects to seize an attractive acquisition opportunity or reallocate capital towards projects where we believe we can generate higher rates of return on capital employed. We also believe in maintaining a strong balance sheet and using commodity hedging. This allows us to be more opportunistic in lower commodity price environments as well as providing more consistent financial results in the long-term.

Marketing and Pricing

We derive revenue principally from the sale of oil and natural gas. As a result, our revenues are determined, to a large degree, by prevailing prices for crude oil and natural gas. We sell our oil and natural gas on the open market at prevailing market prices. The market price for oil and natural gas is dictated by supply and demand, and we cannot accurately predict or control the price we may receive for our oil and natural gas.

We use commodity price hedging instruments to reduce our exposure to oil and natural gas price fluctuations and to help ensure that we have adequate cash flow to fund our debt service costs and capital programs. From time to time, we may enter into futures contracts, collars and basis swap agreements, as well as fixed price physical delivery contracts; however, it is our preference to utilize hedging strategies that provide downside commodity price protection without unduly limiting our revenue potential in an environment of rising commodity prices. We use hedging primarily to manage price risks and returns on certain acquisitions and drilling programs. Our policy is to consider hedging an appropriate portion of our production at commodity prices we deem attractive. In addition, we are required by our lenders to hedge a significant portion of production through calendar year 2012.

Our revenues, cash flows, profitability and future rate of growth depend substantially upon prevailing prices for oil and natural gas. Prices also affect the amount of cash flow available for capital expenditures and our ability to borrow money or raise additional capital. Lower prices may also adversely affect the value of our reserves and make it uneconomical for us to commence or continue production levels of natural gas and crude oil. Historically, the prices received for oil and natural gas have fluctuated widely. Among the factors that can cause these fluctuations are:

	•		changes in global supply and demand for oil and natural gas;
	•		the actions of the Organization of Petroleum Exporting Countries, or OPEC;
	•		the price and quantity of imports of foreign oil and natural gas;
	•		acts of war or terrorism;
	•		political conditions and events, including embargoes, affecting oil-producing activity;
	•		the level of global oil and natural gas exploration and production activity;
	•		the level of global oil and natural gas inventories;
	•		weather conditions;
	•		technological advances affecting energy consumption; and
	•		the price and availability of alternative fuels.

From time to time, we enter into hedging arrangements to reduce our exposure to decreases in the prices of oil and natural gas. Hedging arrangements may expose us to risk of significant financial loss in some circumstances including circumstances where:

	•		our production and/or sales of natural gas are less than expected;
	•		payments owed under derivative hedging contracts come due prior to receipt of the hedged month’s production revenue; or
	•		the counter party to the hedging contract defaults on its contract obligations.

In addition, hedging arrangements limit the benefit we would receive from increases in the prices for oil and natural gas. We cannot assure you that any hedging transactions we may enter into will adequately protect us from a decline in the price of oil and natural gas. On the other hand, should we choose not to engage in hedging transactions in the future (assuming we are permitted by our lenders to do so), we may be more adversely affected by changes in oil and natural gas prices than our competitors who engage in hedging transactions.

As of December 31, 2009, we had the following hedges in place:

		4Q09				1Q10				2Q10				3Q10				4Q10				2010				2011				2012
Natural Gas Hedges
Floors
Volume (MMbtu/d)			652				N/A				N/A				N/A				N/A				N/A				N/A				N/A
Price per MCF		$	7.75				N/A				N/A				N/A				N/A				N/A				N/A				N/A
Collars
Volume (MMbtu/d)			N/A				667				659				652				652				658				548				329
Floor Price per MCF			N/A			$	5.69			$	5.69			$	5.69			$	5.69			$	5.69			$	5.00			$	5.00
Ceiling Price per MCF			N/A			$	7.26			$	7.26			$	7.26			$	7.26			$	7.26			$	8.39			$	9.82
Total Gas Volume Hedged			60,000				60,000				60,000				60,000				60,000				240,000				199,980				120,000
Total PDP			141,504				73,887				74,708				75,529				75,529				299,653				249,230				217,343
Total % Natural Gas Volume Hedged			42	%			81	%			80	%			79	%			79	%			80	%			80	%			55	%
Oil Hedges
Floors
Volume (Bbls/d)			33				N/A				N/A				N/A				N/A				N/A				N/A				N/A
Price per bbl		$	110.00				N/A				N/A				N/A				N/A				N/A				N/A				N/A
Swaps
Volume (Bbls/d)			170				213				187				185				185				192				162				N/A
Price per bbl		$	87.43			$	88.84			$	102.64			$	102.64			$	102.64			$	99.19			$	103.67				N/A
Collars
Volume (MMbtu/d)			N/A				N/A				N/A				N/A				N/A				N/A				N/A				137
Floor Price per MCF			N/A				N/A				N/A				N/A				N/A				N/A				N/A			$	80.00
Ceiling Price per MCF			N/A				N/A				N/A				N/A				N/A				N/A				N/A			$	100.00
Total Oil Volume Hedged			18,367				19,160				17,010				17,010				17,010				70,226				59,225				50,000
Total PDP			47,336				27,893				28,203				28,513				28,513				113,123				98,692				86,489
Total % Oil Volume Hedged			39	%			69	%			60	%			60	%			60	%			62	%			60	%			58	%

Competition

The oil and natural gas industry is highly competitive in all phases. We encounter competition from other oil and natural gas companies in all areas of operation, including the acquisition of leases. Our competitors include numerous independent oil and natural gas companies and individuals. Many of our competitors are large, well established companies that have substantially larger operating staffs and greater capital resources than we do. Our ability to acquire additional properties in the future will depend upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. See “Item 1A. Risk Factors — Competition in the oil and natural gas industry is intense, which may adversely affect our ability to compete.”

Operating Hazards and Risks

Drilling activities are subject to many risks, including the risk that no commercially productive reservoirs will be encountered. There can be no assurance that the new wells we drill will be productive or that we will recover all or any portion of our investment. Drilling for oil and natural gas may involve unprofitable efforts, not only from dry wells, but also from wells that are productive, but do not produce sufficient net revenues to return a profit after drilling, operating and other costs. The cost and timing of drilling, completing and operating wells is often uncertain. Our drilling operations may be curtailed, delayed or canceled as a result of numerous factors, many of which are beyond our control, including low oil and natural gas prices, title problems, weather conditions, delays by project participants, compliance with governmental requirements, shortages or delays in the delivery of equipment and services and increases in the cost for such equipment and services. Our future drilling activities may not be successful and, if unsuccessful, such failure may have a material adverse effect on our business, financial condition, results of operations and cash flows.

Our operations are subject to hazards and risks inherent in drilling for and producing and transporting oil and natural gas, such as fires, natural disasters, explosions, encountering formations with abnormal pressures, blowouts, craterings, pipeline ruptures and spills, any of which can result in the loss of hydrocarbons, environmental pollution, personal injury claims and other damage to our properties and those of others. We maintain insurance against some but not all of the risks described above. In particular, the insurance we maintain does not cover claims relating to failure of title to oil and natural gas leases, loss of surface equipment at well locations, business interruption, loss of revenue due to low commodity prices or loss of revenues due to well failure. Furthermore, in certain circumstances where such insurance is available, we may determine not to purchase it due to cost or other factors. The occurrence of an event that is not covered by, or not fully covered by insurance could have a material adverse effect on our business, financial condition, results of operations and cash flows in the period such event may occur.

Governmental Regulation

Our oil and natural gas exploration activities are subject to extensive laws, rules and regulations promulgated by federal and state legislatures and agencies. Failure to comply with such laws, rules and regulations can result in substantial penalties, including the delay or stopping of our operations. The legislative and regulatory burden on the oil and natural gas industry increases our cost of doing business and affects our profitability. See “Item 1A. Risk Factors — Our operations expose us to substantial costs and liabilities with respect to environmental matters.”

The commercial risk associated with the production of fossil fuels lies in the uncertainty of government-imposed climate change legislation, including cap and trade schemes, and regulations that may affect us, our suppliers, and our customers. The cost of meeting these requirements may have an adverse impact on our financial condition, results of operations and cash flows, and could reduce the demand for our products.

Climate Change

Climate change has become the subject of an important public policy debate. Climate change remains a complex issue, with some scientific research suggesting that an increase in greenhouse gas emissions (GHGs) may pose a risk to society and the environment. The oil and natural gas exploration and production industry is a source of certain GHGs, namely carbon dioxide and methane, and future restrictions on the combustion of fossil fuels or the venting of natural gas could have a significant impact on our future operations. See “Item 1A. Risk Factors — Climate change legislation or regulations restricting emissions of “greenhouse gases” could result in increased operating costs and reduced demand for the oil, natural gas and NGLs that we produce.”

Formation

We were incorporated in the State of Delaware on June 4, 1997.

Employees

At December 31, 2009, we had 18 full-time employees of which 9 were officers. None of our employees are represented by a union. Management considers our relations with employees to be very good. Subsequent to the closing of the acquisition of Triad, we had 139 full-time employees, of which 10 were officers.

Facilities

As of December 31, 2009, our principal executive offices are located in Houston, Texas, where we lease approximately 7,678 square feet of office space at 777 Post Oak Blvd., Suite 910, Houston, Texas 77056, under a lease whereby approximately 6,000 and 1,600 square feet expire in May of 2012 and December of 2013, respectively. We have also inherited, through the acquisition of Sharon Resources, Inc., approximately 6,031 square feet of office space located at 675 Bering, Suite 650, Houston, Texas 77057 under a lease that expires in February of 2012 which we are actively marketing to sub-lease candidates. In connection with the acquisition of Triad in February 2010, we acquired 7,608 square feet of leased office space in Marietta, Ohio as well as field offices in Kentucky and West Virginia.

Website Access

We make available, free of charge through our website, www.MagnumHunterResources.com, our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and all amendments to those reports as soon as reasonably practicable after such material is electronically filed with the Securities and Exchange Commission. Information on our website is not a part of this report.

Item 1A. RISK FACTORS

In evaluating our company, the factors described below should be considered carefully. The occurrence of one or more of these events could significantly and adversely affect our business, prospects, financial condition, results of operations and cash flows.

Risks Related to Our Business

Future economic conditions in the U.S. and global markets may have a material adverse impact on our business and financial condition that we currently cannot predict.

The U.S. and other world economies are slowly recovering from a recession which began in 2008 and has extended into 2009 and 2010. While economic growth has resumed, it remains modest and the timing of an economic recovery is uncertain. There are likely to be significant long-term effects resulting from the recession and credit market crisis, including a future global economic growth rate that is slower than what was experienced in recent years. Unemployment rates remain very high and businesses and consumer confidence levels have not yet fully recovered to pre-recession levels. In addition, more volatility may occur before a sustainable, yet lower, growth rate is achieved. Global economic growth drives demand for energy from all sources, including for oil and natural gas. A lower future economic growth rate will result in decreased demand for our crude oil and natural gas production as well as lower commodity prices, which will reduce our cash flows from operations and our profitability.

Volatility in oil and natural gas prices may adversely affect our business, financial condition or results of operations and our ability to meet our capital expenditure obligations and financial commitments.

The prices we receive for our oil and natural gas production heavily influence our revenue, profitability, access to capital and future rate of growth. Oil and natural gas are commodities, and therefore their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil and natural gas have been extremely volatile. These markets will likely continue to be volatile in the future. The prices we receive for our production, and the levels of our production, depend on numerous factors beyond our control. These factors include, but are not limited to, the following:

	•		the current uncertainty in the global economy;
	•		changes in global supply and demand for oil and natural gas;
	•		the condition of the U.S. and global economy;
	•		the actions of certain foreign countries;
	•		the price and quantity of imports of foreign oil and natural gas (LNG);
	•		political conditions, including embargoes, war or civil unrest in or affecting other oil producing activities of certain countries;
	•		the level of global oil and natural gas exploration and production activity;
	•		the level of global oil and natural gas inventories;
	•		production or pricing decisions made by the Organization of Petroleum Exporting Countries (“OPEC”);
	•		weather conditions;
	•		technological advances affecting energy consumption; and
	•		the price and availability of alternative fuels.

Lower oil and natural gas prices may not only decrease our revenues on a per unit basis, but also may reduce the amount of oil and natural gas that we can produce economically. The higher operating costs associated with many of our oil fields will make our profitability more sensitive to oil price declines. A sustained decline in oil or natural gas prices may materially and adversely affect our future business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures.

We have limited experience in drilling wells to the Eagle Ford Shale, Marcellus Shale, and Bakken Shale and limited information regarding reserves and decline rates in the Eagle Ford Shale, Marcellus Shale and Bakken Shale. Wells drilled to the Eagle Ford Shale, Marcellus Shale and Bakken Shale are more expensive and more susceptible to mechanical problems in drilling and completion techniques than wells in the other conventional areas.

We have limited experience in the drilling and completion of Eagle Ford Shale, Marcellus Shale and Bakken Shale wells. As of December 31, 2009, the management members who joined the Company via the Triad acquisition have drilled 33 gross vertical wells and 30 net vertical wells to the Marcellus Shale. We have limited horizontal drilling and completion experience in the Eagle Ford Shale and Bakken Shale. Other operators in the Eagle Ford, Marcellus Shale and Bakken Shale plays may have significantly more experience in the drilling and completion of these wells, including the drilling and completion of horizontal wells. In addition, we have limited information with respect to the ultimate recoverable reserves and production decline rates. The wells drilled in the Eagle Ford Shale, Marcellus Shale and Bakken Shale are primarily horizontal and require more stimulation, which makes them more expensive to drill and complete. The wells will also be more susceptible to mechanical problems associated with the drilling and completion of the wells, such as casing collapse and lost equipment in the wellbore due to the length of the lateral portions of these unconventional wells. The fracturing of these shale formations will be more extensive and complicated than fracturing other geological formations in our other areas of operation.

If our access to oil and gas markets is restricted, it could negatively impact our production, our income and ultimately our ability to retain our leases. Our ability to sell natural gas and/or receive market prices for our natural gas may be adversely affected by pipeline and gathering system capacity constraints.

Market conditions or the restriction in the availability of satisfactory oil and natural gas transportation arrangements may hinder our access to oil and natural gas markets or delay our production. The availability of a ready market for our oil and natural gas production depends on a number of factors, including the demand for and supply of oil and natural gas and the proximity of reserves to pipelines and terminal facilities. Our ability to market our production depends in substantial part on the availability and capacity of gathering systems, pipelines and processing facilities owned and operated by third parties. Our failure to obtain such services on acceptable terms could materially harm our business. Our productive properties may be located in areas with limited or no access to pipelines, thereby necessitating delivery by other means, such as trucking, or requiring compression facilities. Such restrictions on our ability to sell our oil or natural gas may have several adverse effects, including higher transportation costs, fewer potential purchasers (thereby potentially resulting in a lower selling price) or, in the event we were unable to market and sustain production from a particular lease for an extended time, possibly causing us to lose a lease due to lack of production.

If drilling in the Eagle Ford Shale, Marcellus Shale and Bakken Shale areas proves to be successful, the amount of oil and natural gas being produced by us and others could exceed the capacity of the various gathering and intrastate or interstate transportation pipelines currently available in these areas. If this occurs, it will be necessary for new pipelines and gathering systems to be built. Because of the current economic climate, certain pipeline projects that are planned for the Eagle Ford Shale, Marcellus Shale and Bakken Shale areas may not occur for lack of financing. In addition, capital constraints could limit our ability to build intrastate gathering systems necessary to transport our gas to interstate pipelines. In such event, we might have to shut in our wells awaiting a pipeline connection or capacity and/or sell natural gas production at significantly lower prices than those quoted on NYMEX or than we currently project for these specific regions, which would adversely affect our results of operations.

A portion of our natural gas and oil production in any region may be interrupted, or shut in, from time to time for numerous reasons, including as a result of weather conditions, accidents, loss of pipeline or gathering system access, field labor issues or strikes, or we might voluntarily curtail production in response to market conditions. If a substantial amount of our production is interrupted at the same time, it could temporarily adversely affect our cash flow.

Certain federal income tax deductions currently available with respect to oil and natural gas exploration and development may be eliminated as a result of future legislation.

Among the changes contained in President Obama’s 2011 budget proposal released by the White House on February 1, 2010, is the elimination of certain key U.S. federal income tax preferences currently available to oil and gas exploration and production companies. Such changes include, but are not limited to:

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the repeal of the percentage depletion allowance for oil and gas properties;

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the elimination of current deductions for intangible drilling and development costs;

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the elimination of the deduction for certain U.S. production activities; and

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an extension of the amortization period for certain geological and geophysical expenditures. It is unclear, however, whether any such changes will be enacted or how soon such changes could be effective.

The passage of any legislation as a result of the budget proposal, the Senate bill, or any other similar change in U.S. federal income tax law could eliminate certain tax deductions that are currently available with respect to oil and gas exploration and development, and any such change could negatively affect our financial condition and results of operations.

We depend on a relatively small number of purchasers for a substantial portion of our revenue. The inability of one or more of our purchasers to meet their obligations may adversely affect our financial results.

We derive a significant amount of our revenue from a relatively small number of purchasers. Our inability to continue to provide services to key customers, if not offset by additional sales to our other customers, could adversely affect our financial condition and results of operations. These companies may not provide the same level of our revenue in the future for a variety of reasons, including their lack of funding, a strategic shift on their part in moving to different geographic areas in which we do not operate or our failure to meet their performance criteria. The loss of all or a significant part of this revenue would adversely affect our financial condition and results of operations.

Our results of operations and cash flow may be adversely affected by risks associated with our oil and gas financial derivative activities, and our oil and gas financial derivative activities may limit potential gains.

We have entered into, and we expect to enter into in the future, oil and gas financial derivative arrangements corresponding to a significant portion of our oil and natural gas production. Many derivative instruments that we employ require us to make cash payments to the extent the applicable index exceeds a predetermined price, thereby limiting our ability to realize the benefit of increases in oil and natural gas prices. During the twelve months ended December 31, 2009, we incurred realized gains of $5.4 million from our financial derivatives. Please read “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

If our actual production and sales for any period are less than the corresponding volume of derivative contracts for that period (including reductions in production due to operational delays), or if we are unable to perform our activities as planned, we might be forced to satisfy all or a portion of our derivative obligations without the benefit of the cash flow from our sale of the underlying physical commodity, resulting in a substantial diminution of our liquidity. In addition, our oil and gas financial derivative activities can result in substantial losses. Such losses could occur under various circumstances, including any circumstance in which a counterparty does not perform its obligations under the applicable derivative arrangement, the arrangement is imperfect or our derivative policies and procedures are not followed or do not work as planned. Under the terms of our senior credit facility with Bank of Montreal, the percentage of our total production volumes with respect to which we will be allowed to enter into derivative contracts is limited, and we therefore retain the risk of a price decrease for our remaining production volume.

If oil and natural gas prices decline, we may be required to take additional write-downs of the carrying values of our oil and natural gas properties, potentially triggering earlier-than-anticipated repayments of any outstanding debt obligations and negatively impacting the trading value of our securities.

There is a risk that we will be required to write down the carrying value of our oil and gas properties, which would reduce our earnings and stockholders’ equity. We account for our natural gas and crude oil exploration and development activities using the successful efforts method of accounting. Under this method, costs of productive exploratory wells, developmental dry holes and productive wells and undeveloped leases are capitalized. Oil and gas lease acquisition costs are also capitalized. Exploration costs, including personnel costs, certain geological and geophysical expenses and delay rentals for oil and gas leases are charged to expense as incurred. Exploratory drilling costs are initially capitalized, but charged to expense if and when the well is determined not to have found reserves in commercial quantities. The capitalized costs of our oil and gas properties may not exceed the estimated future net cash flows from our properties. If capitalized costs exceed future cash flows, we write down the costs of the properties to our estimate of fair market value. Any such charge will not affect our cash flow from operating activities, but will reduce our earnings and stockholders’ equity.

Additional write downs could occur if oil and gas prices decline or if we have substantial downward adjustments to our estimated proved reserves, increases in our estimates of development costs or deterioration in our drilling results. Because our properties currently serve, and will likely continue to serve, as collateral for advances under our existing and future credit facilities, a write-down in the carrying values of our properties could require us to repay debt earlier than we would otherwise be required. It is likely that the cumulative effect of a write-down could also negatively impact the value of our securities, including our common stock.

The application of the successful efforts method of accounting requires managerial judgment to determine the proper classification of wells designated as developmental or exploratory, which will ultimately determine the proper accounting treatment of the costs incurred. The results from a drilling operation can take considerable time to analyze and the determination that commercial reserves have been discovered requires both judgment and industry experience. Wells may be completed that are assumed to be productive but may actually deliver oil and gas in quantities insufficient to be economic, which may result in the abandonment of the wells at a later date. Wells are drilled that have targeted geologic structures that are both developmental and exploratory in nature, and an allocation of costs is required to properly account for the results. The evaluation of oil and gas leasehold acquisition costs requires judgment to estimate the fair value of these costs with reference to drilling activity in a given area.

We review our oil and gas properties for impairment annually or whenever events and circumstances indicate a decline in the recoverability of their carrying value. Once incurred, a write down of oil and gas properties is not reversible at a later date even if gas or oil prices increase. Given the complexities associated with oil and gas reserve estimates and the history of price volatility in the oil and gas markets, events may arise that would require us to record an impairment of the book values associated with oil and gas properties.

Drilling for and producing oil and natural gas are high risk activities with many uncertainties that could adversely affect our business, financial condition and results of operations.

Our future success will depend on the success of our exploitation, exploration, development and production activities. Our oil and natural gas exploration and production activities are subject to numerous risks beyond our control, including the risk that drilling will not result in commercially viable oil or natural gas production. Our decisions to purchase, explore, develop or otherwise exploit prospects or properties will depend in part on the evaluation of data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations. Please read “Item 1A. Our estimated reserves are based on many assumptions that may turn out to be inaccurate. Any significant inaccuracies in these reserve estimates or underlying assumptions may materially affect the quantities and present value of our reserves” below for a discussion of the uncertainties involved in these processes. Our costs of drilling, completing and operating wells are often uncertain before drilling commences. Overruns in budgeted expenditures are common risks that can make a particular project uneconomical. Further, our future business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures could be materially and adversely affected by any factor that may curtail, delay or cancel drilling, including the following:

	•		delays imposed by or resulting from compliance with regulatory requirements;
	•		unusual or unexpected geological formations;
	•		pressure or irregularities in geological formations;
	•		shortages of or delays in obtaining equipment and qualified personnel;
	•		equipment malfunctions, failures or accidents;
	•		unexpected operational events and drilling conditions;
	•		pipe or cement failures;
	•		casing collapses;
	•		lost or damaged oilfield drilling and service tools;
	•		loss of drilling fluid circulation;
	•		uncontrollable flows of oil, natural gas and fluids;
	•		fires and natural disasters;
	•		environmental hazards, such as natural gas leaks, oil spills, pipeline ruptures and discharges of toxic gases;
	•		adverse weather conditions;
	•		reductions in oil and natural gas prices;
	•		oil and natural gas property title problems; and
	•		market limitations for oil and natural gas.

If any of these factors were to occur with respect to a particular field, we could lose all or a part of our investment in the field, or we could fail to realize the expected benefits from the field, either of which could materially and adversely affect our revenue and profitability.

Our proved reserves and related PV-10 as of December 31, 2009 have been reported under new SEC rules that went into effect on January 1, 2010. The estimates provided in accordance with the new SEC rules may change materially as a result of interpretive guidance that may be subsequently released by the SEC.

We have included in this report certain estimates of our proved reserves and related PV-10 at December 31, 2009 as prepared consistent with our independent reserve engineers’ interpretations of the new SEC rules relating to disclosures of estimated natural gas and oil reserves. These new rules are effective for fiscal years ending on or after December 31, 2009. These newly adopted rules will require SEC reporting companies to prepare their reserve estimates using revised reserve definitions and revised pricing based on 12-month unweighted first-day-of-the-month average pricing. The SEC has not specifically reviewed our reserve estimates under the new rules and has released only limited interpretive guidance regarding reporting of reserve estimates under the new rules. Accordingly, while the estimates of our proved reserves and related PV-10 at December 31, 2009 included in this report have been prepared based on what we and our independent reserve engineers believe to be reasonable interpretations of the new SEC rules, those estimates could ultimately differ materially from any estimates we might prepare applying more specific SEC interpretive guidance.

We may be limited in our ability to book additional proved undeveloped reserves under the new SEC rules.

Another impact of the new SEC reserve rules is a general requirement that, subject to limited exceptions, proved undeveloped reserves may only be booked if they relate to wells scheduled to be drilled within five years of the date of booking. This new rule may limit our potential to book additional proved undeveloped reserves as we pursue our drilling program on our undeveloped properties.

Our estimated reserves are based on many assumptions that may turn out to be inaccurate. Any significant inaccuracies in these reserve estimates or underlying assumptions may materially affect the quantities and present value of our reserves.

Estimates of oil and natural gas reserves are inherently imprecise. The process of estimating oil and natural gas reserves is complex. It requires interpretations of available technical data and many assumptions, including assumptions relating to economic factors. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present value of reserves. To prepare our estimates, we must project production rates and the timing of development expenditures. We must also analyze available geological, geophysical, production and engineering data. The extent, quality and reliability of this data can vary. The process also requires economic assumptions about matters such as oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds for capital expenditures.

Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves most likely will vary from our estimates. Any significant variance could materially affect the estimated quantities and present value of reserves shown in this report. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development activities, prevailing oil and natural gas prices and other factors, many of which are beyond our control.

The present value of future net cash flows from our proved reserves is not necessarily the same as the current market value of our estimated oil and natural gas reserves. We base the estimated discounted future net cash flows from our proved reserves on prices and costs in effect on the day of estimate. However, actual future net cash flows from our oil and natural gas properties also will be affected by factors such as:

	•		actual prices we receive for oil and natural gas;
	•		actual cost of development and production expenditures;
	•		the amount and timing of actual production;
	•		supply of and demand for oil and natural gas; and
	•		changes in governmental regulations or taxation.

The timing of both our production and our incurrence of expenses in connection with the development and production of oil and natural gas properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general.

Prospects that we decide to drill may not yield oil or natural gas in commercially viable quantities.

Our prospects are in various stages of evaluation. There is no way to predict with certainty in advance of drilling and testing whether any particular prospect will yield oil or natural gas in sufficient quantities to recover drilling or completion costs or to be economically viable, particularly in light of the current economic environment. The use of seismic data and other technologies, and the study of producing fields in the same area, will not enable us to know conclusively before drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in commercially viable quantities. Moreover, the analogies we draw from available data from other wells, more fully explored prospects or producing fields may not be applicable to our drilling prospects.

We cannot control activities on properties that we do not operate and are unable to control their proper operation and profitability.

We do not operate all of the properties in which we own an ownership interest. As a result, we have limited ability to exercise influence over, and control the risks associated with, the operations of these non-operated properties. The failure of an operator of our wells to adequately perform operations, an operator’s breach of the applicable agreements or an operator’s failure to act in ways that are in our best interests could reduce our production, revenues and reserves. The success and timing of our drilling and development activities on properties operated by others therefore depend upon a number of factors outside of our control, including the operator’s:

	•		nature and timing of drilling and operational activities;
	•		timing and amount of capital expenditures;
	•		expertise and financial resources;
	•		the approval of other participants in drilling wells; and
	•		selection of suitable technology.

Unless we replace our oil and natural gas reserves, our reserves and production will decline, which would adversely affect our business, financial condition and results of operations.

Producing oil and natural gas reservoirs generally are characterized by declining production rates that vary depending on reservoir characteristics and other factors. Our future oil and natural gas reserves and production, and therefore our cash flow and income, are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves. We may not be able to develop, find or acquire additional reserves to replace our current and future production at acceptable costs, which would adversely affect our business, financial condition and results of operations.

Our future acquisitions may yield revenue or production that varies significantly from our projections.

In acquiring producing properties, we will assess the recoverable reserves, future natural gas and oil prices, operating costs, potential liabilities and other factors relating to the properties. Our assessments are necessarily inexact, and their accuracy is inherently uncertain. Our review of a subject property in connection with our acquisition assessment will not reveal all existing or potential problems or permit us to become sufficiently familiar with the property to assess fully its deficiencies and capabilities. We may not inspect every well, and we may not be able to observe structural and environmental problems even when we do inspect a well or retain a third-party consultant. If problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of those problems. Any acquisition of property interests may not be economically successful, and unsuccessful acquisitions may have a material adverse effect on our financial condition and future results of operations.

Our development and exploration operations require substantial capital, and we may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a loss of properties and a decline in our oil and natural gas reserves.

The oil and natural gas industry is capital intensive. We make and expect to continue to make substantial capital expenditures in our business and operations for the exploration for, and development, production and acquisition of, oil and natural gas reserves. To date, we have financed capital expenditures primarily with proceeds from bank borrowings, cash generated by operations and preferred and common stock equity offerings. We intend to finance our capital expenditures with the sale of equity, asset sales, cash flow from operations and current and new financing arrangements with our banks. Our cash flow from operations and access to capital is subject to a number of variables, including:

	•		our proved reserves;
	•		the amount of oil and natural gas we are able to produce from existing wells;
	•		the prices at which oil and natural gas are sold; and
	•		our ability to acquire, locate and produce new reserves.

If our revenues decrease as a result of lower oil and natural gas prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels. We may need to seek additional financing in the future. In addition, we may not be able to obtain debt or equity financing on terms favorable to us, or at all, depending on market conditions. The failure to obtain additional financing could result in a curtailment of our operations relating to exploration and development of our prospects, which in turn could lead to a possible loss of properties and a decline in our oil and natural gas reserves. Also, our credit facility contains covenants that restrict our ability to, among other things, materially change our business, approve and distribute dividends, enter into certain transactions with affiliates, create or acquire additional subsidiaries, incur indebtedness, sell assets, make loans to others, make investments, enter into mergers, incur liens, and enter into agreements regarding swap and other derivative transactions.

Restrictive covenants in our senior credit facility may restrict our ability to pursue our business strategies.

The Restated Credit Agreement with our lenders contains certain negative covenants that among other things, restrict our ability to, with certain exceptions:

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incur indebtedness;

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grant liens;

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make certain payments;

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change the nature of our business;

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dispose of all or substantially all of our assets or enter into mergers, consolidations or similar transactions;

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make investments, loans or advances;

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pay cash dividends, unless certain conditions are met and are subject to a “basket” of $2.5 million per year available for payment of dividends on preferred stock; and

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enter into transactions with affiliates.

The Restated Credit Agreement with our lenders also requires the Company to satisfy certain affirmative financial covenants, including maintaining:

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an EBITDAX to interest ratio of not less than 2.5 to 1.0;

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a debt to EBITDAX ratio of not more than (a) 4.5 to 1.0 for the fiscal quarters ending March 31, 2010, June 30, 2010, and September 30, 2010, and (b) 4.0 to 1.0 for each fiscal quarter ending thereafter; and

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a ratio of consolidated current assets to consolidated current liability of not less than 1.0 to 1.0. We are also required to enter into certain commodity price hedging agreements pursuant to the terms of the credit facilities.

Our ability to comply with these covenants may be affected by events beyond our control, and any material deviations from our forecasts could require us to seek waivers or amendments of covenants, alternative sources of financing or reductions in expenditures. We cannot assure you that such waivers, amendments or alternative financings could be obtained or, if obtained, would be on terms acceptable to us.

Our substantial indebtedness could adversely affect our financial condition and our ability to operate our business.

As of March 29, 2010 our outstanding indebtedness was approximately $64 million. Our substantial debt could have important adverse consequences for holders of our common stock, including the following:

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it may be difficult for us to satisfy our obligations, including debt service requirements under our credit agreements;

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our ability to obtain additional financing for working capital, capital expenditures, debt service requirements, and other general corporate purposes may be impaired;

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a significant portion of our cash flow is committed to payments on our debt, which will reduce the funds available to us for other purposes, such as future capital expenditures;

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we are more vulnerable to price fluctuations and to economic downturns and adverse industry conditions and our flexibility to plan for, or react to, changes in our business or industry is more limited;

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our ability to capitalize on business opportunities, and to react to competitive pressures, as compared to others in our industry, may be limited

Our obligations under our Senior Credit Facility are secured by substantially all of our assets, and any failure to meet our debt obligations would adversely affect our business and financial condition.

PRC Williston LLC, our majority-owned subsidiary, Sharon Resources, Inc. and Triad Hunter, LLC, our wholly-owned subsidiaries, and our indirect wholly-owned subsidiary, Eureka Hunter Pipeline, LLC, have each guaranteed the performance of all of our obligations under the Senior Credit Facility, and we have collateralized our obligations under the Senior Credit Facility through our grant of a first priority security interest in our ownership interest in PRC Williston, LLC, Sharon Resources, Inc., Triad Hunter LLC, Eureka Hunter Pipeline, LLC and substantially all of our oil and gas properties, subject only to certain permitted liens.

Our ability to meet debt obligations under the Senior Credit Facility will depend on the future performance of our properties, which will be affected by financial, business, economic, regulatory and other factors, many of which we are unable to control. Our failure to service this debt could result in a default under the credit facilities, which could result in the loss of our ownership interest in PRC Williston, LLC, Sharon Resources, Inc., Triad Hunter LLC, Eureka Hunter Pipeline LLC and our oil and gas assets and otherwise materially adversely affect our business, financial condition and results of operations.

The unavailability or high cost of drilling rigs, equipment, supplies, personnel and oil field services could adversely affect our ability to execute on a timely basis our exploration and development plans within our budget.

We may, from time to time, encounter difficulty in obtaining, or an increase in the cost of securing, drilling rigs, equipment and supplies. In addition, larger producers may be more likely to secure access to such equipment by offering more lucrative terms. If we are unable to acquire access to such resources, or can obtain access only at higher prices, our ability to convert our reserves into cash flow could be delayed and the cost of producing those reserves could increase significantly, which would adversely affect our financial condition and results of operations.

We depend on pipelines owned by others to transport and sell our natural gas production. Disruption of, capacity constraints in, or proximity to pipeline systems could limit sales of our natural gas.

In many instances, we transport our natural gas to market by utilizing pipelines owned by others. If pipelines do not exist near our producing wells, if pipeline capacity is limited or if pipeline capacity is unexpectedly curtailed or disrupted, we may have to reduce sales of our production of gas because we do not have facilities to store excess inventory. If this occurs, our revenues will be reduced, and our unit costs will also increase. In addition, if pipeline gas quality requirements change for a pipeline, we might be required to install additional processing equipment, which could increase our costs. If this should occur, the pipeline could curtail our gas flows until the gas delivered to their pipeline is in compliance.

New technologies may cause our current exploration and drilling methods to become obsolete.

The oil and gas industry is subject to rapid and significant advancements in technology, including the introduction of new products and services using new technologies. As competitors use or develop new technologies, we may be placed at a competitive disadvantage, and competitive pressures may force us to implement new technologies at a substantial cost. In addition, competitors may have greater financial, technical and personnel resources that allow them to enjoy technological advantages and may in the future allow them to implement new technologies before we can. One or more of the technologies that we currently use or that we may implement in the future may become obsolete. We cannot be certain that we will be able to implement technologies on a timely basis or at a cost that is acceptable to us. If we are unable to maintain technological advancements consistent with industry standards, our operations and financial condition may be adversely affected.

We may incur substantial losses and be subject to substantial liability claims as a result of our oil and natural gas operations, and we may not have enough insurance to cover all of the risks that we may ultimately face.

We maintain insurance coverage against some, but not all, potential losses to protect against the risks we foresee. We do not carry business interruption insurance. We may elect not to carry certain types or amounts of insurance if our management believes that the cost of available insurance is excessive relative to the risks presented. In addition, it is not possible to insure fully against pollution and environmental risks.

We are not insured against all risks. Losses and liabilities arising from uninsured and underinsured events could materially and adversely affect our business, financial condition and results of operations. Our oil and natural gas exploration and production activities are subject to all of the operating risks associated with drilling for and producing oil and natural gas, including the possibility of:

	•		environmental hazards, such as uncontrollable flows of oil, natural gas, brine, well fluids, toxic gas or other pollution into the environment, including groundwater and shoreline contamination;
	•		abnormally pressured formations;
	•		mechanical difficulties, such as stuck oil field drilling and service tools and casing collapses;
	•		fires and explosions;
	•		personal injuries and death; and
	•		natural disasters.

Any of these risks could adversely affect our ability to conduct operations or result in substantial losses to us. If a significant accident or other event occurs and is not fully covered by insurance, then that accident or other event could adversely affect our financial condition, results of operations and cash flows.

We have completed several recent acquisitions, and there is no assurance that we will be able to satisfy our contractual and financial obligations thereunder.

In mid-2009 we acquired Sharon Resources, Inc. in a stock acquisition and increased our ownership interest in the East Chalkley field in Louisiana. More significantly, in February 2010, we closed the Triad acquisition and in doing so incurred certain significant contractual and financial obligations, including our commitments under the Senior Credit Facility and with respect to the Series B Preferred Stock issued to Triad and the 10.25% Series C Cumulative Perpetual Preferred Stock that represented a portion of the acquisition financing, and other contractual obligations with respect to the ongoing operations of Triad.

Although we have consummated the Triad transaction, there is no assurance we will be able to have sufficient equity capital or borrowing capacity to operate the acquired assets post-closing. There is also no assurance that we can successfully assimilate Triad’s properties, operations and personnel into our organization.

We do not have a significant operating history and, as a result, there is a limited amount of information about us on which to make an investment decision.

In July 2005, we acquired our initial exploratory drilling prospects, and in November 2005 we commenced drilling activities. In December 2005, we commenced production from our first oil and gas prospects, and in February 2006 we received our first revenues from oil and gas production. In February 2007 we acquired a 43% average working interest in 15 producing oil fields and approximately 150 producing wells located in the Williston Basin in North Dakota at which point we began to receive revenue from associated oil and gas production. Since that time, we have expanded secondary recovery operations in the Williston Basin properties in anticipation of drilling additional producing wells in the future. Beginning in 2007 to present, we have actively participated with Approach Resources Corporation in the drilling of approximately 100 wells located in Crockett County, Texas. Beginning in the last quarter 2008, we participated with Goodrich Petroleum Corporation in five successful wells located in Nacogdoches County, Texas. On September 30, 2009, we acquired Sharon Resources, Inc., a wholly-owned subsidiary of Calgary based Sharon Energy Ltd., bringing an inventory of drilling projects in addition to three exploration and evaluation professionals. In addition, on September 14, 2009, we entered into a Purchase and Sale Agreement with Centurion to acquire for $1.7 million all of Centurion’s ownership interest in the East Chalkley Unit in Cameron Parish, Louisiana. This property acquisition was completed on October 15, 2009 and is operated by our Company. Our Triad acquisition recently closed on February 12, 2010, and as a result, there is limited information upon which to assess our ability to operate successfully the acquired assets. Accordingly, there is little operating history upon which to judge our business strategy, our management team or our current operations.

We have a history of losses and cannot assure you that we will be profitable in the foreseeable future.

Since we entered the oil and gas business in April 2005, through December 31, 2009, we have incurred a cumulative net loss from operations of $27.3 million. If we fail to generate profits from our operations, we will not be able to sustain our business. We may never report profitable operations or generate sufficient revenue to maintain our company as a going concern.

The acquisition and integration of the Triad operating interests and other assets may divert management from other important business activities. This diversion, together with other difficulties in integrating Triad’s business and properties, may have a material adverse effect on our business, financial condition and results of operations.

The difficulties and demands of integrating Triad’s assets and businesses into our Company may divert management attention from other important business activities. In addition to entering into new business activities, as a result of the Triad acquisition, we now operate in new geographic markets and are subject to additional and unfamiliar legal and regulatory requirements. Compliance with such regulatory requirements may impose substantial additional obligations on us and our management, cause us to expend additional time and resources in compliance activities and increase our exposure to penalties or fines for non-compliance with such additional legal requirements. The demands of integrating an acquired business could have a material adverse effect on our business, financial condition and results of operations.

We have limited management and staff and will be dependent upon partnering arrangements.

Prior to the Triad acquisition, we had 18 employees, including our nine officers. As a result of the Triad acquisition the Company and its affiliates, including Triad Hunter LLC, had approximately 139 total employees as of March 29, 2010. Despite this increase in employment, we expect that we will continue to require the services of independent consultants and contractors to perform various professional services, including reservoir engineering, land, legal, environmental and tax services. We will also pursue alliances with partners in the areas of geological and geophysical services and prospect generation, evaluation and prospect leasing. Our dependence on third party consultants and service providers creates a number of risks, including but not limited to:

•

the possibility that such third parties may not be available to us as and when needed; and

•

the risk that we may not be able to properly control the timing and quality of work conducted with respect to our projects.

If we experience significant delays in obtaining the services of such third parties or poor performance by such parties, our results of operations and stock price will be materially adversely affected.

Our business may suffer if we lose key personnel.

Our operations depend on the continuing efforts of our executive officers and senior management. Our business or prospects could be adversely affected if any of these persons does not continue in their management role with us and we are unable to attract and retain qualified replacements. Additionally, we do not carry key person insurance for any of our executive officers or senior management.

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

The exploration, development, production and sale of oil and natural gas are subject to extensive federal, state, and local laws and regulations. Such regulation includes requirements for permits to drill and to conduct other operations and for provision of financial assurances (such as bonds) covering drilling and well operations. Other activities subject to regulation are:

	•		the location and spacing of wells;
	•		the unitization and pooling of properties;
	•		the method of drilling and completing wells;
	•		the surface use and restoration of properties upon which wells are drilled;
	•		the plugging and abandoning of wells;
	•		the disposal of fluids used or other wastes generated in connection with our drilling operations;
	•		the marketing, transportation and reporting of production; and
	•		the valuation and payment of royalties.

Under these laws, we could be subject to claims for personal injury or property damages, including natural resource damages, which may result from the impact of our operations. Failure to comply with these laws also may result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties. Moreover, these laws could change in ways that substantially increase our costs of compliance. Any such liabilities, penalties, suspensions, terminations or regulatory changes could have a material adverse effect on our financial condition and results of operations.

We must obtain governmental permits and approvals for our drilling operations, which can be a costly and time consuming process, which may result in delays and restrictions on our operations.

Regulatory authorities exercise considerable discretion in the timing and scope of permit issuance. Requirements imposed by these authorities may be costly and time consuming and may result in delays in the commencement or continuation of our exploration or production operations. For example, we are often required to prepare and present to federal, state or local authorities data pertaining to the effect or impact that proposed exploration for or production of natural gas or oil may have on the environment. Further, the public may comment on and otherwise engage in the permitting process, including through intervention in the courts. Accordingly, the permits we need may not be issued, or if issued, may not be issued in a timely fashion, or may involve requirements that restrict our ability to conduct our operations or to do so profitably.

Our operations expose us to substantial costs and liabilities with respect to environmental matters.

Our oil and natural gas operations are subject to stringent federal, state and local laws and regulations governing the release of materials into the environment or otherwise relating to environmental protection. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentration of substances that can be released into the environment in connection with our drilling and production activities, limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas, and impose substantial liabilities for pollution that may result from our operations. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of investigatory or remedial obligations or injunctive relief. Under existing environmental laws and regulations, we could be held strictly liable for the removal or remediation of previously released materials or property contamination regardless of whether the release resulted from our operations, or our operations were in compliance with all applicable laws at the time they were performed. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent or costly waste handling, storage, transport, disposal or cleanup requirements could require us to make significant expenditures to maintain compliance, and may otherwise have a material adverse effect on our competitive position, financial condition and results of operations.

Federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.

Congress is currently considering legislation to amend the federal Safe Drinking Water Act to require the disclosure of chemicals used by the oil and natural gas industry in the hydraulic fracturing process. Hydraulic fracturing is an important and commonly used process in the completion of unconventional oil and natural gas wells in shale formations. This process involves the injection of water, sand and chemicals under pressure into rock formations to stimulate production. Sponsors of two companion bills, which are currently pending in the House Energy and Commerce Committee and the Senate Committee on Environment and Public Works Committee have asserted that chemicals used in the fracturing process could adversely affect drinking water supplies. The proposed legislation would require the reporting and public disclosure of chemicals used in the fracturing process, which could make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. In addition, this legislation, if adopted, could establish an additional level of regulation at the federal level that could lead to operational delays or increased operating costs and could result in additional regulatory burdens. The adoption of any future federal or state laws or implementing regulations imposing reporting obligations on, or otherwise limiting, the hydraulic fracturing process could make it more difficult and more expensive to complete new wells in shale formations and increase our costs of compliance and doing business.

Climate change legislation or regulations restricting emissions of “greenhouse gases” could result in increased operating costs and reduced demand for the oil, natural gas and NGLs that we produce.

A variety of regulatory developments, proposals or requirements and legislative initiatives have been introduced in the United States that are focused on restricting the emission of carbon dioxide, methane and other greenhouse gases. On June 26, 2009, the U.S. House of Representatives passed the American Clean Energy and Security Act of 2009, or ACESA, which would establish an economy-wide cap-and-trade program to reduce emissions of greenhouse gases in the United States, including carbon dioxide and methane. The U.S. Senate has begun work on its own legislation for controlling and reducing greenhouse gas emissions in the United States. Although it is not possible at this time to predict whether or when the Senate may act on climate change legislation, how any bill passed by the Senate would be reconciled with ACESA, or how federal legislation may be reconciled with state and regional requirements, any future federal laws or implementing regulations that may be adopted to address greenhouse gas emissions could require us to incur increased operating costs and could adversely affect demand for the oil, natural gas and NGLs that we produce.

In 2007, the U.S. Supreme Court held in Massachusetts, et al. v. EPA that greenhouse gas emissions may be regulated as an “air pollutant” under the federal Clean Air Act. On December 15, 2009, the U.S. Environmental Protection Agency, or EPA, officially published its findings that emissions of carbon dioxide, methane and other “greenhouse gases” present an endangerment to human health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. These findings by the EPA allow the agency to proceed with the adoption and implementation of regulations that would restrict emissions of greenhouse gases under existing provisions of the federal Clean Air Act. In late September 2009, the EPA also proposed two sets of regulations in anticipation of finalizing its findings that would require a reduction in emissions of greenhouse gases from motor vehicles and that could also lead to the imposition of greenhouse gas emission limitations in Clean Air Act permits for certain stationary sources. In addition, on September 22, 2009, the EPA issued a final rule requiring the reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the United States beginning in 2011 for emissions occurring in 2010.

Although it is not possible at this time to predict whether proposed legislation or regulations will be adopted as initially written, if at all, or how legislation or new regulations that may be adopted to address greenhouse gas emissions would impact our business, any such future laws and regulations could result in increased compliance costs or additional operating restrictions. Any additional costs or operating restrictions associated with legislation or regulations regarding greenhouse gas emissions could have a material adverse effect on our business, financial condition and results of operation. In addition, these developments could curtail the demand for fossil fuels such as oil and gas in areas of the world where our customers operate and thus adversely affect demand for our products and services, which may in turn adversely affect our future results of operations.

The adoption of derivatives legislation by Congress and related regulations could have an adverse impact on our ability to hedge risks associated with our business.

The U.S. Congress is currently considering legislation to increase the regulatory oversight of the over-the-counter derivatives markets in order to promote more transparency in those markets, and impose restrictions on certain derivatives transactions, which could affect the use of derivatives in hedging transactions. ACESA contains provisions that would prohibit private energy commodity derivative and hedging transactions. ACESA would expand the power of the Commodity Futures Trading Commission (CFTC) to regulate derivative transactions related to energy commodities, including oil and natural gas, and to mandate clearance of such derivative contracts through registered derivative clearing organizations. Under ACESA, the CFTC’s expanded authority over energy derivatives would terminate upon the adoption of general legislation covering derivative regulatory reform. The Chairman of the CFTC has announced that the CFTC intends to conduct hearings to determine whether to set limits on trading and positions in commodities with finite supply, particularly energy commodities, such as crude oil, natural gas and other energy products. The CFTC also is evaluating whether position limits should be applied consistently across all markets and participants. In addition, the Treasury Department recently has indicated that it intends to propose legislation to subject all OTC derivative dealers and all other major OTC derivative market participants to substantial supervision and regulation, including by imposing conservative capital and margin requirements and strong business conduct standards. Derivative contracts that are not cleared through central clearinghouses and exchanges may be subject to substantially higher capital and margin requirements. Although it is not possible at this time to predict whether or when Congress may act on derivatives legislation or how any climate change bill approved by the Senate would be reconciled with ACESA, any new laws or regulations in this area may result in increased costs and cash collateral requirements for the types of oil and gas derivative instruments we use to hedge and otherwise manage our financial risks related to swings in oil and gas commodity prices. Any legislative changes may impose additional restrictions on our trading and commodity positions, and could have an adverse effect on our ability to hedge risks associated with our business and on the cost of our hedging activity.

Competition in the oil and natural gas industry is intense, which may adversely affect our ability to compete.

We operate in a highly competitive environment for acquiring properties, exploiting mineral leases, marketing oil and natural gas and securing trained personnel. Many of our competitors possess and employ financial, technical and personnel resources substantially greater than ours, which can be particularly important in the areas in which we operate. Those companies may be able to pay more for productive oil and natural gas properties and exploratory prospects and to evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. Our ability to acquire additional prospects and to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. We may not be able to compete successfully in the future in acquiring prospective reserves, developing reserves, marketing hydrocarbons, attracting and retaining quality personnel and raising additional capital.

Risks Related to Our Equity Securities

Since being listed on the NYSE Amex (formerly, the American Stock Exchange) in August of 2006, the price of our common stock has fluctuated substantially and may fluctuate substantially in the future.

Since being listed on the NYSE Amex (formerly, the American Stock Exchange), the price of our common stock has fluctuated substantially. From August 30, 2006 to March 29, 2010, the trading price at the close of the market of our common stock ranged from a low of $0.20 per share to a high of $3.86 per share. We expect our common stock to continue to be subject to fluctuations as a result of a variety of factors, including factors beyond our control. These factors include:

	•		changes in oil and natural gas prices;
	•		variations in quarterly drilling, recompletions, acquisitions, and operating results;
	•		changes in financial estimates by securities analysts;
	•		changes in market valuations of comparable companies;
	•		additions or departures of key personnel;
	•		the level of our overall indebtedness;
	•		future issuances of our stock; and
	•		the other risks and uncertainties described in this “Risk Factors” section and elsewhere in this report.

We may fail to meet the expectations of our stockholders or of securities analysts at some time in the future, and our stock price could decline as a result. Volatility or depressed market prices of our common stock could make it difficult for you to resell shares of our common stock when you want or at attractive prices.

The market for our common stock is limited and may not provide investors with either liquidity or a market based valuation of our common stock.

Our common stock is traded on the NYSE Amex (formerly known as the American Stock Exchange) stock exchange market under the symbol “MHR”. On March 29, 2010, the last reported sale price of our common stock on the NYSE Amex was $3.04 per share. The present volume of trading in our common stock may not provide investors sufficient liquidity in the event they wish to sell their shares of common stock. There can be no assurance that an active market for our common stock will be available for trading in large volumes. In addition, the stock market in general, and early stage public companies in particular, have experienced extreme price and volume fluctuations that have often been unrelated or disproportionate to the operating performance of such companies. If we are unable to further develop an active market for our common stock, you may not be able to sell our common stock at prices you consider to be fair or at times that are convenient for you, or at all.

We will likely issue additional common stock in the future, which would dilute our existing stockholders.

In the future we may issue up to our previously authorized and unissued securities, including shares of our common stock or securities convertible into or exchangeable for our common stock, resulting in the dilution of the ownership interests of our stockholders. We are authorized under our amended and restated certificate of incorporation to issue 100,000,000 shares of common stock and 10,000,000 shares of preferred stock with such designations, preferences, and rights as may be determined by our board of directors. As of March 29, 2010, there were 57,979,111 shares of our common stock issued and outstanding and there were no shares of our Series A Preferred Stock issued and outstanding, 4 million shares of our Series B Preferred Stock issued and outstanding and 356,152 shares of our Series C Preferred Stock issued and outstanding.

We have an effective shelf registration statement from which additional shares of our common stock and other securities can be issued. We may also issue additional shares of our common stock or securities convertible into or exchangeable for our common stock in connection with the hiring of personnel, future acquisitions, future private placements of our securities for capital raising purposes or for other business purposes. Future issuances of our common stock, or the perception that such issuances could occur, could have a material adverse effect on the price of our common stock at any given time.

Additionally, we are engaged in the issuance and sale of our common stock and our Series C Preferred Stock from time to time through Wm. Smith & Co., as our exclusive sales manager pursuant to an “At The Market” sales agreement between the Company and Wm. Smith & Co. Sales of shares of our common stock, if any, by Wm. Smith & Co. will be made in privately negotiated transactions or in any method permitted by law deemed to be an “At The Market” offering as defined in Rule 415 promulgated under the Securities Act of 1933, as amended, at negotiated prices, at prices prevailing at the time of sale or at prices related to such prevailing market prices, including sales made directly on the NYSE Amex or sales made through a market maker other than on an exchange.

We may issue additional Series C Preferred stock in the future, which could dilute our existing holders of our outstanding Series C Preferred Stock.

We have an effective shelf registration statement from which additional shares of our common stock and other securities can be issued. In addition, we may also issue additional shares of our Series C Preferred Stock in connection with the hiring of personnel, future acquisitions, future private placements of our securities for capital raising purposes or for other business purposes.

Additionally, we are engaged in the issuance and sale of up to an additional $9,626,250 of our Series C Preferred Stock from time to time through Wm. Smith & Co., as our exclusive sales manager. Sales of shares of our Series C Preferred Stock, if any, by Wm. Smith & Co. will be made in privately negotiated transactions or in any method permitted by law deemed to be an “At The Market” offering as defined in Rule 415 promulgated under the Securities Act of 1933, as amended, at negotiated prices, at prices prevailing at the time of sale or at prices related to such prevailing market prices, including sales made directly on the NYSE Amex or sales made through a market maker other than on an exchange.

Our amended and restated certificate of incorporation, amended and restated bylaws, and Delaware law contain provisions that could make it more difficult for a third party to acquire us without the consent of our board of directors, our Chairman and other executive officers, who collectively beneficially own approximately 10% of the fully diluted outstanding shares of our common stock as of March 29, 2010.

Provisions in our amended and restated certificate of incorporation and amended and restated bylaws could have the effect of delaying or preventing a change of control of us and changes in our management. These provisions include the following:

	•		the ability of our board of directors to issue shares of our common stock and preferred stock without stockholder approval;
	•		the ability of our board of directors to make, alter, or repeal our bylaws without further stockholder approval;
	•		the requirement for advance notice of director nominations to our board of directors and for proposing other matters to be acted upon at stockholder meetings;
	•		the prohibition on stockholders taking action by written consent;
	•		requiring that special meetings of stockholders be called only by our Chairman, by a majority of our board of directors, by our Chief Executive Officer or by our President; and
	•		allowing our directors, and not our stockholders, to fill vacancies on the board of directors, including vacancies resulting from removal or enlargement of the board of directors.

In addition, we are subject to the provisions of Section 203 of the Delaware General Corporation Law. These provisions may prohibit large stockholders, in particular those owning 15% or more of our outstanding voting stock, from merging or combining with us.

As of March 29, 2010, our board of directors and our other executive officers collectively owned approximately 13% of the outstanding shares of our common stock. Although this is not a majority of our outstanding common stock, these stockholders, acting together, will have the ability to exert substantial influence over all matters requiring stockholder approval, including the election and removal of directors, any proposed merger, consolidation, or sale of all or substantially all of our assets and other corporate transactions.

The provisions in our amended and restated certificate of incorporation and amended and restated bylaws and under Delaware law, and the concentrated ownership of our common stock by our Chairman and other executive officers, could discourage potential takeover attempts and could reduce the price that investors might be willing to pay for shares of our common stock.

Because we have no plans to pay dividends on our common stock, stockholders must look solely to appreciation of our common stock to realize a gain on their investments.

We do not anticipate paying any dividends on our common stock in the foreseeable future. We currently intend to retain future earnings, if any, to finance the expansion of our business. Our future dividend policy is within the discretion of our board of directors and will depend upon various factors, including our business, financial condition, results of operations, capital requirements and investment opportunities. In addition, our Senior Credit Facility limits the payment of dividends without the prior written consent of the lenders. Accordingly, stockholders must look solely to appreciation of our common stock to realize a gain on their investment, which may not occur.

We are able to issue shares of preferred stock with greater rights than our common stock.

Our amended and restated certificate of incorporation authorizes our board of directors to issue one or more series of preferred stock and set the terms of the preferred stock without seeking any further approval from our stockholders. Any preferred stock that is issued may rank ahead of our common stock in terms of dividends, liquidation rights, or voting rights. If we issue preferred stock, it may adversely affect the market price of our common stock.

Our assets are subject to liquidation preferences in favor of the holders of our Series B and Series C Preferred Stock, which will impact the rights of holders of our common stock if we liquidate.

On December 14, 2009, we issued and sold 214,950 shares of our Series C Preferred Stock. We have also issued and sold additional shares of Series C Preferred Stock pursuant to the “At The Market” sales agreement relating to the Series C Preferred. Pursuant to the Prospectus Supplement relating to such “At The Market” sales of Series C Preferred Stock, filed January 6, 2010, we may sell an additional $9,626,250 of Series C Preferred Stock pursuant to such “At The Market” sales agreement. Under the Certificate of Designations of the Series C Preferred Stock, holders of the Series C Preferred Stock are entitled to receive the repayment of their original investment, together with any accrued but unpaid dividends, before any payment is made to holders of our common stock.

The 4,000,000 shares of Series B Preferred Stock issued as partial consideration for the Triad acquisition have an aggregate liquidation preference of $15 million, which pursuant to the Certificate of Designations for the Series B Preferred Stock, must be paid, together with any accrued but unpaid dividends, before any payment is made to holders of junior securities, including holders of common stock.

In addition to the ongoing “At The Market” offerings of shares of our common stock, our Series C Preferred Stock described above, and the Series B Preferred Stock described above, we may also seek to raise additional capital through the issuance of debt securities, preferred stock or other securities, and the holders of such securities may also have rights and preferences that are effectively senior to those of the holders of our common stock. The holders of our common stock might therefore receive nothing in liquidation, or receive much less than they would if there were no Series B, Series C or other Preferred Stock or other senior securities outstanding.

Our outstanding Warrants which are exercisable into our common stock, may be exercised, which would dilute our existing common stockholders.

We have outstanding 8,577,688 warrants that have a final maturity of 2012 exercisable into common stock of Magnum Hunter. Any such exercise will be dilutive to our existing shareholders.

The market price of our common stock could be adversely affected by sales of substantial amounts of our common stock and securities convertible into, or exchangeable for, shares of our common stock in the public markets and the issuance of shares of common stock and securities convertible into, or exchangeable for, shares of our common stock in future acquisitions.

Sales of a substantial number of shares of our common stock by us or by other parties in the public market, or the perception that such sales may occur could cause the market price of our common stock to decline. In addition, the sale of such shares in the public market could impair our ability to raise capital through the sale of common stock or securities convertible into, or exercisable for, shares of common stock.

In addition, in the future, we may issue shares of our common stock and securities convertible into, or exchangeable for, shares of our common stock in furtherance of our acquisitions and development of assets or businesses. If we use our shares for this purpose, the issuances could have a dilutive effect on the value of the shares of common stock, depending on market conditions at the time of such an event, the price we pay, the value of the assets or business acquired and our success in exploiting the properties or integrating the businesses we acquire and other factors.

Item 1B. UNRESOLVED STAFF COMMENTS

As of the date of this filing, we have no unresolved comments from the staff of the SEC.

Item 2. PROPERTIES

PROPERTIES

Appalachian Basin / Marcellus Shale

With the completion of the acquisition of Triad in February of 2010, as of March 29, 2010, the Company held approximately 87,000 net acres in the Appalachian Basin including approximately 46,000 net acres overlying the Marcellus Shale. At year-end 2009, proved reserves from our Appalachian Basin area of operations on an SEC basis were 5.1 MMboe, consisting of 65% oil and an estimated 61% were classified as proved developed producing, with a PV10 of $56.4 million. Using NYMEX strip prices, our proved reserves were 5.7 MMboe and our PV-10 was $119 million. We operate 2,048 wells and exited 2009 with a production rate of approximately 830 Boepd.

The Appalachian Basin includes the states of West Virginia, Ohio, Kentucky, Pennsylvania, Maryland, New York, Virginia, and Tennessee and is considered the most mature oil and gas producing region in the United States. Because the Appalachian Basin is located near the energy-consuming regions of the mid-Atlantic and northeastern United States, Appalachian producers have historically sold their natural gas at a premium to the benchmark price for natural gas on the NYMEX. Historically, producers in the Appalachian Basin developed oil and natural gas from Upper Devonian age shallow sandstones with low permeability, which are prevalent in the region. Traditional shallow wells in the Appalachian Basin generally produce little or no water, contributing to a low cost of operation. In addition, most wells produce dry natural gas, which does not require processing. However, times have changed for the Appalachian Basin. In recent years, the application of lateral well drilling and completion technology has lead to the development of the Marcellus Shale; transforming the Appalachian Basin into one of the country’s premier economic shale gas reserves.

The productive limits of the Marcellus Shale cover a large area within New York, Pennsylvania, Ohio and West Virginia. This Devonian age shale is a black, organic rich shale deposit productive at depths between 5,000 and 8,500 feet and ranges in thickness from 50 to over 200 feet. It is considered the largest natural gas field in the country. Marcellus gas is best produced from hydraulically fractured horizontal wellbores. These horizontal laterals exceed 2,000 feet in length, and typically involve multistage fracturing completions. The Company’s Marcellus acreage covers Pleasants, Tyler and Ritchie counties within West Virginia. As of March 29, 2010 the Company operates 32 vertical Marcellus wells defining the potential within our existing acreage.

The Company’s mineral lease acreage covers Pleasants, Tyler, Ritchie, Calhoun, Clay, Roane, Wayne, Wirt, Wood, and Lewis Counties in West Virginia, Leigh, Elliott and Morgan Counties in Kentucky and Morgan, Noble and Washington Counties in Ohio. As of March 29, 2010, we had over 87,000 net acres in the Appalachian Basin including approximately 46,000 net acres in the Marcellus Shale. As of March 29, 2010, approximately 75% of our leases are held by production. Our shallow production comes from the Berea, Macksburg 500 Sand, Devonian Shale and the Clinton/Medina Sands and we also believe that our acreage may also have the possibility of producing from the Trenton-Black River and Huron formations. The Huron formation has also benefited from lateral well drilling technology. In addition to our Marcellus Shale acreage, we also have significant enhanced waterflood oil recovery operations in Calhoun, Clay and Roane counties in West Virginia including our Granny’s Creek Field, Richardson Unit and Tariff unit.

In 2010, we plan to expand our Marcellus program, drilling a minimum of two horizontal wells from our inventory of over 25 identified horizontal drilling locations at a cost of approximately $7.0 million.

North Dakota-Williston Basin / Madison Group / Bakken Shale

At December 31, 2009, the Company owned an approximately 43% average working interest in 15 fields located in the Williston Basin in North Dakota comprising 146 wells and approximately 18,600 gross acres (approximately 90% of which is held by production) located in Burke, Renville, Ward, Bottineau and McHenry counties in North Dakota. As of December 31, 2009, our proved reserves on an SEC basis were an estimated 3.1 Mmboe with a PV-10 of $45.7 million with approximately 94 % and 89% of our reserves and production, respectively, consisting of oil. As of December 31, 2009, on a NYMEX strip basis, our proved reserves were 3.3 Mmboe with a PV-10 of $81.5 million. At December 31, 2009, we had a production exit rate of approximately 440 Boepd from our North Dakota properties.

The Williston Basin is spread across North Dakota, Montana and parts of southern Canada with the United States portion of the basin encompassing approximately 143,000 square miles. The basin produces oil and gas from numerous producing horizons including the Madison, Bakken, Three Forks/Sanish and Red River formations.

The Bakken formation is a Devonian-age shale found within the Williston Basin. The Bakken Shale is estimated to contain up to 4.3 billion barrels of recoverable crude oil according to a report issued by the United State Geological Survey (“USGS”) in April 2008, making it the largest continuous crude oil accumulation ever assessed by the USGS. Generally the Bakken formation underlies portions of North Dakota and Montana and is generally found at vertical depths of 9,000 to 10,500 feet. Below the Lower Bakken Shale lies the Three Forks/Sanish formation, and the Three Forks Shale has also proven to contain reservoir rock. The Three Forks/Sanish typically consists of interbedded dolomites and shale with local development of a discontinuous sandy member at the top, known as the Sanish sand. Crude oil production from the Bakken Shale and Three Forks/Sanish reservoirs is made possible through the combination of advanced horizontal drilling and fracture stimulation technology. Combining these two technologies to produce crude oil from the Bakken formation began to evolve around year 2000. Horizontal wells in these formations are typically drilled on 320,640 acre or 1,280 acre spacing with horizontal laterals extending 4,500 to 9,500 feet into the reservoir. Fracture stimulation techniques vary but most commonly utilize multi-stage mechanically diverted stimulations using un-cemented liners and packers.

Eagle Operating is the current operator of our Williston Basin properties. Re-pressurization efforts commenced in November of 2002, which have resulted in the ability to begin secondary recovery efforts through conventional and horizontal drilling activities in seven of the 15 producing fields. We have identified approximately 80 horizontal drilling locations. We drilled three horizontal wells in the fourth quarter of 2009 with a combined initial production rate of approximately 525 Boe per day (gross). These wells cost approximately $1.1 million gross per well and have estimated average of approximately 200,000 boe EUR gross per well.

South Texas / Eagle Ford Shale

As of March 29, 2010, we had approximately 15,000 net acres (20,000 gross) primarily targeting the Eagle Ford Shale. At year-end 2009, on an SEC basis, the Company had 590 Mboe of proved reserves and PV-10 of $3.6 million. Using NYMEX strip pricing, we had proved reserves of 603 Mboe with a PV-10 of $9.0 million.

The Eagle Ford Shale is a Cretaceous aged shale ranging in thickness of less than 100 feet to over 500 feet. The Eagle Ford Shale is present within the subsurface along the entire Gulf Coast of Texas and is productive within the majority of the trend, producing from the more brittle calcareous or dolomitic shale sections. The Eagle Ford Shale produces from depths that range from approximately 6,500 feet to 15,000 feet deep. To date, the Eagle Ford Shale produces in the Texas counties of Atascosa, Brazos, Burleson, Dewitt, Dimmit, Gonzales, Karnes, La Salle, Lee, Live Oak, Maverick, McMullen and Webb, spanning approximately 300 miles of the Texas Gulf Coast and is becoming one of newest emerging successful shale reserves in the country.

The Company has focused in the up-dip oil trend of the Eagle Ford Shale (7,000 feet to 11,000 feet) to provide better economics metrics and commodity stability. As of March 29, 2010, Magnum Hunter Resources had over 20,000 gross acres leased in the Eagle Ford Shale within the up-dip oil trend in Atascosa, Gonzales, Lee and Fayette counties, Texas. At March 20, 2010, we controlled approximately 15,000 net acres of Eagle Ford Shale and operate all of our Eagle Ford Shale properties. We have identified approximately 35 horizontal Eagle Ford Shale drilling locations. Working interest varies from 50% in Lee and Fayette Counties, Texas to 100% in Gonzales and Atascosa Counties, Texas.

In February 2010, as part of the Company’s ongoing evaluation of the Eagle Ford Shale, we fraced and tested a vertical Eagle Ford Shale well, the Barbara Ann Unit #1, in Lee County, Texas. We believe that frac stimulation is the most important element in the successful completion of these shale wells and understanding frac dynamics within these shales using existing vertical wells will allow us to better plan completions within our proposed horizontal wells. Our South Texas acreage has conventional oil and natural gas potential derived from both the Austin Chalk and Wilcox formations. Our Eberstadt # 1 well, located in the South Caesar Field of Bee County, Texas, began flowing to sales on February 1, 2010 with a daily production rate of approximately 1,500 Mcf, producing from a gross 100 foot thick section of the middle Wilcox formation. We believe that at least two additional Wilcox wells can be drilled offsetting the Eberstadt #1.

We have budgeted an estimated $6.95 million in capital expenditures for 2010 associated with leasing new acreage and the drilling of two horizontal wells, which are currently expected to commence in the second quarter of 2010. We are also exploring multiple Joint Venture opportunities with third parties in the Eagle Ford Shale.

South Louisiana / East Chalkley

Our East Chalkley field is located in Cameron Parish, Louisiana. The unit consists of approximately 714 gross acres. This developmental project is an exploitation of bypassed oil reserves remaining in a natural gas field located at depths between 9,300 feet and 9,400 feet. Proved reserves on an SEC basis at December 31, 2009 totaled 285 Mboe, consisting of 88% oil and 49% proved developed, with PV-10 of $3.9 million. On a NYMEX strip basis, our proved reserves were 293 Mboe with a PV-10 of $7.3 million. On October 15, 2009, we acquired Centurion Exploration Company LLC’s ownership interest East Chalkley for $1.7 million. Subsequently, on October 23, 2009, we divested a portion of our ownership interest for $500,000. Following the acquisition of additional ownership interest and subsequent partial divestiture, we now operate East Chalkley and own a 62% working interest with a 42.78% net revenue interest. During 2009, we added a salt water disposal well to reduce operating expenses and we put in electrification of the facilities. We estimate the future potential of the project to include three producing wells and three injection wells. As of March 29, 2010, we have two wells producing at a rate of approximately 100 gross Bbls per day. We have not allocated any capital to this project in 2010, as of March 29, 2010.

West Texas / Cinco Terry

We own a 10% working interest in an exploratory prospect area in Crockett County, Texas. The Cinco Terry project area has oil and natural gas potential from multiple horizons, including the Canyon (approximately 7,500 feet to 8,100 feet) and Ellenburger Sands (approximately 8,200 feet to 8,800 feet). We exited 2009 producing approximately 280 boepd, compared with 287 bbls per day in 2008. Our proved reserves at December 31, 2009 on an SEC PV-10 basis were 2.3 Mmboe, consisting of 62% oil and NGLs and 41% were classified as proved developed, with PV-10 of $12.2 million. On a NYMEX strip basis we had proved reserves of 2.3 Mmboe and a PV-10 of $27.8 million. Cinco Terry is operated by Approach Resources, Inc. and consists of approximately 50,000 gross acres (5,000 net). In 2009, we successfully drilled and completed 23 gross wells for total capital cost of about $2.2 million to the Company. We have identified approximately 150 additional drilling locations. In 2010, we plan to spend approximately $1 million in the Cinco Terry Prospect.

Other Properties

East Texas / Surprise — The Surprise Project is located in Nacogdoches County, Texas with natural gas potential from multiple horizons including James Lime, Pettit, Travis Peak, Expanded Bossier, Cotton Valley, and Haynesville Shale formations. The prospect is operated by Goodrich Petroleum Corporation. The prospect area consists of approximately 3,000 gross (300 net) acres and we have a 10% working interest in the prospect and a net revenue interest of 7.4%. As of March 29, 2010, we do not have any capital allocated to this project in 2010.

Other — In addition to our unconventional and other conventional properties, we have approximately 184,300 gross (31,287 net) undeveloped acres in the States of New Mexico, Kentucky and Utah. As of March 29, 2010, we do not plan to allocate capital to these areas in 2010. Furthermore, in 2009, we allowed our acreage positions in Allen Parish, Louisiana and Floyd and Motley Counties, Texas to expire, as they were not deemed conducive to our new business strategy.

Reserves

Our Oil and gas properties are primarily located in the (i) Appalachian Basin in West Virginia, Ohio and Kentucky with substantial acreage in the Marcellus Shale area in West Virginia; (ii) Williston Basin in North Dakota: (iii) Texas, including substantial acreage in the Eagle Ford Shale area; and (iv) Southern Louisiana. Our natural gas and crude oil reserves have been estimated as of December 31, 2009 by Cawley, Gillespie & Associates, Inc. (“CGA”), and DeGolyer & MacNaughton (“DM”). Natural gas and crude oil reserves and the estimates of the present value of future net revenues therefrom, were determined based on prices and costs as of December 31, 2009. Since January 1, 2009, we have not filed, nor were we required to file, any reports concerning our oil and gas reserves with any federal authority or agency.

There are numerous uncertainties inherent in estimating quantities of proved oil and gas reserves and estimates of reserve quantities and values must be viewed as being subject to significant change as more data about the properties becomes available.

Proved Reserves

In December 2008, the SEC released its finalized rule for “Modernization of Oil and Gas Reporting.” The new rule requires disclosure of oil and gas proved reserves by significant geographic area, using the arithmetic 12-month average beginning-of-the-month price for the year, as opposed to using year-end prices as was practiced in all previous years. The rule also allows for the use of reliable technologies to estimate proved oil and gas reserves, contingent on demonstrated reliability in conclusions about reserve volumes. Under the new rules, companies are required to report on the independence and qualifications of its reserve preparer or auditor, and file reports when a third-party is relied upon to prepare reserve estimates or conduct a reserve audit. The following table sets forth our estimated proved reserves based on the new SEC rules as defined in Rule 4.10(a) of Regulation S-X and Item 1200 of Regulation S-K.

		Net Reserves (SEC Prices at 12/31/09)
Category		Oil				NGL				Gas				PV-10
		(Barrels)				(Barrels)				(Mcf)				($MM)
Proved Developed			1,693,973				361,557				5,055,269			$	35.0
Proved Undeveloped			2,127,115				425,933				4,512,127			$	30.5
Total Proved			3,821,088				787,490				9,567,396			$	65.5

The table below summarizes our proved reserves, based on NYMEX futures strip pricing as of December 31, 2009.

		Net Reserves (Based on Futures Prices at 12/31/09)
Category		Oil				NGL				Gas				PV-10
		(Barrels)				(Barrels)				(Mcf)				($MM)
Proved Developed			1,880,794				384,076				5,304,369			$	61.3
Proved Undeveloped			2,178,966				457,002				4,719,557			$	64.2
Total Proved			4,059,760				841,078				10,023,926			$	125.5

All of our reserves are located within the continental United States. Reserve estimates are inherently imprecise and remain subject to revisions based on production history, results of additional exploration and development, prices of oil and natural gas and other factors. Please read “Item 1A. Risk Factors — Our estimated reserves are based on many assumptions that may turn out to be inaccurate. Any significant inaccuracies in these reserve estimates or underlying assumptions may materially affect the quantities and present value of our reserves” You should also read the notes following the table below and our Consolidated and Combined Financial Statements for the year ended December 31, 2009 in conjunction with the following reserve estimates.

The following tables include reserves related to our recent acquisition of Triad located in the Appalachian Basin, which closed in February of 2010.

		Pro Forma Net Reserves (SEC Prices at 12/31/09)*
Category		Oil				NGL				Gas				PV-10
		(Barrels)				(Barrels)				(Mcf)				($MM)
Proved Developed			3,799,567				361,000				11,949,768			$	76.8
Proved Undeveloped			3,367,568				426,000				8,112,153			$	45.2
Total Proved			7,167,135				787,000				20,061,921			$	122.0

		Pro Forma Net Reserves (Based on Futures Prices at 12/31/09)*
Category		Oil				NGL				Gas				PV-10
		(Barrels)				(Barrels)				(Mcf)				($MM)
Proved Developed			4,397,991				384,076				13,436,040			$	143.1
Proved Undeveloped			3,422,341				457,002				8,375,001			$	101.4
Total Proved			7,820,332				841,078				21,811,041			$	244.5

The following table sets forth our estimated proved reserves at the end of each of the past three years:

		2009				2008				2007
Description
Proved Developed Reserves
Oil (Bbls)			1,694,700				1,092,730				1,522,500
NGLs (Bbls)			361,000				301,577				0
Natural Gas (Mcf)			4,952,500				2,549,496				1,261,300
Proved Undeveloped Reserves
Oil (Bbls)			2,126,800				769,309				847,000
NGLs (Bbls)			426,000				245,636				0
Natural Gas (Mcf)			4,411,700				1,703,450				820,700
Total Proved Reserves (Boe) (1)(2)			6,169,200				3,118,076				2,716,500
PV-10 Value ($MMs) (3)		$	65.6			$	21.0			$	9.4
Standardized Measure ($MMs)		$	47.4			$	15.6			$	40.1

Marcellus Infrastructure Assets

The Triad acquisition brought important infrastructure assets for the effective development of the Marcellus Shale unconventional resource. With increased drilling activity in the region, relying on third-party oilfield service providers and pipeline operators can be costly. We feel that control of key oil field services allows us to manage the timing and costs of drilling and production. Furthermore, we believe that access to a pipeline system is vital to flow natural gas to sales, often being a deciding factor on drilling and production decisions. The summary below provides a brief overview of such services we operate and control, which mitigate certain risks associated with development of the Marcellus Shale. Additionally, we anticipate these assets will generate an attractive revenue stream as we actively market them to third-party producers in the Appalachian Basin.

Eureka Hunter Pipeline — The Eureka Hunter Pipeline consists of approximately 182 miles of pipeline, gathering and rights-of-way located in Northern West Virginia, in the Marcellus Shale. Specifically, the existing pipeline system runs through Pleasants, Tyler, Ritchie, Wetzel, Marion, Harrison, Doddridge, Lewis and Monongalia Counties. We are currently reviewing completion and expansion opportunities for the pipeline and we believe that the system can be expanded to up to 200 MMcf/d of throughput capacity. Following our anticipated expansion, we expect to have sufficient capacity to transport significant quantities of Company-produced natural gas from our Marcellus Shale development program, as well as third-party gas. We have budgeted $10 million for the completion of the first 12 miles of the pipeline project and anticipate completion in the third quarter of 2010.

Drilling Rigs and Oilfield Service Equipment — As part of the Triad acquisition in February of 2010, we acquired drilling rigs and oilfield service equipment. Our oilfield service equipment primarily consists of three drilling rigs, a workover rig and heavy machinery which are operated for us and third parties by our wholly-owned subsidiary, Alpha Hunter Drilling, LLC. We anticipate using our rigs to drill the vertical portion of our Marcellus Shale wells and then switching to larger rigs for the horizontal sections. This flexibility is expected to reduce the overall drilling costs, as well as improve the timing of drilling activity. As of March 29, 2010, two of our rigs are under a multi well drilling contract to a large producer in the area.

Salt Water Disposal Facility — Typically, Marcellus Shale wells produce significant amounts of water that, in most cases, requires disposal. Producers often remove the water in trucks for proper disposal in approved facilities. While this method has been the only option to many producers in the Appalachian Basin, it adds a significant operating burden and increases costs. We own and operate salt water disposal facilities with the current capacity of approximately 2,500 barrels of water per day. In addition to benefiting from our own disposal facilities, we market our disposal capabilities to third-party operators. In 2010, we anticipate disposal capacity will increase to over 4,000 barrels of water per day, following a $250,000 planned capital improvement.

Recent SEC Rule-Making Activity

In December 2008, the SEC announced that it had approved revisions designed to modernize the oil and gas company reserves reporting requirements. The most significant amendments to the requirements included the following:

	•		Commodity Prices: Economic producibility of reserves and discounted cash flows are now based on a 12-month average commodity price unless contractual arrangements designate the price to be used.
	•		Disclosure of Unproved Reserves: Probable and possible reserves may be disclosed separately on a voluntary basis.
	•		Proved Undeveloped Reserve Guidelines: Reserves may be classified as proved undeveloped if there is a high degree of confidence that the quantities will be recovered and they are scheduled to be drilled within the next five years, unless the specific circumstances justify a longer time.
	•		Reserves Estimation Using New Technologies: Reserves may be estimated through the use of reliable technology in addition to flow tests and production history.
	•		Reserves Personnel and Estimation Process: Additional disclosure is required regarding the qualifications of the chief technical person who oversees the reserves estimation process. We are also required to provide a general discussion of our internal controls used to assure the objectivity of the reserves estimate.
	•		Non-Traditional Resources: The definition of oil and gas producing activities has expanded and focuses on the marketable product rather than the method of extraction.

We adopted the rules effective December 31, 2009, as required by the SEC.

Effect of Adoption.

Application of the new reserve rules resulted in the use of lower prices at December 31, 2009 for both oil and gas than would have resulted under the previous rules. Use of new 12-month average pricing rules at December 31, 2009 resulted in proved reserves of approximately 6.2 MMboe. Use of the old year-end prices rules would have resulted in proved reserves of approximately 6.5 MMboe at December 31, 2009. Therefore, the total impact of the new price methodology rules resulted in negative reserves revisions of 0.4 MMboe.

Proved Undeveloped Reserves (PUD’s)

As of December 31, 2009, our proved undeveloped reserves totaled 2.1 MMboe of crude oil, 0.4 MMboe of NGLs and 4.4 Bcf of natural gas, for a total of 3.3 MMboe. Changes in PUDs that occurred during the year were due to:

	•		Successful drilling of 23 PUD locations in West Texas
	•		Successful drilling of 2 PUD locations in the Mohall Madison Unit in North Dakota and the re-drill of a Probable Undeveloped location in the East Flaxton Madison Unit in North Dakota.
	•		Successful re-pressurization results associated with two fields in North Dakota

Costs incurred relating to the development of PUD’s were approximately $7.6 million in 2009. Estimated future development costs relating to the development of PUD’s are projected to be approximately $17.0 million in 2010, $9.6 million in 2011, and $5.6 million in 2012.

All PUD drilling locations are scheduled to be drilled prior to the end of 2012. Initial production from these PUD’s is expected to begin between 2010 to 2013. We do not have PUD’s associated with reserves that have been booked for longer than three years.

The following table summarizes the changes in our proved reserves for the year ended December 31, 2009:

		For the Year Ended
Proved Developed Reserves (Mboe)		December 31, 2009
Proved Reserves — Beginning of year			3,118.1
Revisions of previous estimates			1,335.9
Improved recovery			0.0
Extensions and discoveries			1,330.2
Production			(256.6	)
Purchases of reserves in place			661.3
Sales of reserves in place			(19.7	)
Proved Reserves — End of year			6,169.2
Proved developed reserves — Beginning of year			1,819.2
Proved developed reserves — End of year			2,880.7

Reserve Estimation.

Cawley, Gillespie & Associates, Inc. (“CGA”) and DeGolyer & MacNaughton (“DM”), two independent petroleum engineering firms, evaluated our oil and gas reserves on a consolidated basis as of December 31, 2009. At December 31, 2009, these third party consultants collectively reviewed all of our proved oil and gas reserves. The technical persons responsible for preparing our proved reserves estimates meet the requirements with regards to qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. Our independent third party engineers do not own an interest in any of our properties and are not employed by us on a contingent basis.

We maintain an internal staff of petroleum engineers and geoscience professionals who work closely with CGA and DM to ensure the integrity, accuracy and timeliness of the data used to calculate our proved oil and gas reserves. Our internal technical team members meet with CGA and DM periodically throughout the year to discuss the assumptions and methods used in the proved reserve estimation process. We provide historical information to CGA and DM for our properties such as ownership interest; oil and gas production; well test data; commodity prices and operating and development costs. The preparation of our proved reserve estimates are completed in accordance with our internal control procedures, which include the verification of input data used by CGA and DM, as well as extensive management review and approval.

Acreage and Productive Wells Summary

The following table sets forth, for our continuing operations, our gross and net acreage of developed and undeveloped oil and natural gas leases and our gross and net productive oil and natural gas wells as of December 31, 2009.

		Developed								Undeveloped
		Acreage (1)								Acreage (2)								Total Acreage
		Gross				Net				Gross				Net				Gross				Net
North Dakota			15,200				6,536				3,411				1,116				18,611				7,652
West Texas			10,318				1,032				39,963				3,996				50,281				5,028
South Texas / Gulf Coast			1,471				485				10,527				4,811				11,998				5,296
Other			185,014				31,730				0				0				185,014				31,730
Total			212,003				39,783				53,901				9,923				265,904				49,706

The following two tables represent the pro forma calculation, as they include the Triad transaction which did not close until February of 2010:

		Pro Forma Developed								Pro Forma Undeveloped
		Acreage (1)								Acreage (2)								Pro Forma Total Acreage
		Gross				Net				Gross				Net				Gross				Net
Appalachia			67,000				60,000				35,602				21,449				102,602				81,449
North Dakota			15,200				6,536				3,411				1,116				18,611				7,652
West Texas			10,318				1,032				39,963				3,996				50,281				5,028
South Texas / Gulf Coast			1,471				485				10,527				4,811				11,998				5,296
Other			185,014				31,730				0				0				185,014				31,730
Total			279,003				99,783				89,503				31,372				368,506				131,155

The table below lists our wells by category and area.

		Pro Forma Producing								Pro Forma Producing								Pro Forma Total Producing
		Oil Wells								Gas Wells								Oil and Gas Wells
		Gross				Net				Gross				Net				Gross				Net
Appalachia			800.0				760.0				1,274.0				1,210.3				2,074.0				1,970.3
North Dakota			0.0				0.0				146.0				65.7				146.0				65.7
West Texas			87.0				8.7				0.0				0.0				87.0				8.7
South Texas / Gulf Coast			8.0				1.1				2.0				1.2				10.0				2.3
Other			5.0				0.5				0.0				0.0				5.0				0.5
Total			900				770				1,422				1,277				2,322				2,048

Substantially all of the leases summarized in the preceding table will expire at the end of their respective primary terms unless the existing lease is renewed or we have obtained production from the acreage subject to the lease before the end of the primary term; in which event, the lease will remain in effect until the cessation of production.

The following table sets forth, for our continuing operations, the gross and net acres of undeveloped land subject to leases summarized in the preceding table that will expire during the periods indicated:

		Expiring
Year Ending		Acreage
December 31,		Gross				Net
2010			858				337
2011			9,200				6,299
2012			750				610
2013			10,000				7,509
Total			20,808				14,755

Drilling Results

The following table summarizes our drilling activity for the past three years. Gross wells reflect the sum of all wells in which we own an interest. Net wells reflect the sum of our working interests in gross wells. All of our drilling activities were conducted on a contract basis by independent drilling contractors.

		2009								2008								2007
		Gross				Net				Gross				Net				Gross				Net
Exploratory Wells:
Productive			3				0.70				25				2.45				15				2.11
Unproductive			1				0.10				11				2.20				6				0.93
Total			4				0.80				36				4.65				21				3.04
Developmental Wells:			27				3.80				8				1.41				4				1.96
Total Wells:
Productive			30				4.50				33				3.86				19				4.07
Unproductive			1				0.10				0				0.00				6				0.93
Total			31				4.60				33				3.86				25				5.00
Success Ratio (1)			96.8	%			97.8	%			100.0	%			100.0	%			76.0	%			81.4	%