Magnum Hunter Resources 10-K 2012 FY Annual report

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

____________________________________

Form 10-K

x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 2012

Commission file number: 001-32997

____________________________________

Magnum Hunter Resources Corporation

(Name of registrant as specified in its charter)

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

777 Post Oak Boulevard, Suite 650, Houston, Texas 77056
(Address of principal executive offices, including zip code)

Registrant’s telephone number including area code: (832) 369-6986

Securities registered under Section 12(b) of the Act:

Title of Each Class	Name of Each Exchange on Which Registered
Common Stock, par value $.01 per share 10.25% Series C Cumulative Perpetual Preferred Stock 8.0% Series D Cumulative Preferred Stock Depositary Shares, each representing a 1/1,000 interest in a share of 8.0% Series E Cumulative Convertible Preferred Stock	NYSE NYSE MKT NYSE MKT NYSE MKT

Securities registered under Section 12(g) of the Act:
None

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

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  ¨    No   x

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 ¨     No  x

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, 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  ¨    No  x

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.                                                     ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer	x		Accelerated filer	¨
Non-accelerated filer	¨	(Do not check if a smaller reporting company)	Smaller reporting company	¨

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

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: $651,693,735.

As of June 1, 2013, 169,619,879 shares of the registrant’s common stock were issued and outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Documents incorporated by reference: None.

MAGNUM HUNTER RESOURCES CORPORATION

2012 Annual Report on Form 10-K

Table of Contents

		Page
GLOSSARY OF OIL AND NATURAL GAS TERMS		5
Item 1.	BUSINESS	10
Item 1A.	RISK FACTORS	23
Item 1B.	UNRESOLVED STAFF COMMENTS	46
Item 2.	PROPERTIES	46
Item 3.	LEGAL PROCEEDINGS	69
Item 4.	MINE SAFETY DISCLOSURES	69
Item 5.	MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES	70
Item 6.	SELECTED FINANCIAL DATA	72
Item 7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	73
Item 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	96
Item 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	F-1
Item 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	99
Item 9A.	CONTROLS AND PROCEDURES	99
Item 9B.	OTHER INFORMATION	102
Item 10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE	103
Item 11.	EXECUTIVE COMPENSATION	112
Item 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS	123
Item 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE	124
Item 14.	PRINCIPAL ACCOUNTANT FEES AND SERVICES	126
Item 15.	EXHIBITS, FINANCIAL STATEMENT SCHEDULES	128

CAUTIONARY NOTICE REGARDING FORWARD-LOOKING STATEMENTS

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, referred to as the Securities Act, and Section 21E of the Securities Exchange Act of 1934, as amended, referred to as the Exchange Act. 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, our ability to successfully develop, expand and market our midstream services, anticipated trends in our business or industry, our future results of operations, our liquidity and ability to finance our exploration and development activities and our midstream activities, market conditions in the oil and gas industry and the impact of environmental and other governmental regulation.

In addition, with respect to any pending or proposed acquisitions or dispositions described herein, forward-looking statements include, but are not limited to, statements regarding the expected timing of the completion of the transactions; the ability to complete the transactions considering the various closing or market conditions; the benefits of such transactions and their impact on the Company’s business; and any statements of assumptions underlying any of the foregoing. Also, if and when any proposed acquisition is consummated, there will be risks and uncertainties related to the Company’s ability to successfully integrate the operations and employees of the Company and the acquired business. Furthermore, with respect to our recent acquisitions, factors, risks and uncertainties that may cause actual results, performance or achievements to vary materially from those anticipated in forward-looking statements include, but are not limited to, failure to realize the expected benefits of the transactions; negative effects of announcement or consummation of the transactions on the market price of our common stock; significant transaction costs and/or unknown liabilities; general economic and business conditions that affect the companies following the transactions; and other factors.

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, Canada and globally;

• difficult and adverse conditions in the domestic and global capital and credit markets;

• changes in domestic and global demand for oil, natural gas and natural gas liquids;

• volatility in the prices we receive for our oil, natural gas and natural gas liquids;

• 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, natural gas and natural gas liquids income through exploration and development;

• our use of geo-scientific, petro-physical and engineering analyses to evaluate drilling prospects;

• our ability to successfully apply horizontal drilling techniques;

• the effects of increased federal and state regulation, including regulation of the environmental aspects, of hydraulic fracturing;

• 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 qualified personnel;

• changes in our drilling plans and related budgets;

• the availability of infrastructure, including pipelines, for the storage, gathering and transmission of oil and natural gas;

• the availability of plants and other equipment and facilities for the processing of natural gas;

• regulatory, environmental and land management issues, and demand for gas gathering services, relating to our gas gathering operations;

• regulatory and environmental issues, and demand for gas treating services, relating to our natural gas treating operations;

• the adequacy of our capital resources and liquidity including, but not limited to, access to additional borrowing capacity and the capital markets; and

• other factors discussed under “Risk Factors” in Item 1A of this annual report.

These factors are in addition to the risks described in the “Management’s Discussion and Analysis of Financial Condition and Results of Operations” section of this annual report. 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, which we refer to as the SEC.

NON-GAAP FINANCIAL MEASURES

We refer to the term PV-10 in this annual report on Form 10-K. This is a supplemental financial measure that is not prepared in accordance with U.S. generally accepted accounting principles, or GAAP. Any analysis of non-GAAP financial measures should be used only in conjunction with results presented in accordance with GAAP. PV-10 is the present value of the estimated future cash flows from estimated total proved reserves after deducting estimated production and ad valorem taxes, future capital costs, abandonment costs, net of salvage value, and operating expenses, but before deducting any estimates of future income taxes. The estimated future cash flows are discounted at an annual rate of 10% to determine their “present value.” We believe PV-10 to be an important measure for evaluating the relative significance of our oil and gas properties and that the presentation of the non-GAAP financial measure of PV-10 provides useful information to investors because it is widely used by professional analysts and investors in evaluating oil and gas companies. Because there are many unique factors that can impact an individual company when estimating the amount of future income taxes to be paid, we believe the use of a pre-tax measure is valuable for evaluating the Company. We believe that PV-10 is a financial measure routinely used and calculated similarly by other companies in the oil and gas industry. However, PV-10 is considered a non-GAAP financial measure under SEC regulations because it does not include the effects of future income taxes, as is required in computing the standardized measure of discounted future net cash flows.

The SEC has adopted rules to regulate the use in filings with the SEC and in public disclosures of “non-GAAP financial measures,” such as PV-10. These measures are derived on the basis of methodologies other than in accordance with GAAP. These rules govern the manner in which non-GAAP financial measures are publicly presented and require, among other things:

• a presentation with equal or greater prominence of the most comparable financial measure or measures calculated and presented in accordance with GAAP; and

• a statement disclosing the purposes for which the company’s management uses the non-GAAP financial measure.

For a reconciliation of PV-10 to the standardized measure of our proved oil and gas reserves at December 31, 2012, see “Properties-Non-GAAP Measures; Reconciliations” in Item 2 of this annual report.

GLOSSARY OF OIL AND NATURAL GAS TERMS

The following is a description of the meanings of some of the oil and natural gas industry terms used in this report.

bbl	Stock tank barrel, or 42 U.S. gallons liquid volume, used in this report in reference to crude oil or other liquid hydrocarbons.
bcf	Billion cubic feet of natural gas.
boe	Barrels of crude oil equivalent, determined using the ratio of six mcf of natural gas to one bbl of crude oil, condensate or natural gas liquids.
boepd	boe per day.
Completion	The process of treating a drilled well followed by the installation of permanent equipment for the production of natural gas or oil, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.
Condensate	Hydrocarbons which are in the gaseous state under reservoir conditions and which become liquid when temperature or pressure is reduced. A mixture of pentanes and higher hydrocarbons.
Development well	A well drilled within the proved area of a natural gas or oil reservoir to the depth of a stratigraphic horizon known to be productive.
Drilling locations	Total gross locations specifically quantified by management to be included in the Company’s multi-year drilling activities on existing acreage. The Company’s actual drilling activities may change depending on the availability of capital, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, drilling results and other factors.
Dry hole	A well found to be incapable of producing either oil or natural gas in sufficient quantities to justify completion as an oil or gas well.
EUR	Estimated ultimate recovery.
Exploratory well	A well drilled to find and produce natural gas or oil reserves not classified as proved, to find a new reservoir in a field previously found to be productive of natural gas or oil in another reservoir or to extend a known reservoir.
Field	An area consisting of either a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.
Formation	An identifiable layer of rocks named after its geographical location and dominant rock type.
Frac or fracing	Hydraulic fracturing, a common practice that is used to stimulate production of oil and natural gas from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, sand and chemicals under pressure into a formation to fracture the surrounding rock and stimulate production.
IP-24 hour or IP-24	A measurement of the amount of production by a newly-opened well during the first 24 hours of production.
IP-7 day or IP-7	A measurement of the average daily amount of production by a newly-opened well during the first seven days of production.
IP-30 day or IP-30	A measurement of the average daily amount of production by a newly-opened well during the first 30 days of production.
Lease	A lease specifies the terms of the business relationship between an energy company and a landowner or mineral rights holder on a particular tract of land and typically grants to the energy company a fee simple determinable estate in the minerals.
Leasehold	Mineral rights leased in a certain area to form a project area.
mbbls	Thousand barrels of crude oil or other liquid hydrocarbons.

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mbblspd	Thousand barrels of crude oil or other liquid hydrocarbons per day.
mboe	Thousand barrels of crude oil equivalent, determined using the ratio of six mcf of natural gas to one bbl of crude oil, condensate or natural gas liquids.
mboepd	Thousand barrels of crude oil equivalent, determined using the ratio of six mcf of natural gas to one bbl of crude oil, condensate or natural gas liquids, per day.
mcf	Thousand cubic feet of natural gas.
mcfpd	Thousand cubic feet of natural gas per day.
mcfe	Thousand cubic feet equivalent, determined using the ratio of six mcf of natural gas to one bbl of crude oil, condensate or natural gas liquids.
mcfepd	Thousand cubic feet equivalent, determined using the ratio of six mcf of natural gas to one bbl of crude oil, condensate or natural gas liquids, per day.
mmbbls	Million barrels of crude oil or other liquid hydrocarbons.
mmblspd	Million barrels of crude oil or other liquid hydrocarbons per day.
mmboe	Million barrels of crude oil equivalent, determined using the ratio of six mcf of natural gas to one bbl of crude oil, condensate or natural gas liquids.
mmboepd	Million barrels of crude oil equivalent, determined using the ratio of six mcf of natural gas to one bbl of crude oil, condensate or natural gas liquids, per day.
mmbtu	Million British Thermal Units.
mmbtupd	Million British Thermal Units per day.
mmcf	Million cubic feet of natural gas.
mmcfpd	Million cubic feet of natural gas per day.
Net acres, net wells or net reserves	The sum of the fractional working interests owned in gross acres, gross wells, or gross reserves, as the case may be.
NYMEX	New York Mercantile Exchange.
ngl	Natural gas liquids, or liquid hydrocarbons found in association with natural gas.
Overriding royalty interest	Is similar to a basic royalty interest except that it is typically created out of the working interest. For example, an operator possesses a standard lease providing for a basic royalty to the lessor or mineral rights owner of 1/8 of 8/8. This then entitles the operator to retain 7/8 of the total oil and natural gas produced. The 7/8 in this case is the net revenue interest attributable to the 100% working interest the operator owns. This operator may assign its working interest to another operator and reserve a 1/8 overriding royalty. This would then result in a basic royalty of 1/8, an overriding royalty of 1/8 and a working interest of 100% (with a net revenue interest attributable to such working interest of 3/4). Overriding royalty interest owners have no obligation or responsibility for developing and operating the property. The only expenses borne by the overriding royalty owner are a share of the production or severance taxes and sometimes costs incurred to make the oil or gas salable.
Plugging and abandonment	Refers to the sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum will not escape into another or to the surface. Regulations of all states require plugging of abandoned wells.
Present value of future net revenues (PV-10)	The present value of estimated future revenues to be generated from the production of proved reserves, before income taxes, calculated in accordance with Financial Accounting Standards Board guidelines, net of estimated production and future development costs, and abandonment costs, net of salvage value, using prices and costs as of the date of estimation without future escalation, without giving effect to hedging activities, non-property related expenses such as general and administrative expenses, debt service and depreciation, depletion and amortization, and discounted using an annual discount rate of 10%. PV-10 uses year-end prices for 2008 and prior years and the arithmetic 12-month average beginning-of-the-month price for 2009 and subsequent years. PV-10 differs from standardized measure because PV-10 does not include the effect of future income taxes.

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Production	Natural resources, such as oil or gas, taken out of the ground.
Proved oil and gas reserves	Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.
	(i)	The area of the reservoir considered as proved includes: (A) The area identified by drilling and limited by fluid contacts, if any, and (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.
	(ii)	In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering or performance data and reliable technology establish a lower contact with reasonable certainty.
	(iii)	Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering or performance data and reliable technology establish the higher contact with reasonable certainty.
	(iv)	Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (B) The project has been approved for development by all necessary parties and entities, including governmental entities.
	(v)	Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. For 2009 and subsequent years, the price shall be the average price during the 12-month period prior to the ending date of the period covered by the reserve report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.
Proved developed oil and gas reserves		Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as “proved developed reserves” only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.
Proved undeveloped oil and gas reserves		Proved undeveloped oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.

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Probable reserves	Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered. When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates. Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir. Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.
Possible reserves	Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates. Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project. Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves. Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the Company believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir. Where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.
Productive well	A well that is found to be capable of producing either oil or natural gas in sufficient quantities to justify completion as an oil or gas well.
Project	A targeted development area where it is probable that oil or natural gas can be produced from new wells.
Prospect	A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.
R/P	The reserves to production ratio. The reserve portion of the ratio is the amount of a resource known to exist in an area and to be economically recoverable. The production portion of the ratio is the amount of resource used in one year at the current rate.
Recompletion	The process of re-entering an existing well bore that is either producing or not producing and completing new reservoirs in an attempt to establish or increase existing production.
Reserves	Oil, natural gas and gas liquids thought to be accumulated in known reservoirs.
Reservoir	A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is separate from other reservoirs.

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Secondary recovery	A recovery process that uses mechanisms other than the natural pressure of the reservoir, such as gas injection or water flooding, to produce residual oil and natural gas remaining after the primary recovery phase.
Shut-in	A well that has been capped (having the valves locked shut) for an undetermined amount of time. This could be for additional testing, to wait for pipeline or processing facility, or for a number of other reasons.
Standardized measure	The present value of estimated future cash inflows from proved oil and natural gas reserves, less future development, abandonment costs, net of salvage value, production and income tax expenses, discounted at 10% per annum to reflect timing of future cash flows and using the same pricing assumptions as were used to calculate PV-10. Standardized measure differs from PV-10 because standardized measure includes the effect of future income taxes.
Successful	A well is determined to be successful if it is producing oil or natural gas, or awaiting hookup, but not abandoned or plugged.
Undeveloped acreage	Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves.
Water flood	A method of secondary recovery in which water is injected into the reservoir formation to displace residual oil and enhance hydrocarbon recovery.
Working interest	The operating interest that gives the owner thereof the right to drill, produce and conduct operating activities on the property and receive a share of production and requires the owner to pay a share of the costs of drilling and production operations.

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Item 1. BUSINESS

Our Company

We are an independent oil and gas company engaged in the exploration for and the exploitation, acquisition, development and production of crude oil, natural gas and natural gas liquids resources in the United States and Canada. We are presently active in three of the most prolific unconventional shale resource plays in North America, specifically, the Marcellus Shale in West Virginia and Ohio; the Utica Shale in southeastern Ohio and western West Virginia; and the Williston Basin/Bakken Shale in North Dakota and Saskatchewan, Canada. Our oil and natural gas reserves and operations are primarily concentrated in West Virginia, Ohio, North Dakota, Saskatchewan, Kentucky and Texas. We are also engaged in midstream and oil field services operations, primarily in West Virginia, Ohio and Texas.

Our principal business strategy is to (a) exploit our substantial inventory of lower risk, liquids-weighted drilling locations, (b) acquire and develop long-lived proved reserves and undeveloped leases with significant exploitation and development opportunities primarily located in close proximity to our existing core areas of operation and (c) selectively monetize our assets at opportune times and attractive prices. Since the current management team assumed leadership of the Company in May 2009 and completely refocused our business strategy, we have substantially increased our assets and production base through a combination of acquisitions, joint ventures and ongoing development drilling efforts. We believe the increased scale in all our core resource plays allows for ongoing cost recovery and production efficiencies as we exploit and monetize our asset base. We are focused on the further development and exploitation of our asset base, selective “bolt-on” acquisitions of additional operated properties in our core operating regions, expansion of our midstream operations and, ultimately, the possible monetization of our assets.

In April 2013, we monetized our core properties in the oil window of the Eagle Ford Shale in Gonzales and Lavaca Counties in south Texas through a sale of these properties to an affiliate of Penn Virginia Corporation, or Penn Virginia, for a total purchase price of $422.1 million, paid to us in the form of $379 million in cash (before customary purchase price adjustments) and $42.3 million in Penn Virginia common stock (valued, for purposes of the purchase price calculation, at a price of $4.23 per share). We refer to this sale as our sale of the Eagle Ford Properties or our Eagle Ford Properties Sale. As a result of our sale of the Eagle Ford Properties, we are now strategically focused on our Marcellus Shale, Utica Shale and Williston Basin/Bakken Shale plays.

We have reallocated our 2013 capital expenditure budget of $100 million previously allocated to the Eagle Ford Shale to our other shale plays, resulting in a capital expenditure budget of $150 million for the Marcellus Shale and Utica Shale plays and $150 million for the Williston Basin/Bakken Shale play, for a total 2013 upstream capital expenditure budget of $300 million.

We are exploring the possible monetization in 2013 or 2014 of all or part of our midstream operations. We have also identified a number of non-core properties, which we believe represent approximately $100 million to $200 million in aggregate value, for possible divestiture in 2013 and 2014.

Our midstream operations are conducted through our majority-owned subsidiary, Eureka Hunter Holdings, LLC, or Eureka Holdings. Eureka Holdings conducts its operations primarily through the following two subsidiaries: (i) Eureka Hunter Pipeline, LLC, or Eureka Pipeline, which owns and operates a gas gathering system in West Virginia and Ohio, referred to as our Eureka Hunter Gas Gathering System; and (ii) TransTex Hunter, LLC, or TransTex Hunter, which is engaged primarily in the business of treating natural gas at the wellhead for third party producers in Texas and other states. We have obtained financing for our midstream operations through an equity purchase commitment from an unaffiliated third party (which also gives us the right to make capital contributions in conjunction with or alongside the capital contributions from the third party) and two separate credit facilities on a non-recourse basis to Magnum Hunter.

We also conduct oil field services operations through our wholly-owned subsidiary, Alpha Hunter Drilling, LLC, or Alpha Hunter Drilling, which owns and operates five drilling rigs that are used primarily for vertical section (top-hole) air drilling in the Appalachian Basin. Alpha Hunter Drilling recently took delivery of a new drilling rig that can also drill the horizontal sections of wells in the shale plays where we are active.

Our principal executive offices are located at 777 Post Oak Boulevard, Suite 650, Houston, Texas 77056, and our telephone number at these offices is (832) 369-6986. Our website is www.magnumhunterresources.com. Unless stated otherwise or unless the context otherwise requires, all references in this report to Magnum Hunter, the Company, we, our, ours and us are to Magnum Hunter Resources Corporation and its consolidated subsidiaries.

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Our Core Operating Areas

Our core exploration and development operating areas are located in three of the most prolific unconventional shale resource plays in North America: the Marcellus Shale and the Utica Shale in the Appalachian Basin; and the Bakken/Three Forks Sanish formations in the Williston Basin. Our core operations also include our newly constructed gas gathering system located in the Marcellus Shale and Utica Shale in West Virginia and Ohio.

Appalachian Basin

Our Appalachian Basin drilling operations are focused on development in the liquids rich Marcellus Shale and Utica Shale underlying West Virginia and Ohio, and, to a lesser extent, in southern Appalachia. We entered the Appalachian Basin in February 2010 through our acquisition of substantially all the assets of Triad Energy Corporation. We subsequently expanded our operations through various corporate and leasehold acreage acquisitions, including (i) the acquisition of NGAS Resources, Inc., or NGAS, in April 2011, which established our position in southern Appalachia, (ii) the acquisition of assets from PostRock Energy Corporation and Windsor Marcellus LLC in late 2010 and early 2011, pursuant to which we acquired additional Marcellus Shale properties in Lewis, Braxton and Wetzel Counties, West Virginia, (iii) the expansion of our position in the Utica Shale in early 2012 through the acquisition of approximately 12,100 net acres in Noble and Washington Counties, Ohio, referred to as our Utica Acreage Acquisition, and (iv) the acquisition of privately-held Viking International Resources Co., Inc. in November 2012, referred to as our Virco Acquisition, which added approximately 51,500 net acres to our existing position in Appalachia, including approximately 27,000 net acres in the Marcellus Shale and approximately 28,500 net acres prospective for the Utica Shale (a portion of which acreage overlaps our Marcellus Shale acreage).

Marcellus Shale. As of May 1, 2013, we had a total of approximately 81,000 net leasehold acres in the Marcellus Shale. Our Marcellus Shale acreage is located principally in Tyler, Pleasants, Doddridge, Wetzel and Lewis Counties, West Virginia and in Washington, Monroe and Noble Counties, Ohio. As of May 1, 2013, the Company was operating 16 horizontal Marcellus Shale wells, and 10 horizontal wells (six net) were awaiting completion, one horizontal well (one-half net) was drilling and one drilling rig was operating on our Company-operated Marcellus Shale properties. As of May 1, 2013, approximately 76% of our mineral leases in the Marcellus Shale area were held by production. As of May 1, 2013, our 11 most recently completed Company-operated horizontal wells targeting the Marcellus Shale generated approximately 9,525 mcfepd and 5,800 mcfepd average IP-24 hour and IP-30 day rates, respectively.

Utica Shale. As of May 1, 2013, we had a total of approximately 79,000 net leasehold acres prospective for the Utica Shale (a portion of which acreage overlaps our Marcellus Shale acreage). We believe approximately 26,000 of these Utica Shale net acres are located in the wet gas window of the play. We acquired approximately 12,100 net acres pursuant to the Utica Acreage Acquisition completed in early 2012 and approximately 28,500 net acres pursuant to the Virco Acquisition completed in November 2012. Substantially all of our acreage in the Utica Shale is held by shallow production. We intend to become much more active in the Utica Shale play in the second half of 2013 and 2014. We are currently testing one horizontal well in the Utica Shale, which we spud in April 2013. We expect to commence a 25 plus stage fracture stimulation of the well in July 2013. After we finish fracing the well, we plan to shut in the well for approximately 30 to 40 days and then begin flow testing the well in August or September 2013. We plan to drill three more horizontal wells in the Utica Shale in 2013. Subject to the results of these wells, we expect to significantly expand our drilling program in the play in 2014, as we also continue to expand our Eureka Hunter Gas Gathering System into Ohio to gather the anticipated production in this new play.

Our 2013 capital expenditure budget includes approximately $150 million of capital expenditures in the Appalachian Basin, essentially all in the Marcellus Shale and Utica Shale regions. We intend to drill a total of 30 gross (21 net) wells in the Marcellus Shale and four gross (three net) wells in the Utica Shale in 2013.

Williston Basin/Bakken Shale

We acquired NuLoch Resources Inc., or NuLoch, in May 2011, establishing our initial presence in the Bakken/Three Forks Sanish formations in North Dakota and Saskatchewan, Canada. We expanded our presence in the Williston Basin through (i) our March 2012 acquisition of Eagle Operating, Inc.’s operating working interest ownership in certain oil and gas leases and wells in five counties in North Dakota, (ii) our May 2012 acquisition of Baytex Energy USA Ltd.’s non-operating working interest ownership in certain oil and gas leases and wells in Divide and Burke Counties, North Dakota and (iii) our December 2012 acquisition of Samson Resources Company’s operating and non-operating working interest ownership in certain oil and gas leases and wells in Divide County, North Dakota.

As of May 1, 2013, our Williston Basin properties included approximately 178,000 net leasehold acres consisting of approximately 124,600 net acres and 53,400 net acres in the Bakken/Three Forks Sanish formations in North Dakota and Saskatchewan, respectively. As of May 1, 2013, (i) our five most recently completed third-party-operated one-mile horizontal wells in Divide County, North Dakota generated an average IP-24 hour rate of approximately 594 boepd and (ii) our five most recently completed third-party-operated two-mile horizontal wells in Divide County North, Dakota generated an average IP-24 hour rate of approximately 732 boepd.

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Our drilling activities in 2012 and 2013 in our Company-operated Tableland Field area in Saskatchewan in the Bakken/Three Forks Sanish formations have shown consistently improved results. The implementation of our re-designed fracture stimulation technique in the Tableland Field area has substantially increased the initial productivity of our more recent wells. As of May 1, 2013, our eight most recently completed horizontal wells in the Tableland Field generated an average IP-24 hour rate of approximately 358 boepd.

Our 2013 capital expenditure budget includes approximately $150 million of capital expenditures in the Williston Basin/Bakken Shale and is expected to include expenditures for the drilling of approximately 65 gross (22.4 net) wells in the Bakken/Three Forks Sanish formations. We intend to focus our Williston Basin activity in 2013 largely on further development in the Bakken/Three Forks Sanish formations in the Ambrose Field in northwest Divide County, North Dakota. We have experienced better rates of return on capital deployed in this area compared with other areas in the Williston Basin where we are active. We also plan to focus our activities in 2013 significantly more on developing the middle Bakken formation in our properties in Divide County.

Midstream Operations

We are continuing the commercial development of our Eureka Hunter Gas Gathering System in West Virginia and Ohio to support the development of our existing and anticipated future Marcellus Shale and Utica Shale acreage positions, as well as the expanding gas gathering needs of third party producers in these regions. The system is being constructed primarily out of 20-inch and 16-inch high-pressure steel pipe with an estimated 350 mmcfpd of initial throughput capacity. As of May 1, 2013, we had completed the construction of a total of approximately 79 miles of pipeline as part of the system, including (i) a lateral section of the pipeline that connected to the Mobley Processing Plant in Wetzel County, West Virginia described below and (ii) a lateral section of the pipeline that crossed under the Ohio River from Wetzel County, West Virginia into Monroe County, Ohio. As of June 10, 2013, we were flowing approximately 100,000 mcf of natural gas per day through the Eureka Hunter Gas Gathering System.

We have entered into gas processing and other agreements with MarkWest Liberty Midstream & Resources, L.L.C., or MarkWest. In December 2012, pursuant to these agreements, MarkWest began processing at its 200 mmcfe per day gas processing plant located near the town of Mobley in Wetzel County, West Virginia, referred to as the Mobley Processing Plant, natural gas production of the Company and third parties gathered through our Eureka Hunter Gas Gathering System.

The Eureka Hunter Gas Gathering System will enable us to continue to develop our substantial natural gas and natural gas liquids resources in the Marcellus Shale and Utica Shale, as well as provide the opportunity for substantial cash flow from the gathering of third party volumes of natural gas. Our 2013 capital expenditure budget includes approximately $100 million of capital expenditures (to the 100% ownership interest) relating to the Eureka Hunter Gas Gathering System.

Our midstream operations also include TransTex Hunter’s business of treating natural gas at the wellhead for third-party producers.

Summary of Proved Reserves, Production and Acreage

• As of December 31, 2012, we had approximately 73.1 mmboe of estimated proved reserves, of which approximately 62.9% was oil and natural gas liquids and approximately 52% was classified as proved developed producing reserves. By comparison, as of December 31, 2011, our estimated proved reserves were approximately 44.9 mmboe, of which approximately 48% was oil and natural gas liquids and approximately 51% was classified as proved developed producing reserves. Our estimated proved reserves, on a boe basis, at year-end 2012 increased 63% from that at year-end 2011.

• As of December 31, 2012, after giving effect to our sale of the Eagle Ford Properties in April 2013, we had approximately 61.6 mmboe of estimated proved reserves, of which approximately 57% was oil and natural gas liquids and approximately 56% was classified as proved developed producing reserves.

• As of December 31, 2012, we had proved reserves with a PV-10 value of $981.2 million (SEC basis) and $1.0 billion (NYMEX basis) (as further explained in the “Management’s Discussion and Analysis of Financial Condition and Results of Operations” section of this annual report). This compares with proved reserves with a PV-10 value of $616.9 million (SEC basis) and $600.9 million (NYMEX basis) as of December 31, 2011. The PV-10 value (SEC basis), of our estimated proved reserves at year-end 2012 increased 59% from that at year-end 2011. PV-10 values are different from the standardized measure of proved reserves due to the inclusion in the standardized measure of estimated future income taxes. The standardized measure of our proved reserves at December 31, 2012 was $847.7 million.

• As of December 31, 2012, after giving effect to our sale of the Eagle Ford Properties in April 2013, we had proved reserves with a PV-10 value of $753.4 million (SEC basis) and $809.0 million (NYMEX basis). The standardized measure of our proved reserves at December 31, 2012, after giving effect to our sale of the Eagle Ford Properties in April 2013, was $633.2 million.

• Our daily production volumes at December 31, 2012 were approximately 18,500 boepd. Our average daily production volumes for the year ended December 31, 2012, were approximately 13,152 boepd, which represented a 141% increase from the year ended December 31, 2011. Our average daily production volumes for the quarter ended December 31, 2012 were approximately 14,587 boepd.

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• Our daily production volumes at June 10, 2013 were approximately 17,500 boepd. Our sale of the Eagle Ford Properties in April 2013 reduced our current volumes by approximately 3,500 boepd.

• As of May 1, 2013, we had approximately 338,800 net leasehold acres in our core operating areas, including (i) approximately 81,000 net acres in the Marcellus Shale, (ii) approximately 79,000 net acres prospective for the Utica Shale (a portion of which acreage overlaps our Marcellus Shale acreage) and (iii) approximately 178,000 net acres in the Williston Basin/Bakken Shale.

SEC Case Reserve Summary

	At December 31, 2012
	ProvedReserves(a)	PV-10 (b)(c)		%Proved Developed	%Oil/Liquids
						Productive Wells
Area	(mmboe)	(Millions)				Gross		Net
Eagle Ford Shale (d)	11.9	$	237.4	37%	96%	42		21.4
Appalachian Basin	36.5	$	296.0	79%	31%	3,887		2,746.1
Williston Basin
Williston Hunter U.S.	21.2	$	351.1	35%	95%	288		136.4
Williston Hunter Canada	2.5	$	76.8	83%	99%	38		34.0
Other U.S.(e)	0.7	$	8.6	38%	35%	24		3.2
Other Canada (f)	0.3	$	11.3	100%	91%	49		44.0
Total at December 31, 2012	73.1	$	981.2	60%	63%	4,328		2,985.1
Less: Eagle Ford Properties Sale (d)	(11.4)	(227.8)		37%	96%	(39	)	(18.9	)
Total at December 31, 2012, giving effect to the Eagle Ford Properties Sale	61.7	$	753.4	64%	57%	4,289		2,966.2

(a) Mmboe is defined as one million barrels of oil equivalent determined using the ratio of six mcf of natural gas to one bbl of crude oil, condensate or natural gas liquids.

(b) The prices used to calculate this measure were $94.71 per barrel of oil and $2.75 per mmbtu of natural gas. The prices represent the average prices per barrel of oil and per mmbtu of natural gas at the beginning of each month in the 12-month period prior to the end of the reporting period. These prices were adjusted to reflect applicable transportation and quality differentials on a well-by-well basis to arrive at realized sales prices used to estimate our reserves at this date.

(c) The standardized measure of our proved reserves at December 31, 2012 was $847.7 million. The standardized measure of our proved reserves at December 31, 2012, after giving effect to the Eagle Ford Properties Sale, was $ $633.2 million. See “Item 2. Properties—Non-GAAP Measures; Reconciliations” for a definition of pre-tax PV-10 and a reconciliation of our standardized measure to our pre-tax PV-10 value.

(d) See "Our Recent Significant Developments" below and "Note 20 - Subsequent Events" for a summary description of the Eagle Ford Properties Sale to a Penn Virginia affiliate in April 2013. Shale Hunter, LLC, a wholly-owned subsidiary of the Company, holds certain Eagle Ford Shale assets that remained with Magnum Hunter following the Eagle Ford Properties Sale.

(e) Other U.S. pertains to certain miscellaneous properties in Texas (outside of the Eagle Ford Shale area) and Louisiana, for which no capital expenditures have been budgeted in 2013. See “Item 2. Properties-Other Properties”.

(f) Other Canada pertains to our Alberta, Canada properties.

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NYMEX Futures Strip Case Reserve Summary

	At December 31, 2012
	ProvedReserves(a)	PV-10 (b)(c)		%Proved Developed	%Oil/Liquids	Productive Wells
Area	(mmboe)	(Millions)				Gross		Net
Eagle Ford Shale (d)	11.5	$	212.8	38%	96%	42		21.4
Appalachian Basin	39.8	$	401.3	77%	30%	3,887		2,746.1
Williston Basin
Williston Hunter U.S.	19.6	$	307.2	38%	96%	288		136.4
Williston Hunter Canada	2.1	$	70.1	96%	100%	38		34.0
Other U.S.(e)	0.7	$	10.3	42%	33%	24		3.2
Other Canada (f)	0.4	$	11.2	100%	66%	49		44.0
Total at December 31, 2012	74.1	$	1,012.9	61%	60%	4,328		2,985.1
Less: Eagle Ford Properties Sale (d)	(11.1)	(203.9)		38%	96%	(39	)	(18.9	)
Total at December 31, 2012, giving effect to the Eagle Ford Properties Sale	63.0	$	809.0	65%	53%	4,289		2,966.2

(a) Mmboe is defined as one million barrels of oil equivalent determined using the ratio of six mcf of natural gas to one bbl of crude oil, condensate or natural gas liquids.

(b) The prices used to calculate this measure were the NYMEX futures strip prices as of December 31, 2012.

(c) The standardized measure of our proved reserves at December 31, 2012 was $847.7 million. The standardized measure of our proved reserves at December 31, 2012, after giving effect to the Eagle Ford Properties Sale, was $633.2 million. See “Item 2. Properties—Non-GAAP Measures; Reconciliations” for a definition of pre-tax PV-10 and a reconciliation of our standardized measure to our pre-tax PV-10 value.

(d) See "Our Recent Significant Developments" below and "Note 20 - Subsequent Events" for a summary description of the Eagle Ford Properties Sale to a Penn Virginia affiliate in April 2013. Shale Hunter, LLC, a wholly-owned subsidiary of the Company, holds certain Eagle Ford Shale assets that remained with Magnum Hunter following the Eagle Ford Properties Sale.

(e) Other U.S. pertains to certain miscellaneous properties in Texas (outside of the Eagle Ford Shale area) and Louisiana, for which no capital expenditures have been budgeted in 2013. See “Item 2. Properties-Other Properties”.

(f) Other Canada pertains to our Alberta, Canada properties.

Our Business Strategy

Our business strategy is to create significant value for our stockholders by growing reserves, production volumes and cash flow at an attractive rate of return through a combination of efficient development of our properties and strategic acquisitions and joint ventures, and to selectively monetize properties at opportune times and attractive prices.

The development of our core properties in the oil window of the Eagle Ford Shale in Gonzales and Lavaca Counties, Texas, and subsequent monetization of these properties through our sale of the Eagle Ford Properties to a Penn Virginia affiliate in April 2013, was representative of this strategy. This transaction allowed us to delever and to redeploy capital into our remaining shale plays.

Key elements of our business strategy include:

Continued Focus on Core Unconventional Resource Plays

We intend to continue to focus on the development and expansion of our core areas of operation in the Marcellus Shale in West Virginia and Ohio, in the Utica Shale in southeastern Ohio and western West Virginia and in the Williston Basin/Bakken Shale in North Dakota and Saskatchewan, Canada. As of May 1, 2013, we had a total of approximately 551,700 gross acres (338,800 net acres) in these core areas. We believe we have achieved "shale scale" and that these core areas represent the potential for an attractive return on invested capital for the Company.

Continued Focus on Development and Acquisition of Oil and Liquids Rich Resources

We focus our development and acquisition efforts primarily on oil and liquids rich projects, including (i) liquids rich gas (greater than 1,250 btu) in the Marcellus Shale areas of West Virginia and Ohio, (ii) the liquids rich area of the Utica Shale in southeastern Ohio and (iii) oil reserves in the Williston Basin (Bakken Shale/Three Forks Sanish formations). We have allocated substantially all

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of our 2013 upstream capital expenditure budget to oil and liquids rich development projects. We intend to only pursue strategic “bolt-on” acquisitions, primarily of leasehold acreage, in our core areas, on a very selective and value accretive basis, to enhance long-term asset values and economies of scale.

Utilize Expertise in Unconventional Resource Plays to Improve Rates of Return

We strive to use state of the art drilling, completion and production technologies, including certain completion techniques that we have developed and continue to refine, allowing us the best opportunity for cost-effective drilling, completion and production success. Our technical team regularly reviews the most current technologies and, to the extent appropriate and cost-effective, applies them to our reserve base for the effective development of our project inventory. As a result of our improving drilling and completion techniques, our drilling and completion results in our core unconventional resource plays have dramatically improved, resulting in substantially better initial production, or IP, rates, estimated ultimate recoveries, and, ultimately, rates of return on capital deployed. Additionally, our focus on increasing and concentrating our acreage provides the opportunity to capture economies of scale, such as pad drilling, and to reduce rig mobilization time and cost.

Allocate Capital Expenditures to Projects with Higher Rates of Return

Our large and diverse inventory of highly economic properties allows our management to allocate capital to areas and projects with the highest potential rates of return. In 2012, we allocated approximately 95% of our upstream capital expenditures to oil and liquids rich natural gas related projects due to their better relative rates of return in last year's commodity price environment. In 2013, we expect to allocate a greater percentage of upstream capital expenditures to such projects. However, the price of natural gas has more than doubled from a low of less than $2.00 per mcf last year to over $4.00 per mcf this year.

As a result of our sale of the Eagle Ford Properties, we have reallocated our 2013 upstream capital expenditures budget of $300 million, as follows: (i) $150 million to the Appalachian Basin, almost all of which is allocated to our Marcellus Shale and Utica Shale plays; and (ii) $150 million to our Williston Basin/Bakken Shale play. We have allocated a significant portion of our 2013 capital budget to the Marcellus Shale and Utica Shale plays to take advantage of our processing capacity at the now-operational Mobley Processing Plant (and the expected significant uplift in the realized price for our liquids-rich gas stream processed at the plant) and in anticipation of our continued build-out of our Eureka Hunter Gas Gathering System.

Selected Monetization in Core and Non-Core Areas

Our strategy has always been to “build to sell”. In the past four years, we significantly expanded our positions in the Williston Basin, Marcellus Shale, Utica Shale, Eagle Ford Shale and southern Appalachian Basin through acquisitions and joint ventures. We monetized our core Eagle Ford Shale properties through our sale of the Eagle Ford Properties in April 2013 for a purchase price of $401 million. We expect to continue to develop our remaining core assets in 2013, while also reviewing the selective monetization of certain of our non-core assets and interests. We have identified a number of non-core properties, which are typically conventional properties, that we believe represent approximately $100 million to $200 million in aggregate value, for possible divestiture in 2013 and 2014. We are also exploring the possible monetization in 2013 or 2014 of all or part of our midstream operations.

Focus on Properties with Operating Control

We believe that operatorship provides us with the ability to maximize the value of our assets, including control of the timing of drilling expenditures, greater control of operational costs and the ability to efficiently increase production volumes and reserves. During the past four years, we have significantly increased the number of wells that we operate and control. As of May 1, 2013, following our sale of the Eagle Ford Properties, we were operating approximately 80% of our producing wells. As of December 31, 2012, after giving effect to our sale of the Eagle Ford Properties, we were operating approximately 61% of our proved reserves. Approximately45% of our 2013 capital expenditure budget relates to our operated properties. Substantially all of our operated properties is held by existing production which gives us the flexibility to make determinations regarding the most optimum time to further develop the properties in a cost-effective manner without concern of lease expirations.

Maintain Appropriate Leverage, Liquidity and Financial Flexibility

We utilize what we consider to be appropriate amounts of debt and equity to maintain adequate liquidity and manageable leverage ratios, while at the same time providing an accelerated rate of growth in order to achieve above average returns on capital. As of May 1, 2013, we had total liquidity of approximately $380 million, including cash on hand of approximately $115 million and approximately $265 million of borrowing capacity available under the Company’s Second Amended and Restated Credit Agreement, referred to as our MHR Senior Revolving Credit Facility or our revolving credit facility. As of June 1, 2013, we also owned 10 million shares of Penn Virginia common stock (acquired as partial consideration for our sale of the Eagle Ford Properties), valued at $42.3 million, based on the market price of the stock as of that date, and we intend to monetize these shares in 2013, depending on market conditions and other considerations. We also plan an aggregate of $100 million to $200 million of non-core asset divestitures

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in 2013 and 2014, which would provide us with additional liquidity and strategic flexibility. We maintain an active rolling commodity derivatives program to provide stability and predictability to our cash flow stream.

Our liquidity and leverage ratios improved significantly as a result of our receipt of the approximately $361 million in cash proceeds (before customary purchase price adjustments) from our sale of the Eagle Ford Properties. We also expect to utilize a portion of our existing net operating loss carry-forward amounts to offset all of the taxable gain realized from such sale.

We believe that (i) our cash on hand, (ii) our expected operating cash flows, (iii) the available borrowing capacity under our MHR Senior Revolving Credit Facility, (iv) proceeds generated from possible sales of our Penn Virginia common stock and (v) our expected ability to access the funding facilities we have obtained for our midstream operations, will collectively provide us with the financial flexibility to complete our capital program in 2013, thus helping to achieve our long-term business objectives.

Continued Development of our Eureka Hunter Gas Gathering System

We are continuing the commercial development of our Eureka Hunter Gas Gathering System in West Virginia and Ohio to provide infrastructure to support the development of our existing and anticipated future Marcellus Shale and Utica Shale acreage positions, as well as to provide the opportunity for substantial cash flow from the increasing gathering needs of third party producers in these regions. We are exploring the possible monetization in 2013 or 2014 of all or part of our midstream operations.

Our Competitive Strengths

We believe we have the following competitive strengths that will support our efforts to successfully execute our business strategy:

Diversified Long-Lived Asset Base with Substantial Oil and Liquids Reserves

We believe our geographic mix of properties and drilling opportunities, combined with timely development and additional acquisitions of properties in our core resource areas, present us with a variety of highly economic growth opportunities. As of December 31, 2012, after giving effect to our sale of the Eagle Ford Properties in April 2013, approximately 57% and 40% of our proved reserves and production, respectively, were oil and natural gas liquids. As of May 1, 2013, we held ownership interests in approximately 4,300 gross (2,960 net) wells. We expect to increase our oil and natural gas liquids reserves over time through our focused drilling program in our core areas and through possible acquisitions.

Improving Results in Our Core Resource Areas

As a result of improved drilling and completion techniques, our initial production, or IP, rates have been steadily increasing. As of May 1, 2013, improvements in our drilling results include: (i) IP‑24 rates for our 11 most recently completed Company-operated horizontal wells in the Marcellus Shale have averaged approximately 9,525 mmcfpd; (ii) (a) IP-24 rates for our five most recently completed third-party-operated one-mile horizontal wells in Divide County, North Dakota have averaged approximately 594 boepd, and (b) IP-24 rates for our five most recently completed third-party-operated two-mile horizontal wells in Divide County, North Dakota have averaged approximately 732 boepd; and (iii) IP-24 rates for our eight most recently completed Company-operated horizontal wells in the Tableland Field in Canada have averaged approximately 358 boepd.

Operational Control Over Significant Portion of Assets

We operate a significant portion of our assets (approximately 80% of our producing wells as of May 1, 2013). Consequently, we have substantial control over the timing, the allocation and the amount of a significant portion of our planned 2013 capital expenditures, which allows us the flexibility to reallocate these expenditures depending on commodity prices, rates of return and prevailing industry conditions. We have continued to demonstrate increasingly robust drilling and completion results in our operated areas as we execute on our strategy.

Experienced Management Teamwith Proven Operating and Acquisition History

Our senior management team, on average, has over 25 years of experience in the oil and gas industry and has extensive experience in managing, financing and operating public oil and gas companies. Magnum Hunter Resources, Inc., founded by Gary C. Evans, our chairman and chief executive officer, in 1985, achieved an average annual internal rate of return to shareholders of 38% during the 15 years it was publicly traded before it was sold to Cimarex Energy Corporation for $2.2 billion in 2005. Additionally, our management team has collectively completed financing transactions and acquisitions in the oil and gas industry totaling billions of dollars, and our key personnel have extensive expertise in the principal operational disciplines in our core unconventional resource plays.

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Our Significant Recent Developments

Eagle Ford Properties Sale

On April 24, 2013, we sold our core properties in the oil window of the Eagle Ford Shale in Gonzales and Lavaca Counties, Texas to an affiliate of Penn Virginia for a total purchase price of $422.1 million, paid to us in the form of $379.8 million in cash (before customary purchase price adjustments) and $42.3 million in Penn Virginia common stock (valued, for purposes of the purchase price calculation, at a price of $4.23 per share). We used the cash portion of the purchase price to repay all our outstanding borrowings under our MHR Senior Revolving Credit Facility and for general corporate purposes.

The properties sold to the Penn Virginia affiliate included approximately 19,000 net Eagle Ford Shale leasehold acres, and our operating and non-operating leasehold working interests in certain existing wells, in Gonzales and Lavaca Counties, Texas. The transaction was structured as a sale by us to the Penn Virginia affiliate of all of the outstanding capital stock of our wholly-owned subsidiary, Eagle Ford Hunter, Inc., or Eagle Ford Hunter. The effective date of the transaction was January 1, 2013.

Prior to the closing of the transaction, Eagle Ford Hunter transferred to Shale Hunter, LLC, one of our wholly-owned subsidiaries, all of the assets and properties held by Eagle Ford Hunter other than the properties in Gonzales and Lavaca Counties purchased by the Penn Virginia affiliate. As a result, as of May 1, 2013, we continued to own (a) approximately 7,000 net Eagle Ford Shale leasehold acres located primarily in Fayette, Lee and Atascosa Counties, Texas, of which approximately 5,100 net acres are also prospective for the development of the Pearsall Shale formation in Atascosa County, and (b) leasehold working interests in certain existing producing, development and test wells located on these properties.

Expansion of Marcellus and Utica Shale Positions

We expanded and intend to further expand our Marcellus Shale and Utica Shale positions through the following transactions completed by, and ongoing and planned drilling operations of, our wholly-owned subsidiary, Triad Hunter, LLC, or Triad Hunter.

Commencement of Development in Utica Shale. During 2013, Triad Hunter plans to drill a minimum of four wells in Washington County and Monroe County, Ohio to test the Utica Shale formation. If the results of these test wells are similar to certain positive test well results recently reported by third party offset operators in the area, Triad Hunter plans to significantly increase its drilling activity in this area during 2014. In connection with this planned test development, Triad Hunter is currently constructing its first Utica Shale drilling pad, which is located in Washington County, Ohio and has been designed to drill up to four horizontal wells. Triad Hunter spud its first Utica Shale test well from this drilling pad in April 2013. We expect to commence a 25 plus stage fracture stimulation of the well in July 2013. After we finish fracing the well, we plan to shut in the well for approximately 30 to 40 days and then begin flow testing the well in August or September 2013.

Triad Hunter is also constructing a Utica Shale drilling pad in Monroe, County, Ohio, designed to drill up to 16 horizontal wells. Triad Hunter plans to drill three additional horizontal wells to the Utica Shale formation from this pad in 2013 under its joint development agreement with Eclipse Resources I, LP described below.

Also, in anticipation of favorable results from these wells, we have commissioned engineering drawings and drilling unit preparations for two additional planned Utica Shale drilling pads, one to be located in Noble County, Ohio, and to be designed for up to 10 horizontal wells, and the other to be located in Washington County, Ohio, and to be designed for up to four horizontal wells.

We currently anticipate that the natural gas production from our Utica Shale wells will be delivered through our Eureka Hunter Gas Gathering System to the Mobley Processing Plant (or other anticipated closer gas processing facilities) for processing.

Eclipse Resources Joint Venture. In January 2013, Triad Hunter entered into joint development and operating agreements with Eclipse Resources I, LP, or Eclipse Resources, pursuant to which the parties agreed to jointly develop a contract area consisting of approximately 1,950 leasehold acres in the Marcellus Shale and Utica Shale in Monroe County, Ohio. Each party owns a 47% working interest in the contract area. Triad Hunter is the operator for the contract area. Eclipse Resources also agreed to dedicate its share of production from the contract area to gathering by our Eureka Hunter Gas Gathering System.

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Virco Acquisition. On November 2, 2012, Triad Hunter acquired all of the outstanding capital stock of privately-held Viking International Resources Co., Inc., or Virco, for a purchase price of approximately $100.8 million, of which $37.3 million was paid in cash and $65.2 million (based on stated liquidation preference) was paid in the form of restricted depositary shares representing shares of the Company’s 8.0% Series E Cumulative Convertible Preferred Stock. The Virco Acquisition added approximately 51,500 net mineral acres located in West Virginia and Ohio to our Appalachian Basin position. The acquired acreage includes approximately 27,000 net acres in the Marcellus Shale, of which 19,000 are located in what we believe to be a very liquids-rich area of Ritchie County, West Virginia and 8,000 are located in Washington and Monroe Counties, Ohio. Specifically, we acquired 7,500 acres in the Ormet area of Monroe County where we were originally a 50/50 joint venture partner with Virco. We intend to increase our drilling activity in the Ormet area during 2013, due in part to positive results from our initial joint venture well. The acquired acreage also includes approximately 9,000 net liquids-rich Utica Shale acres in Ohio and 19,000 net dry Utica Shale acres, a portion of which overlaps our Marcellus Shale acreage. Approximately 98% of the total acquired acreage position is held by shallow production. The Virco Acquisition also provides us with additional volume expansion opportunities in West Virginia and Ohio for our Eureka Hunter Gas Gathering System.

Utica Acreage Acquisition. In February 2012, Triad Hunter acquired leasehold mineral interests located primarily in Noble County, Ohio from a third party for a total purchase price of $24.8 million. The acquired leasehold acreage consisted of approximately 15,500 gross (12,100 net) acres that are prospective for the Utica Shale. Substantially all of this leasehold acreage is held by shallow production. The Utica Acreage Acquisition significantly expanded our acreage position in a strategic region of Ohio, and also provides the opportunity for us to expand the Eureka Hunter Gas Gathering System into this region, which is currently not adequately served by midstream competitors.

Stone Energy Joint Venture. In December 2011, Triad Hunter entered into joint development and operating agreements with Stone Energy Corporation, or Stone Energy, pursuant to which the parties agreed to jointly develop a contract area consisting of approximately 1,925 leasehold acres in the Marcellus Shale in Wetzel County, West Virginia. Each party owns a 50% working interest in the contract area. Stone Energy is the operator for the contract area. Stone Energy also agreed to dedicate its share of production from the contract area to gathering by our Eureka Hunter Gas Gathering System.

Expansion of Williston Basin Position

We expanded our Williston Basin position through the following transactions by our wholly-owned subsidiaries, Bakken Hunter, LLC and Williston Hunter ND, LLC. Our principal strategy is to increase our working interests and the number of Company-operated properties in the Bakken Shale in North Dakota.

Samson Assets Acquisition. On December 20, 2012, Bakken Hunter, LLC, or Bakken Hunter, acquired from Samson Resources Company, or Samson, effective as of August 1, 2012, approximately 20,000 net Williston Basin leasehold acres, and Samson’s operating and non-operating leasehold working interests in certain existing wells, located in Divide County, North Dakota, referred to as the Acquired Samson Assets. The purchase price for the Acquired Samson Assets was $30 million in cash, subject to customary purchase price adjustments. The Acquired Samson Assets include acreage adjacent to our acreage in the Tableland Field in Saskatchewan, Canada, and acquisition of the assets established the Company as an operator in the Bakken Shale in Divide County, North Dakota.

Baytex Assets Acquisition. On May 22, 2012, Bakken Hunter acquired from Baytex Energy USA Ltd., or Baytex, effective as of March 1, 2012, all of Baytex’s non-operating working interest (up to 37%) in certain oil and gas properties and wells located in Divide and Burke Counties, North Dakota, referred to as the Acquired Baytex Assets, within an area subject to an existing operating agreement among Samson, as operator, Baytex and Williston Hunter Inc., a wholly-owned subsidiary of Magnum Hunter. Immediately prior to the acquisition, we owned up to a 10% non-operating working interest in the properties. The purchase price for the Acquired Baytex Assets was $312 million in cash, subject to customary purchase price adjustments. The acquisition increased our non-operating working interests in these properties from up to 10% to up to 47%.

Eagle Operating Assets Acquisition. On March 30, 2012, Williston Hunter ND, LLC acquired from a privately‑held company, Eagle Operating, Inc., or Eagle Operating, effective as of April 1, 2011, all of Eagle Operating’s operating working interest ownership in certain oil and gas leases and wells on approximately 17,500 gross acres located within five counties of the Williston Basin in North Dakota, referred to as the Acquired Eagle Assets. The acquisition increased our working interests in these oil and gas properties from approximately 47% to up to 95% and we assumed operatorship of the properties, thus establishing the Company as an operator in North Dakota. The purchase price for the Acquired Eagle Assets was $53 million, which was paid in the form of $50.9 million in cash and approximately 296,859 shares of our restricted common stock. Eagle Operating retained a variable and depth restricted overriding royalty interest not exceeding 2% on certain of the properties.

Oneok Gas Gathering Arrangement. In March 2012, our wholly-owned subsidiary, Williston Hunter Inc., entered into a gas purchase agreement with Oneok Rockies Midstream, LLC, or Oneok, pursuant to which Oneok is currently constructing a natural gas gathering system and related facilities in North Dakota for the gathering and processing by Oneok of associated natural gas production, including

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associated natural gas production from our oil properties in Divide County, North Dakota dedicated by us to Oneok for this purpose. This arrangement was expanded to cover certain of the Acquired Baytex Assets and the Acquired Samson Assets when we acquired those assets in May and December 2012, respectively.

Midstream Operations

Expansion of Eureka Hunter Gas Gathering System. In the past year, we have significantly expanded our Eureka Hunter Gas Gathering System, completing the construction of approximately 29 miles of additional pipeline. As of May 1, 2013, our Eureka Hunter Gas Gathering System was comprised of a total of approximately 79 miles of completed pipeline, of which approximately 74.3 miles consisted of 20-inch or 16-inch high-pressure steel pipe. As of June 10, 2013, we were flowing approximately 100,000 mcf of natural gas per day through the Eureka Hunter Gas Gathering System.

In January 2013, we extended our Pursley lateral section of the pipeline (which is a 20-inch lateral section extending north from our mainline) under the Ohio River from Wetzel County, West Virginia into Monroe County, Ohio. We continue to construct the pipeline further into Ohio to support the continued development of our Marcellus Shale and Utica Shale acreage in Ohio, as well as acreage of third party producers. In December 2012, we completed the construction of our Lewis-Wetzel lateral section of the pipeline (which is a 20-inch lateral section extending north from our mainline) connecting to our new central compression facility near the community of Carbide in Wetzel County, West Virginia, referred to as our Eureka Carbide Facility. The Eureka Carbide Facility, the initial construction of which was also completed in December 2012, includes a low-pressure natural gas and liquids gathering system, natural gas compression equipment and liquids handling equipment. In November 2012, we completed the construction of our Mobley lateral section of the pipeline (which is a 20-inch lateral section extending east from the Eureka Carbide Facility) connecting to the Mobley Processing Plant. We also completed approximately 2.5 miles of our low-pressure natural gas gathering system extending south from the Eureka Carbide Facility connecting to certain producing wells of Triad Hunter and Stone Energy in Wetzel County, West Virginia.

Commencement of Mobley Gas Processing Operations. In late 2011, Triad Hunter entered into certain midstream services agreements with MarkWest Liberty Midstream & Resources, L.L.C., or MarkWest, pursuant to which MarkWest agreed to provide long-term gas processing and related services for natural gas produced by both Triad Hunter and other producers and gathered through our Eureka Pipeline System. In December 2012, following completion of MarkWest’s 200 mmcfe per day Mobley Processing Plant in Wetzel County, West Virginia, Eureka Pipeline began flowing natural gas production through the Eureka Hunter Gas Gathering System for processing at the Mobley Processing Plant. Eureka Pipeline has supplied and expects to continue to supply the Mobley Processing Plant with both Company and third party natural gas produced primarily from the Marcellus Shale formation. MarkWest also provides natural gas liquids handling and fractionation services for Mobley Processing Plant products at its nearby fractionation facility. These agreements with MarkWest allow Eureka Pipeline to offer third party producers in the Marcellus Shale not only gas gathering services through our Eureka Hunter Gas Gathering System, but also access to natural gas processing at the Mobley Processing Plant. Also, our ability to process our natural gas at the Mobley Processing Plant has provided and is expected to continue to provide us with a significant uplift in the realized price for our liquids-rich gas stream. Effective as of April 2013, we have committed to approximately 95% of the processing capacity of the 200 mmcfe per day Mobley Processing Plant.

ArcLight Investment/Partial Monetization. On March 21, 2012, Magnum Hunter and Eureka Holdings entered into an agreement with Ridgeline Midstream Holdings, LLC, or Ridgeline, an affiliate of ArcLight Capital Partners, LLC, or ArcLight, pursuant to which Ridgeline committed, subject to certain terms and conditions, to invest up to $200 million in Eureka Holdings in exchange for preferred units representing membership interests in Eureka Holdings. This equity commitment facility was established primarily to provide us with funding, as needed, for Eureka Pipeline’s pipeline development capital expenditures and any Eureka Pipeline asset acquisitions, and to allow us to receive distributions representing a return of certain capital we previously invested in Eureka Pipeline. In March and April 2012, Eureka Holdings sold preferred units to Ridgeline for an aggregate cash purchase price of $106.8 million. We received this cash purchase price (a portion of which we used to purchase the assets of TransTex Gas Services, LP described below) and retained approximately $300 million in agreed-upon value of common units in Eureka Holdings, in exchange for the total 25% preferred equity ownership interest in Eureka Holdings we sold to Ridgeline at that time. Since then, Ridgeline has invested an additional $65 million in Eureka Holdings in exchange for preferred units.

On March 7, 2013, Magnum Hunter and Ridgeline entered into an amendment to the operating agreement for Eureka Holdings which, among other things, provides Magnum Hunter a right to make additional capital contributions to Eureka Holdings in conjunction with or alongside additional capital contributions from Ridgeline. As of May 1, 2013, we owned approximately 58.3% and Ridgeline owned approximately 39.5% of the equity ownership of Eureka Holdings.

TransTex Assets Acquisition. On April 2, 2012, Eureka Holdings and an acquisition subsidiary now called TransTex Hunter, LLC, or TransTex Hunter, acquired substantially all of the assets of privately-held TransTex Gas Services, LP, or TransTex Gas Services, for $58.5 million, in the form of $46.0 million in cash and 622,641 common units in Eureka Holdings, representing at that time an approximate 2.8% equity interest in Eureka Holdings. TransTex Hunter now operates the business and assets acquired from TransTex Gas Services. TransTex Hunter is a leading natural gas treating company, with a significant presence in the Eagle Ford Shale and

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the potential for expansion into the Marcellus Shale and Utica Shale. TransTex Hunter is primarily engaged in the business of treating natural gas at the wellhead for third party producers, with a focus on associated natural gas produced from various oil shale plays.

Senior Revolving Credit Facility

Borrowings under our MHR Senior Revolving Credit Facility are subject to a maximum borrowing base derived from the amount of our proved crude oil and natural gas reserves. At January 1, 2012, our MHR Senior Revolving Credit Facility had a borrowing base of $200 million. As of May 1, 2013, the borrowing base under the MHR Senior Revolving Credit Facility was $265 million. Our lenders significantly expanded the MHR Senior Revolving Credit Facility through multiple borrowing base increases over the past 15 months.These borrowing base increases were attributable primarily to our organic proved reserves growth. The borrowing base under the facility reached a high of $375 million during the fourth quarter of 2012, but was also reduced in 2012 pursuant to adjustments made under the facility to take into account the long-term debt we incurred when we issued our Senior Notes in May and December 2012, as described below. The borrowing base under the facility was further reduced in April 2013 due to the reduction in our proved reserves resulting from our Eagle Ford Properties Sale, to the borrowing base level of $265 million as of May 1, 2013.

Common Stock and Senior Notes Offerings

On May 16, 2012, we concurrently closed our underwritten public offering of 35 million shares of our common stock at a public offering price of $4.50 per share and our issuance and sale, in a private placement, of $450 million in aggregate principal amount of our unsecured 9.750% Senior Notes due 2020, referred to as our Senior Notes. The net proceeds of the common stock offering, after deducting underwriting discounts and commissions and estimated offering expenses, were approximately $148.2 million. The net proceeds of the Senior Notes offering, after deducting the initial purchasers' discounts and estimated offering expenses, were approximately $430.4 million. The net proceeds of these concurrent offerings were used in part to repay a portion of the indebtedness outstanding under our MHR Senior Revolving Credit Facility and repay in full a $100 million term loan we obtained from our bank syndicate in September 2011.

On December 18, 2012, we closed an add-on private offering of $150 million in aggregate principal amount of the Senior Notes. The net proceeds of the offering (which included a pricing premium), after deducting initial purchasers' discounts and estimated offering expenses, were approximately $149.9 million. The net proceeds were used to repay a portion of the indebtedness outstanding under our MHR Senior Revolving Credit Facility.

Public Offering of Series D Preferred Stock

On September 12, 2012, we closed an underwritten public offering of 1,050,000 shares of our non-convertible 8.0% Series D Cumulative Preferred Stock (stated liquidation preference of $50.00 per share), referred to as our Series D Preferred Stock, at a public offering price of $44.00 per share. The net proceeds to us, after deducting underwriting discounts and commissions and estimated offering expenses, were approximately $44.1 million.

Public Offering of Depositary Shares Representing Series E Preferred Stock

On December 12, 2012, we closed an underwritten public offering of depositary shares, each representing a 1/1,000th interest in a share of our 8.0% Series E Cumulative Convertible Preferred Stock, referred to as our Depositary Shares and Series E Preferred Stock, respectively, with a stated liquidation preference of $25,000 per share of Series E Preferred Stock, which is equivalent to a stated liquidation preference of $25.00 per Depositary Share. We sold one million Depositary Shares at a public offering price of $23.50 per share. The net proceeds to us, after deducting underwriters’ commissions and estimated offering expenses, were approximately $21.9 million.

The offering was completed to partially cover the purchase price of the Acquired Samson Assets, while also satisfying assurances regarding the stock exchange listing of the Depositary Shares made to the former stockholders of Virco, who received Depositary Shares as a portion of the purchase price we paid when we acquired Virco in November 2012. In connection with the offering, the Depositary Shares were listed for trading on the NYSE MKT.

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2013 Capital Expenditure Budget

Our capital expenditure budget for fiscal year 2013 is currently (a) $300 million for our upstream operations, consisting of approximately $150 million for the Marcellus and Utica Shales and approximately $150 million for the Williston Basin/Bakken Shale, and (b) $100 million for our midstream operations (excluding, in each case, any budgeted amounts for operations that may be acquired pursuant to acquisitions).

We expect that the 2013 capital expenditure budget for our midstream operations will be funded by us and by the third-party equity and non-recourse debt facilities we have obtained for the midstream operations. See "Management's Discussion and Analysis of Financial Condition and Results of Operations" in this annual report for a description of these facilities, including the third-party equity commitment for our midstream operations (under which we have the right to make capital contributions in conjunction with or alongside the capital contributions from the third party).

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 pursue an attractive acquisition opportunity or reallocate capital to projects we believe can generate higher rates of return on capital employed. We also believe in maintaining a strong balance sheet and using commodity price derivatives to mitigate uncontrollable risk. This allows us to be more opportunistic in a lower commodity price environment as well as providing more consistent financial results in the long-term.

Competition

The oil and natural gas industry is highly competitive in all phases. We encounter competition from other oil and natural gas companies, including midstream services companies, in all areas of operation, including the acquisition of leases and properties, the securing of drilling, fracturing and other oilfield services and equipment and, with respect to our midstream operations, the acquisition of commitments from third party producers for the treating and gathering of natural gas. Our competitors include numerous independent oil and natural gas companies and individuals, as well as major international oil companies. Many of our competitors are large, well established companies that have substantially larger operating staffs and greater capital resources than we do.

The prices of our products are controlled by the world oil market and North American natural gas markets. Thus, competitive pricing behavior in this regard is considered unlikely. However, competition in the oil and natural gas exploration industry exists in the form of competition to acquire the most promising properties and obtain the most favorable prices for the costs of drilling and completing wells. Competition for the acquisition of oil and gas properties is intense with many properties available in a competitive bidding process in which we may lack technological information or expertise available to other bidders. Therefore, we may not be successful in acquiring and developing profitable properties in the face of this competition. 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 an efficient manner even 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.”

Our industry is cyclical, and from time to time there is a shortage of drilling rigs, fracture stimulation services, equipment, supplies and qualified personnel. During these periods, the costs and delivery times of rigs, equipment and supplies are substantially greater. If the unavailability or high cost of drilling rigs, equipment, supplies or qualified personnel were particularly severe in the areas where we operate, we could be materially and adversely affected. We believe that there are potential alternative providers of drilling services and that it may be necessary to establish relationships with new contractors as our activity level and capital program grow. However, there can be no assurance that we can establish such relationships or that those relationships will result in increased availability of drilling rigs.

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, completion, 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 or disputes with 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 oil and natural gas, disposing of wastewater produced from drilling operations, transporting crude oil and treating, gathering and processing natural gas. These hazards and risks include fires, natural disasters, explosions, encountering formations with abnormal pressures, blowouts, craterings, pipeline ruptures, oil and wastewater spills and equipment failures, any of which can result in the loss of hydrocarbons, environmental pollution, personal injury claims and 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,

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loss of surface equipment at well locations, business interruption, loss of revenue due to low commodity prices or loss of revenue 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.

We are also subject to risks attendant to our Canadian operations. Some of these additional risks include, but are not limited to, increases in governmental royalties; application of new tax laws (including host-country export, excise and income taxes and U.S. taxes on foreign operations); currency restrictions and exchange rate fluctuations; legal and governmental regulatory requirements; difficulties and costs of staffing and managing international operations; and possible language and cultural differences. Our Canadian operations also may be adversely affected by the laws and policies of the U.S. affecting foreign trade, taxation and investment. In addition, if a dispute arises with respect to our foreign operations, we may be subject to the exclusive jurisdiction of foreign courts or may not be successful in subjecting foreign persons to the jurisdiction of the courts of the U.S.

Governmental Regulation

Our oil and natural gas exploration, development and production activities, and our midstream services activities, are subject to extensive laws, rules and regulations promulgated by federal, state and foreign 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.

Our exploration, development and production activities and our midstream services activities, including the construction, operation and maintenance of wells, pipelines, plants and other facilities and equipment for exploring for, developing, producing, treating, gathering, processing and storing oil, natural gas and other products, are subject to stringent federal, state, local and foreign laws and regulations governing environmental quality, including those relating to oil spills, pipeline ruptures and pollution control, which are constantly changing. Although such laws and regulations can increase the cost of planning, designing, installing and operating such facilities, it is anticipated that, absent the occurrence of an extraordinary event, compliance with existing federal, state, local and foreign laws, rules and regulations governing the release of materials in the environment or otherwise relating to the protection of the environment, will not have a material effect upon our business operations, capital expenditures, operating results or competitive position. See “Item 1A. Risk Factors—Our operations expose us to substantial costs and liabilities with respect to environmental matters.”

We commonly use hydraulic fracturing as part of our operations. Hydraulic fracturing typically is regulated by state oil and natural gas commissions, but the U.S. Environmental Protection Agency, referred to as the EPA, has asserted federal regulatory authority pursuant to the Safe Drinking Water Act over certain hydraulic fracturing activities involving the use of diesel. In addition, legislation has been introduced before Congress to provide for federal regulation of hydraulic fracturing under the Safe Drinking Water Act and to require disclosure of the chemicals used in the hydraulic fracturing process. Several states are also considering implementing, and some states, including Texas, have implemented, new regulations pertaining to hydraulic fracturing, including the disclosure of chemicals used in connection therewith. These existing and any future regulatory requirements may result in additional costs and operational restrictions and delays, which could have an adverse impact on our business, financial condition, results of operations and cash flows. See “Item 1A. Risk Factors—Federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.”

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, or 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. 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 business, financial condition, results of operations and cash flows, and could reduce the demand for our products. 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 natural gas liquids that we produce.”

Formation

We were incorporated in the State of Delaware on June 4, 1997. In 2005, we began oil and gas operations under the name Petro Resources Corporation. In May 2009, we restructured our management team and completely refocused our business strategy, and in July 2009 we changed our name to Magnum Hunter Resources Corporation. The restructured management team includes Gary C. Evans, our chairman and chief executive officer, and Ronald D. Ormand, our executive vice president and chief financial officer. Mr. Evans is the former founder, chairman and chief executive officer of Magnum Hunter Resources, Inc., a company of similar name that was sold to Cimarex Energy Corporation for $2.2 billion in June 2005.

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Employees

As of May 1, 2013, we had approximately 420 full-time employees. None of our employees is represented by a union. Management considers our relations with employees to be very good.

Facilities

Our principal executive offices are located in Houston, Texas, and consist of approximately 15,000 square feet of leased commercial office space. Our lease expires with respect to approximately 9,000 and 6,000 square feet of this space in April 2016 and May 2014, respectively. We also lease approximately 1,600 square feet of additional office space in this building, under a lease that expires in December 2013. We currently sublease this additional space.

Our Triad Hunter offices consist of approximately 4,000 square feet of office space in a commercial office building we own in Marietta, Ohio, and an additional 14,000 square feet of office space in buildings (including portable buildings) we own in Reno, Ohio. We also lease certain field offices in Kentucky and West Virginia.

Our Magnum Hunter Production, Inc. offices consist of approximately 9,100 square feet of leased office space under a lease that expires in 2013, in an office building owned by us in Lexington, Kentucky. Magnum Hunter Production, Inc. also leases a field office and equipment storage yard in Harlan County, Kentucky.

We refer to our properties in North Dakota as our Williston Hunter U.S. properties and our properties in Canada (which include our Bakken/Three Forks Sanish properties in Saskatchewan as well as certain properties we operate in Alberta) as our Williston Hunter Canada properties. Our Williston Hunter U.S. offices consist of approximately 4,500 square feet of leased office space in Denver, Colorado, under a lease that expires in December 2014. Williston Hunter U.S. also leases a field office containing 1,250 square feet of office space in Mohall, North Dakota, under a lease that expires in 2017. Our Williston Hunter Canada offices consist of approximately 8,300 square feet of leased office space in Calgary, Alberta, Canada, under a lease that expires in March 2014.

TransTex Hunter maintains a field office and equipment storage yard on approximately 10 acres of land it owns in Lavaca County, Texas.

Alpha Hunter Drilling maintains a field office and equipment storage yard on approximately 12 acres of land it owns in Gonzalez County, Texas.

We own a commercial office building in Grapevine, Texas containing approximately 10,200 square feet of office space and also lease, currently on a month-to-month basis, approximately 875 square feet of office space in another commercial office building in Grapevine. These offices house our principal accounting, financial reporting, information systems and human resources functions.

Segment Reporting; Major Customers

For information as to the geographic areas and industry segments in which we operate, namely U.S. Upstream, Canadian Upstream, Midstream and Oil Field Services, see "Note 16 -Other Information—Segment Reporting". For information regarding our major customers for fiscal years 2010, 2011 and 2012, see "Note 15 - Major Customers". This information is incorporated in this Item 1 by reference.

Available Information

Our principal executive offices are located at 777 Post Oak Blvd., Suite 650, Houston, Texas 77056. Our telephone number at this office is (832) 369-6986. We file annual, quarterly and current reports, proxy statements and other documents with the SEC under the Exchange Act. The public may read and copy any materials that 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. In addition, the SEC maintains a website that contains reports, proxy and information statements and other information that is electronically filed with the SEC. The public can obtain any documents that we file with the SEC at www.sec.gov.

We also make available free of charge on our website (www.magnumhunterresources.com) our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, any amendments to those reports and our proxy statements filed with or furnished to the SEC under the Exchange Act as soon as reasonably practicable after we file such material with, or furnish it to, the SEC. Information on our website does not constitute part of this or any other report filed with or furnished to the SEC.

Item 1A. RISK FACTORS

The factors described below should be considered carefully in evaluating our Company. 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.

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Risks Related to Our Business

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

The U.S., Canadian and other world economies are slowly recovering from the economic recession that began in 2008. 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 the years preceding the recession. 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 daily 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., Canadian and global economies;

• the actions of certain foreign countries;

• the price and quantity of imports of foreign oil and natural gas;

• 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, or 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 in the future. 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 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, 2012, we had incurred an accumulated deficit of $307.4 million. If we fail to eventually 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.

We rely on liquidity from our credit facilities and equity and debt financings to fund our operations and capital budget, which liquidity may not be available on acceptable terms or at all in the future.

We depend upon borrowings under our credit facilities and the availability of equity and debt financing to fund our operations and planned capital expenditures. Borrowings under our credit facilities could be curtailed or eliminated if (i) we fail to file our Form 10-Q for the quarter ended March 31, 2013 by the lenders' extended deadline of July 12, 2013 or within any extended time period our lenders may in the future provide or (ii) an uncured cross‑default under such facilities results from any uncured “event of default” under the indenture relating to our Senior Notes stemming from our late SEC filings. Further, borrowings under our credit facilities and the availability of equity and debt financing are affected by commodity prices and prevailing economic conditions in our industry and financial, business and other factors, some of which are beyond our control. We cannot predict whether additional liquidity from equity or debt financings beyond our credit facilities will be available or acceptable on our terms, or at all, in the foreseeable future.

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

We have acquired a number of properties since June 2009 and, consequently, a large amount of our focus has been on assimilating the properties, operations and personnel we have acquired into our organization. Accordingly, there is relatively little operating history upon which to judge our business strategy, our management team or our current operations.

We have identified certain weaknesses in our internal controls, which we are remediating, but failure to do so could adversely affect our ability to obtain borrowings and ourcapital raising ability.

In October and November 2012, we identified material weaknesses in our internal controls over financial reporting in connection with (i) our lack of sufficient qualified personnel to design and manage an effective control environment, (ii) our period-end financial reporting process and (iii) our share-based compensation. The first material weakness, the lack of sufficient qualified personnel, resulted in the restatement of the accounting treatment of the preferred units of Eureka Holdings, our commodity and preferred stock embedded derivative liabilities and our loss in derivatives and related disclosures for the three- and six-month periods ended June 30, 2012 that resulted in accounting adjustments to our condensed consolidated financial statements for the three- and nine-month periods ended September 30, 2012. The second material weakness, the lack of effective controls over our period-end financial reporting process, resulted in monthly account reconciliations and monthly and quarterly financial information not being timely prepared and/or reviewed, thereby causing accounting adjustments to our condensed consolidated financial statements for the three- and nine-month periods ended September 30, 2012. The third material weakness, which related to our internal controls over financial reporting relating to our share-based compensation, resulted in inaccuracies in the vesting schedule and journal entries relating to our share-based compensation expense that caused us to restate our general and administrative expense and our share-based compensation disclosures for the three- and six-month periods ended June 30, 2012.

As further described in "Item 9A. Controls and Procedures" in this annual report, we have identified five categories of material weaknesses in our internal controls over financial reporting. The first and second categories generally resemble the three material weaknesses discussed in the above paragraph. The five categories relate to material weaknesses occurring in connection with (i) our failure to maintain an effective control environment given our rapid growth; (ii) our period-end financial reporting process; (iii) our leasehold property costs; (iv) complex accounting issues with respect to complex equity instruments; and (v) income tax accounting.

We have implemented, and continue to implement, measures we believe will effectively address the above-described weaknesses. Some of the measures we have taken include: (i) hiring and replacing resources to implement an effective control environment given our rapid growth, including hiring a new Chief Accounting Officer, corporate-level controllers, regional controllers and managers of internal audit, tax and financial reporting, as well as supplementing management's in-house internal audit and tax functions with the use of a "Big Four" accounting firm; (ii) reorganizing the roles and responsibilities in the accounting and financial reporting processes and implementing additional monitoring and detective controls to remediate the financial reporting material weakness; (iii) implementing additional internal controls with regard to share based-compensation activity; (iv) implementing actions to ensure that there are appropriate effective controls over leasehold property accounts; (v) adding technical staff to assist in the review of complex transactions, including complex equity instruments for financial statement implications; and (vi) engaging a “Big Four” accounting firm to provide advisory services on tax matters. We have also started to implement a more functional and integrated accounting system. To implement the foregoing, among other measures, management has developed a formal remediation plan and time-line and is monitoring the Company's remediation efforts.

Despite our remediation efforts, any failure to adequately address any of these weaknesses could adversely affect the accuracy of our financial statements, our compliance with our reporting obligations under the Exchange Act and our compliance with our debt covenants, and therefore our ability to obtain borrowings and access the capital markets to provide required liquidity.

Our failure to timely file certain periodic reports with the SEC limits our access to the public markets to raise debt or equity capital.

We did not file this annual report on Form 10-K, and we have not yet filed our Form 10-Q for the quarter ended March 31, 2013, within the time frame required by the SEC. Because of these late filings, we may be limited in our ability to access the public markets to raise debt or equity capital, which could prevent us from pursuing transactions or implementing business strategies that would be beneficial to our business. We expect to become current with our SEC reporting obligations upon the filing of our Form 10-Q for the quarter ended March 31, 2013, which we expect to occur within the next 30 days. Until twelve months after the date on which we become current, we will be ineligible to use abbreviated and less costly SEC filings, such as the SEC's Form S-3 registration statement, to register our securities for sale. Further, during such period, we will be unable to use our existing shelf registration statement on Form S-3 or conduct “at-the-market”, or ATM, offerings of our equity securities, which ATM offerings we had conducted on a regular basis with respect to our preferred stock prior to our late SEC filings. We may use Form S-1 to register a sale of our

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securities to raise capital or complete acquisitions, but doing so would likely increase transaction costs and adversely impact our ability to raise capital or complete acquisitions in an expeditious manner.

A pending SEC inquiry and pending third-party litigation may divert the attention of management and other important resources, may expose us to negative publicity and could have a material adverse effect on our business, financial condition, results of operations and cash flows.

As further described in “Item 3. Legal Proceedings,” on April 26, 2013, we were advised by the staff of the SEC Enforcement Division that the SEC had commenced an inquiry into matters disclosed in certain of our SEC filings and press releases, as well as the sufficiency of our internal controls and our decisions to change auditors from Hein & Associates LLP to PricewaterhouseCoopers LLP, or PwC, and from PwC to BDO USA, LLP, among other matters. This inquiry is ongoing and we are cooperating with the SEC in connection with these matters. We may incur significant professional fees and other costs in responding to the SEC inquiry. If the SEC were to conclude that enforcement action is appropriate, we could be required to pay substantial civil penalties and fines. The SEC also could impose other sanctions against us or certain of our current and/or former directors and officers. Any of these events could have a material adverse effect on our business, financial condition, results of operations or cash flows. Further, there is a risk that we may have to restate our historical consolidated financial statements, amend prior filings with the SEC or take other actions not currently contemplated in connection with the SEC inquiry.

As also further described in “Item 3. Legal Proceedings,” several putative stockholders class action complaints (that have since been consolidated, or we anticipate will be consolidated, into two actions) and putative stockholders derivative complaints have been filed against us and/or certain of our directors and officers. We may incur significant professional fees and other costs defending the lawsuits. Depending on the outcome of these lawsuits, we could be required to pay one or more settlements or judgments, which could have a material adverse effect on our financial condition. In addition, our board of directors, management and employees may spend a substantial amount of time on pending litigation, diverting a significant amount of resources and attention that would otherwise be directed toward our operations and implementation of our business strategy, all of which could materially adversely affect our business, financial condition, results of operations or cash flows.

Our indemnification obligations and limitations of our directors' and officers' liability insurance may have a material adverse effect on our financial condition, results of operations and cash flows. Under Delaware law, our certificate of incorporation and bylaws and certain indemnification agreements to which we are a party, we have an obligation to indemnify, or we have otherwise agreed to indemnify, certain of our directors and officers with respect to current and future investigations and litigation, including the matters discussed in “Item 3. Legal Proceedings.” In connection with some of these pending matters, we are required to, or we have otherwise agreed to, advance legal fees and related expenses to certain of our directors and officers and expect to do so while these matters are pending. Certain of these obligations may not be “covered matters” under our directors' and officers' liability insurance, or there may be insufficient coverage available. Further, in the event the directors and officers are ultimately determined to not be entitled to indemnification, we may be unable to recover any amounts we previously advanced to them.

We cannot provide any assurances that the above-described pending claims, or claims yet to arise, will not exceed the limits of our insurance policies, that such claims are covered by the terms of our insurance policies or that our insurance carrier will be able to cover our claims. The insurers also may seek to deny or limit coverage in some or all of these matters. Furthermore, the insurers could become insolvent and be unable to fulfill their obligation to defend, pay or reimburse us for insured claims. Due to these coverage limitations, we may incur significant unreimbursed costs, including to satisfy our indemnification obligations, which may have a material adverse effect on our business, financial condition, results of operations or cash flows.

As a result of the outstanding SEC inquiry and pending class action lawsuits and stockholders derivative litigation, we have been the subject of negative publicity. We believe this negative publicity has adversely affected, and may continue to adversely affect, our stock price and may harm our reputation and our relationships with current and future investors, lenders, customers, suppliers, business partners and employees. As a result, our business, financial condition, results of operations or cash flows may be materially adversely affected.

We have been required to pay penalty interest on our Senior Notes since May 16, 2013 as a result of our failure to complete an exchange offer for our Senior Notes, and we may encounter additional difficulties in completing such exchange offer for our Senior Notes due to our loss of eligibility to incorporate information by reference in our SEC registration statements.

As of May 1, 2013, we had $600 million aggregate principal amount of our Senior Notes outstanding. In connection with the May and December 2012 offerings of the Senior Notes, we entered into registration rights agreements pursuant to which we agreed to complete, by May 16, 2013, a registered exchange offer of the Senior Notes for the same principal amount of a new issue of Senior Notes with substantially identical terms, except the new Senior Notes will be registered and generally freely transferable under the Securities Act. In addition, we agreed to file, under certain circumstances, a shelf registration statement to cover re-sales of the new Senior Notes.

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Due to previously-disclosed delays in connection with the audit of our consolidated financial statements for the fiscal year ended December 31, 2012, we have not yet commenced an exchange offer for the Senior Notes. Accordingly, we have been required to pay additional interest on the Senior Notes since May 16, 2013, and we will be required to pay additional interest until the exchange offer has been completed or the shelf registration statement has been declared effective. Further, we anticipate encountering greater difficulties in completing the exchange offer due to our loss of eligibility to incorporate information by reference into the exchange offer registration statement on Form S-4, which will necessitate any updating of the registration statement to be done through post-effective amendments that are subject to SEC reviews and any accompanying delays. Similarly, a shelf registration statement on Form S-1 will entail similar burdens under the Securities Act, including the filing of post-effective amendments to maintain effectiveness.

Our late SEC filings render unavailable certain covenant exceptions in the indenture governing our Senior Notes and may result in the acceleration of the Senior Notes and the outstanding debt under our credit facilities, as well as the termination of the commitments under our credit facilities, which would have a material adverse effect on our business, financial condition and liquidity.

The indenture governing our Senior Notes and each of our credit facilities, which include our MHR Senior Revolving Credit Facility and Eureka Pipeline's revolver and term loan facilities, require us to file with the SEC and make available to certain parties certain Exchange Act reports and documents, including our Forms 10-K and 10-Q, within specified time periods after their respective SEC filing deadlines. As previously disclosed in our SEC filings, we did not timely file our Form 10-K for the fiscal year ended December 31, 2012 and have not timely filed our Form 10-Q for the fiscal quarter ended March 31, 2013.

The failure to timely file each of these periodic reports constitutes a “default” under the Senior Notes indenture, which results in, among other consequences, the unavailability for the duration of any such default of certain exceptions to restrictive covenants contained therein, including in respect of our ability (i) to make certain restricted payments, including the payment of dividends to our preferred stockholders, (ii) to effect certain mergers or sales of all or substantially all of our assets, (iii) to designate unrestricted subsidiaries under the indenture and (iv) to effect legal and covenant defeasance or satisfaction and discharge of the indenture. Furthermore, if we receive notice from the indenture trustee or a certain percentage of the holders of our Senior Notes of any such default and are unable to timely cure or otherwise obtain waivers of such defaults, each default will constitute an “event of default” under our indenture, which would entitle the holders of our Senior Notes to exercise certain rights and remedies, including accelerating our debt under the outstanding Senior Notes. Additionally, as discussed below, under certain circumstances an event of default under our credit facilities would trigger a cross-default under our indenture.

This annual report was filed within the extended time deadline provided by the lenders under each of our credit facilities. Such lenders also extended the deadline for delivery of our Form 10-Q for the fiscal quarter ended March 31, 2013 to July 12, 2013, and further agreed to waive any cross-defaults that might result from any “default” under our indenture due to our failure to file such Forms 10-K and 10-Q in compliance with the requirements under the indenture. However, if we fail to file such Form 10-Q by the lenders' extended deadline (or within any further extended time period such lenders may provide in the future), such failure would result in a default under the credit facilities, which could result in the termination of the commitments thereunder, as well as the acceleration of any debt outstanding thereunder, and also, subject to limited exceptions, trigger a cross-default under our indenture if the debt outstanding under such credit facilities is accelerated.

As of May 1, 2013, approximately $673.2 million of debt was outstanding under our indenture and various credit facilities. If any debt outstanding under our indenture or credit facilities is declared due and payable, there is no assurance that we would have the cash resources available to repay such accelerated obligations, which would have a material adverse effect on our business, financial condition and liquidity.

Current prohibitions on trading in our securities in certain jurisdictions of Canada will be in effect until we are current with our disclosure filings and successful in our applications to revoke the Canadian cease trade orders currently in effect.

The trading and purchasing of our securities in certain provinces of Canada, including Alberta, Manitoba, Ontario and Quebec, are currently prohibited due to the issuance in each such jurisdiction of a cease trade order to that effect resulting from our failure to file our audited financial statements, annual management's discussion and analysis and certification of annual filings for the year ended December 31, 2012. The securities commission of British Columbia has issued a similar order; however, the order permits a holder who is not an insider or control person of the Company to sell securities of the Company in certain circumstances.

Following the filing of this annual report and a report with respect to our first quarter 2013 financial results and condition on Form 10-Q, we intend to apply to revoke the cease trade orders in Canada currently in effect. Although we currently anticipate having the cease trade orders revoked following the filing of the outstanding reports described above, we may encounter unforeseen impediments during the process which could prolong the continuation of the prohibition on trading of our securities in the applicable Canadian

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jurisdictions. In addition, because we are considered to be a reporting issuer in each province of Canada, in addition to the provinces that have already issued cease trade orders, additional Canadian provinces could issue a cease trade order prior to our becoming current with all our continuous disclosure filings.

The recent financial crisis may have lasting effects on our liquidity, business and financial condition that we cannot predict.

Liquidity is essential to our business. Our liquidity could be substantially negatively affected by an inability to obtain capital in the long-term or short-term debt or equity capital markets or an inability to access bank financing. A prolonged credit crisis and related turmoil in the global financial system would likely materially affect our liquidity, business and financial condition. The economic situation could also adversely affect the collectability of our trade receivables or performance by our suppliers and cause our commodity hedging arrangements to be ineffective if our counterparties are unable to perform their obligations or seek bankruptcy protection.

Failure to successfully integrate our acquired assets and businesses could negatively impact our future business and financial results.

The integration of our acquired assets and businesses may consume a significant amount of our management resources. Further, our entry into a new geographic core area may involve operating conditions and a regulatory environment that may not be as familiar to us as our existing core operating areas. The success of our recent acquisitions will depend, in part, on our ability to realize the anticipated benefits from integrating the acquired assets or businesses with our existing businesses. The integration process may be complex, costly and time-consuming. To realize these anticipated benefits, we must successfully combine the acquired assets or businesses in an efficient and effective manner. If we are not able to achieve these objectives within the anticipated time frame, or at all, the anticipated benefits and cost savings of the acquisitions may not be realized fully, or at all, or may take longer to realize than expected.

Our Canadian operations subject us to foreign laws and regulations and additional operating risks, including currency fluctuations, which could impact our financial position and results of operations.

Upon our acquisition of NuLoch Resources Inc. in May 2011, we expanded our operations into portions of Canada, which expose us to a new regulatory environment and risks from foreign operations. Some of these additional risks include, but are not limited to:

• increases in governmental royalties;

• application of new tax laws (including host-country export, excise and income taxes and U.S. taxes on foreign operations);

• currency restrictions and exchange rate fluctuations;

• legal and governmental regulatory requirements;

• difficulties and costs of staffing and managing international operations; and

• possible language and cultural differences.

Our Canadian operations also may be adversely affected by the laws and policies of the U.S. affecting foreign trade, taxation and investment. In addition, if a dispute arises with respect to our foreign operations, we may be subject to the exclusive jurisdiction of foreign courts or may not be successful in subjecting foreign persons to the jurisdiction of the courts of the U.S.

Our operations require significant amounts of capital and additional financing may be necessary for us to continue our exploration, development and midstream activities, including meeting certain drilling obligations under our existing lease agreements and expanding our pipeline facilities.

Our cash flow from our reserves and midstream operations may not be sufficient to fund our ongoing activities at all times. From time to time, we may require additional financing in order to carry out our oil and gas acquisitions and exploration and development activities and our midstream activities. Failure to obtain such financing on a timely basis could cause us to forfeit our interest in certain properties as a result of not fulfilling our existing drilling commitments. Certain of our undeveloped leasehold acreage is subject to leases that will expire unless production is established or we meet certain capital expenditure and drilling requirements. If our revenues from our reserves decrease as a result of lower oil and natural gas prices or otherwise, it will affect our ability to expend the necessary capital to replace our reserves or to maintain our current production. In addition, capital constraints could limit our ability to build and expand our gas gathering pipeline system. If our cash flow from operations is not sufficient to satisfy our capital expenditure requirements, there can be no assurance that additional debt or equity financing will be available to meet these requirements or available to us on favorable terms.

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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 gathering and transportation 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 transportation infrastructure. Our ability to market our production depends in substantial part on the availability and capacity of pipeline gathering and transportation systems, processing facilities, terminals and rail and truck transportation 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 Marcellus Shale, Utica Shale, Bakken Shale, Eagle Ford Shale and Pearsall 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 or may be planned for the Marcellus Shale, Utica Shale, Bakken Shale, Eagle Ford Shale and Pearsall Shale areas may not occur for lack of financing. In addition, capital constraints could limit our ability to build gathering systems, such as our Eureka Hunter Gas Gathering System, necessary to gather our gas to deliver 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.

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 of our production. 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.

Shortages of equipment, services and qualified personnel could reduce our cash flow and adversely affect results of operations.

The demand for qualified and experienced field personnel to drill wells and conduct field operations, geologists, geophysicists, engineers, pipeline operators, oil and natural gas marketers and other professionals in the oil and natural gas industry can fluctuate significantly, often in correlation with oil and natural gas prices and activity levels in certain regions where we are active, causing periodic shortages. During periods of high oil and gas prices, we have experienced shortages of equipment, including drilling rigs and completion equipment, as demand for rigs and equipment has increased along with higher commodity prices and increased activity levels. In addition, there is currently a shortage of hydraulic fracturing and wastewater disposal capacity in many of the areas in which we operate. Higher oil and natural gas prices generally stimulate increased demand and result in increased prices for drilling rigs, crews and associated supplies, oilfield equipment and services, pipe and other midstream services equipment and qualified personnel in exploration, production and midstream operations. These types of shortages or price increases could significantly decrease our profit margin, cash flow and operating results and/or restrict or delay our ability to drill wells, construct gathering pipelines and conduct other operations that we currently have planned or budgeted, causing us to miss our forecasts and projections.

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

We do not operate all the properties in which we have 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:

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• the nature and timing of the operator’s drilling and other activities;

• the timing and amount of required capital expenditures;

• the operator’s geological and engineering expertise and financial resources;

• the approval of other participants in drilling wells; and

• the operator’s selection of suitable technology.

NGAS Resources, Inc. conducted part of its operations through private drilling partnerships, and, following our acquisition of NGAS in April 2011, we have sponsored two private drilling partnerships, and plan to sponsor additional drilling and/or income partnerships, which subject us to additional risks that could have a material adverse effect on our financial position and results of operations.

NGAS conducted a portion of its operations through private drilling partnerships with third parties. Following our acquisition of NGAS, our Magnum Hunter Production, Inc. subsidiary, as sponsor, has completed two private drilling partnerships and plans to sponsor an additional private drilling and/or income partnership or partnerships in 2013. Under our partnership structure, proceeds from the private placement of interests in each investment partnership, together with the sponsor’s capital contribution, are contributed to a separate joint venture or “program” that the sponsor forms with that partnership to conduct drilling or property operations. These NGAS historical drilling partnerships and the Magnum Hunter Production, Inc. sponsored drilling partnerships expose us to additional risks that could negatively affect our financial condition and results of operations. These additional risks include risks relating to regulatory requirements relating to the sale of interests in the investment partnerships, risks relating to the governmental regulation of Energy Hunter Securities, Inc., our wholly-owned broker-dealer subsidiary, risks relating to potential challenges to tax positions taken by the investment partnerships, risks relating to disagreements with partners in the investment partnerships and risks relating to the general liability of Magnum Hunter Production, Inc., in its capacity as general partner of the investment partnerships and program partnerships. Also, our failure to continue these drilling and/or income partnerships could adversely affect our ability to transact the business that is the subject of such partnerships, which would in turn negatively affect our financial condition and results of operations.

Our exploration, development and midstream 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 very 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, gathering, processing and acquisition of, oil and natural gas reserves and production. To date, we have financed capital expenditures primarily with proceeds from bank borrowings, cash generated by operations and proceeds from public (including "at-the-market", or ATM) offerings of our preferred stock, private offerings of our Senior Notes, the private equity commitment of the ArcLight affiliate and, to a lesser extent, the public (including years-past ATM) offerings of our common stock. However, as a result of our late SEC filings, we are unable to conduct ATM offerings of our equity securities, until we again become eligible to use the SEC's short-form registration statement on Form S-3, and our ability to access the capital markets is therefore restricted.

We intend to finance our future capital expenditures with a combination of proceeds from asset sales, cash flow from operations, current and new financing arrangements with our banks and, to a lesser extent, the possible sales of common and preferred equity. However, 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 our wells;

• the prices at which oil, natural gas and natural gas liquids are sold;

• our ability to acquire, locate and produce new reserves; and

• our ability to obtain commitments from third-party producers for the gathering of their natural gas production through our Eureka Hunter Gas Gathering System and for the treating of their natural gas production by our natural gas treating operations.

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, or could prevent us from expanding, maintaining and operating our pipeline facilities. Also, our MHR Senior Revolving Credit Facility and the indenture governing our Senior Notes contain various covenants that restrict our ability to, among other things, incur indebtedness and issue preferred stock, grant liens on our assets, make certain restricted payments, including

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dividends on our common and preferred stock, change the nature of our business, acquire or make expenditures for oil and gas properties outside of the U.S. and Canada, acquire certain assets or businesses or make certain asset sales, dispose of all or substantially all our assets or enter into mergers, consolidations or similar transactions, make investments, loans or advances, enter into transactions with affiliates, create new subsidiaries and enter into certain derivative transactions.

Further, our late SEC filings will make it more difficult to access the capital markets and could affect our ability to utilize our credit facilities. See “Risk Factors - Our late SEC filings may render unavailable certain covenant exceptions in our Senior Notes indenture, result in the acceleration of the Senior Notes and the outstanding debt under our credit facilities, as well as the termination of the commitments thereunder, which would have a material adverse effect on our business, financial condition and liquidity.”

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. For example, we maintain (i) comprehensive general liability insurance, (ii) employer’s liability and workers' compensation insurance, (iii) automobile liability insurance, (iv) environmental insurance, (v) property insurance, (vi) directors' and officers' insurance, (vii) control of well insurance, (viii) pollution insurance and (ix) umbrella/excess liability insurance. We do not carry business interruption insurance. We may elect not to carry, or may cease 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 under insured events could materially and adversely affect our business, financial condition, results of operations and cash flows. 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.

Our midstream activities are subject to all of the operating risks associated with constructing, operating and maintaining pipelines and related equipment and natural gas treating equipment, including the possibility of pipeline leaks, breaks and ruptures, pipeline damage due to natural hazards, such as ground movement and weather, equipment failures, explosions, fires, accidents and personal injuries and death.

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 business, financial condition, results of operations and cash flows.

We are dependent upon contractor, consultant and partnering arrangements.

We had a total of approximately 420 full-time employees as of May 1, 2013. Despite this number of employees, we expect that we will continue to require the services of independent contractors and consultants to perform various services, including professional services such as 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 leasing. Our dependence on contractors, consultants and third-party 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 could be materially adversely affected.

Our business may suffer if we lose key personnel.

Our operations depend on the continuing efforts of our executive officers, including specifically Gary C. Evans, our chairman and chief executive officer, and other senior management. Our business or prospects could be adversely affected if any of these persons

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do not continue in their management role with us and we are unable to attract and retain qualified replacements. Additionally, we do not presently carry key person life insurance for any of our executive officers or senior management.

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 analysis, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations. 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.

We may incur losses as a result of title deficiencies.

We purchase and acquire from third parties or directly from the mineral fee owners certain oil and gas leasehold interests and other real property interests upon which we will perform our drilling and exploration activities. The existence of a title deficiency can significantly devalue an acquired interest or render a lease worthless and can adversely affect our results of operations and financial condition. As is customary in the oil and gas industry, we generally rely upon the judgment of oil and gas lease brokers or internal or independent landmen who perform the field work in examining records in the appropriate governmental offices and abstract facilities before attempting to acquire or place under lease a specific mineral interest and before drilling a well on a leased tract. The failure of title may not be discovered until after a well is drilled, in which case we may lose the lease and the right to produce all or a portion of the minerals under the property.

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, treating and gathering third-party natural gas production 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, evaluate, bid for and purchase a greater number of properties and prospects and establish and maintain more diversified and expansive

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midstream services 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 an efficient manner even in a highly competitive environment. We may not be able to compete successfully in the future in acquiring prospective reserves, developing reserves, marketing hydrocarbons, offering midstream services, attracting and retaining quality personnel and raising additional capital.

We have limited or relatively limited experience in drilling wells to the Marcellus Shale, Utica Shale, Bakken Shale/Three Forks Sanish, Eagle Ford Shale and Pearsall Shale formations and limited information regarding reserves and decline rates in these areas. Wells drilled to these areas are more expensive and more susceptible to mechanical problems in drilling and completion techniques than wells in conventional areas.

We have limited or relatively limited experience in the drilling and completion of Marcellus Shale, Utica Shale, Bakken Shale/Three Forks Sanish, Eagle Ford Shale and Pearsall Shale formation wells, including limited horizontal drilling and completion experience. Other operators in these 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 in these areas due to their limited histories. The wells drilled in Marcellus Shale, Utica Shale, Bakken Shale/Three Forks Sanish, Eagle Ford Shale and Pearsall Shale formations are primarily horizontal and require more artificial stimulation, which makes them more expensive to drill and complete. The wells also are 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 formations will be more extensive and complicated than fracturing geological formations in conventional areas of operation.

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 and development. 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.

New technologies may cause our current exploration, development 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 new 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.

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

As of May 1, 2013, our total outstanding indebtedness was approximately $673.2 million. This indebtedness consisted primarily of borrowings under the the indenture governing our Senior Notes and Eureka Pipeline’s term loan credit facility. Our principal debt facilities are described under the “Management’s Discussion and Analysis of Financial Condition and Results of Operations” section of this annual report.

We will incur additional debt from time to time, and such borrowings may be substantial. Our debt could have material adverse consequences to us, including the following:

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

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

• 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, acquisitions and general working capital;

• 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; and

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

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Our failure to service any such debt or to comply with the applicable debt covenants could result in a default under the related debt agreement, and under any other debt agreement or any commodity derivative contract under which such default is a cross-default, which could result in the acceleration of the payment of such debt, loss of our ownership interests in the secured properties, early termination of the commodity derivative contract (and an early termination payment obligation) and/or otherwise materially adversely affect our business, financial condition and results of operations.

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.

Product price derivative contracts may expose us to potential financial loss.

To reduce our exposure to fluctuations in the prices of oil and natural gas, we currently and will likely continue to enter into derivative contracts to economically hedge a portion of our oil and natural gas production. Derivative contracts expose us to risk of financial loss in some circumstances, including when:

• production is less than expected;

• the counterparty to the derivative contract defaults on its contract obligations; or

• there is a change in the expected differential between the underlying price in the derivative contract and actual prices received.

In addition, these derivative contracts may limit the benefit we would receive from increases in the prices for oil and natural gas. Under the terms of our MHR Senior Revolving Credit Facility, the percentage of our total production volumes with respect to which we are allowed to enter into derivative contracts is limited, and we therefore retain the risk of a price decrease for our remaining production volumes.

Also, our failure to service our debt or to comply with our debt covenants could result in a default under the applicable debt agreement, and therefore a default under any of our derivative contracts under which such debt default is a cross-default, which could result in the early termination of the derivative contracts (and early termination payment obligations) and/or otherwise materially adversely affect our business, financial condition and results of operations.

Information as to our derivatives activities is set forth in the notes to our financial statements contained in our annual and quarterly reports that we file with the SEC on Forms 10-K and 10-Q.

Write-downs of the carrying values of our oil and natural gas properties 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 and preferred stock and our Senior Notes.

We account for our crude oil and natural gas 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 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. Future wells are drilled that target geological structures that are both developmental and exploratory in nature. A subsequent allocation of costs is then 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.

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 value. Any such charge will not affect our cash flow from operating activities, but will reduce our earnings and shareholders’ equity. When evaluating our properties, we

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are required to test for potential write-downs at the lowest level for which identifiable cash flows are largely independent of the cash flows of other assets, which is typically on a field by field basis.

We incurred an impairment charge in 2011 related to certain proved oil and gas properties acquired as part of our acquisition of NGAS totaling $21.8 million due to a significant decline in natural gas prices at December 31, 2011. Impairment of proved oil and gas properties is calculated on a field by field basis under the successful efforts accounting method, and this 2011 impairment was recorded based upon the estimated fair value of a specific field when the undiscounted reserve value of the field was less than the net capitalized cost of the field at December 31, 2011. Fair value was determined by calculating the present value of future net cash flows using NYMEX prices in effect during February 2012.

During 2011, we also incurred abandonment charges of $306,000 and $802,000 due to the expiration of leases covering certain undeveloped acreage in our Eagle Ford Shale and Appalachian Basin regions, respectively, that we chose not to develop.

During the year ended December 31, 2012, we incurred $43.8 million and $70.6 million of pre-tax non-cash abandonment and impairment charges, respectively, to reduce the carrying value of our unproved properties. The abandonment charges of $33.6 million and $10.2 million related to the expiration of leases covering acreage that we chose not to develop in the Williston and Appalachian Basins, respectively. Impairment charges of $62.2 million, $7.0 million and $1.4 million were related to certain of our properties in the Williston Basin, Appalachian Basin and south Texas, respectively.

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 oil or gas prices subsequently 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 further impairments of the book values associated with oil and gas properties. Accordingly, there is a risk that we will be required to further write down the carrying value of our oil and gas properties, which would reduce our earnings and shareholders’ equity.

Restrictive covenants in our credit facilities and the indenture governing our Senior Notes may restrict our ability to pursue our business strategies.

Our MHR Senior Revolving Credit Facility and the indenture governing our Senior Notes contain certain covenants that, among other things, restrict our ability to, with certain exceptions:

• incur indebtedness and issue preferred stock;

• grant liens on our assets;

• make certain restricted payments, including payment of dividends on our outstanding common and preferred stock;

• change the nature of our business;

• acquire or make expenditures for oil and gas properties outside of the U.S. and Canada;

• acquire certain assets or businesses or make certain asset sales;

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

• make investments, loans or advances;

• enter into transactions with affiliates;

• create new subsidiaries; and

• enter into certain derivatives transactions.

Our MHR Senior Revolving Credit Facility also requires us to satisfy certain financial covenants, including maintaining:

• a ratio of earnings before interest, taxes, depreciation, amortization and exploration expenses, or EBITDAX, to interest expense of not less than 2.5 to 1.0;

• a ratio of total debt to EBITDAX of not more than (i) 4.75 to 1.0 for the fiscal quarter ended December 31, 2012, (ii) 4.50 to 1.00 for the fiscal quarter ended March 31, 2013, (iii) 4.25 to 1.0 for the fiscal quarter ending June 30, 2013 and (iv) 4.25 to 1.0 for the fiscal quarter ending September 30, 2013 and for each fiscal quarter ending thereafter, unless, in the case of this clause (iv) only, a “material asset sale” shall have occurred during any such fiscal quarter in which case the ratio of total debt to EBITDAX shall not exceed 4.0 to 1.0 for such fiscal quarter. A “material asset sale” is any asset sale resulting in the receipt of net cash proceeds in excess of $15 million, other than asset sales made in the ordinary course of the Company’s and its restricted subsidiaries’ partnership drilling programs; and

• a ratio of consolidated current assets to consolidated current liabilities of not less than 1.0 to 1.0.

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Eureka Pipeline’s revolving and term loan credit facilities also require Eureka Pipeline and its subsidiaries to comply with certain covenants, including financial covenants.

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 or alternative sources of financing or reduce our expenditures. We cannot assure you that such waivers, amendments or alternative financings could be obtained or, if obtainable or obtained, would be on terms acceptable or favorable to us.

Our principal debt agreements are described under the “Management’s Discussion and Analysis of Financial Condition and Results of Operations” section of this annual report.

Eureka Holdings has the right, subject to certain conditions, to obtain equity financing from Ridgeline, an Arclight affiliate, but if the conditions to any future purchases of preferred units of Eureka Holdings in connection with the Ridgeline investment are not met, then Eureka Holdings will not be able to obtain additional funds from Ridgeline, which may adversely affect the operations of Eureka Pipeline and its subsidiaries.

Pursuant to the Series A Convertible Preferred Unit Purchase Agreement among Magnum Hunter, Eureka Holdings and Ridgeline, referred to as the Unit Purchase Agreement, Ridgeline committed, subject to certain conditions, to purchase up to $200 million of preferred units of Eureka Holdings. As of May 1, 2013, Eureka Holdings had sold preferred units to Ridgeline for an aggregate purchase price of $171.8 million, and, as permitted by the EH Operating Agreement described below, had issued additional pay-in-kind preferred units to Ridgeline in lieu of approximately $6.2 million of cash distributions otherwise owed to Ridgeline in respect of its outstanding preferred units.

Eureka Holdings’ ability to obtain additional funds from Ridgeline is subject to the satisfaction of certain conditions to Ridgeline’s obligation to purchase preferred units as set forth in the Unit Purchase Agreement. These conditions include, among others, that (i) the proceeds be used for certain approved capital expenditures, midstream growth projects and/or acquisitions (or for any other purposes agreed to by Ridgeline) and (ii) no defaults or material adverse events have occurred. If these conditions are not met, then Eureka Holdings will not be able to obtain additional funds from Ridgeline. In such event, the business, financial condition and results of operations of Eureka Pipeline and its subsidiaries may be adversely affected.

There are restrictive covenants, mandatory distribution requirements and other provisions in the Ridgeline investment documents that may restrict our ability to pursue our business strategies with respect to Eureka Holdings, Eureka Pipeline and TransTex Hunter.

The Amended and Restated Limited Liability Company Agreement of Eureka Holdings, referred to as the EH Operating Agreement, contains certain covenants that, among other things, restrict the ability of Eureka Holdings and its subsidiaries, including Eureka Pipeline and TransTex Hunter, to, with certain exceptions:

• incur funded indebtedness, whether direct or contingent;

• issue additional equity interests;

• pay distributions to its owners, or repurchase or redeem any of its equity securities;

• make any material acquisitions, dispositions or divestitures; or

• enter into a sale, merger, consolidation or other change of control transaction.

Under the EH Operating Agreement, the holders of preferred units of Eureka Holdings are entitled to receive an annual distribution of 8%, payable quarterly. Through and including the quarter ended March 31, 2013, the board of directors of Eureka Holdings could elect to pay up to 75% of any such distribution in kind (i.e., in additional preferred units), in lieu of cash. For the quarter ending June 30, 2013 through and including the quarter ending March 31, 2014, the board of directors of Eureka Holdings may elect to pay up to 50% of any such distribution in kind. Thereafter, all distributions to Ridgeline relating to the preferred units will be paid solely in cash.

In addition to the required quarterly distributions of accrued preferred return on the preferred units, the EH Operating Agreement also (i) gives Eureka Holdings the right, at any time on or after the fifth anniversary of the closing of the initial Ridgeline investment, to redeem all, but not less than all, of the outstanding preferred units, and (ii) gives Ridgeline the right, at any time on or after the eighth anniversary of the closing of the initial Ridgeline investment, to require Eureka Holdings to redeem all, but not less than all, of the outstanding preferred units. If Eureka Holdings fails to meet its redemption obligations under clause (ii) above, then Ridgeline will have the right to assume control of the board of directors of Eureka Holdings and, at its option, to cause Eureka Holdings and/or its other owners to enter into a sale, merger or other disposition of Eureka Holdings or its assets (on terms acceptable to Ridgeline).

Further, pursuant to the terms of the EH Operating Agreement, the number and composition of the board of directors of Eureka Holdings may change over time based on Ridgeline’s percentage ownership interest in Eureka Holdings (after taking into account any additional purchases of preferred units) or the failure of Eureka Holdings to satisfy certain performance goals by the third anniversary of the closing of the initial Ridgeline investment (or as of any anniversary after such date). The board of directors of

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Eureka Holdings is currently composed of a majority of members appointed by Magnum Hunter. Subject to the rights described above, the board of directors of Eureka Holdings may in the future be composed of an equal number of directors appointed by Magnum Hunter and Ridgeline or, in certain cases, of a majority of directors appointed by Ridgeline.

The EH Operating Agreement originally contained a requirement that Ridgeline have an exclusive first right to fund up to 100% of Eureka Holdings’ funding requirements, subject to certain exceptions. On March 7, 2013, Magnum Hunter and Ridgeline entered into an amendment to the EH Operating Agreement which, among other things, provides Magnum Hunter a right to make additional capital contributions to Eureka Holdings in conjunction with or alongside additional capital contributions from Ridgeline.  Accordingly, Magnum Hunter contributed $30 million to Eureka Holdings on March 7, 2013, followed by Ridgeline contributing $20 million during April 2013.  Further, the agreement (as amended) provides that the next $70.5 million of additional capital contributions must be made 60% by Magnum Hunter and 40% by Ridgeline in order for each party to maintain its existing ownership percentage interest in Eureka Holdings.

If a change of control of Magnum Hunter occurs at any time prior to a qualified public offering (as defined in the EH Operating Agreement) of Eureka Holdings, Ridgeline will have the right under the terms of the EH Operating Agreement to purchase sufficient additional preferred units in Eureka Holdings so that it holds up to 51.0% of the equity ownership of Eureka Holdings.

The EH Operating Agreement also contains (i) preferred unit conversion rights in favor of Ridgeline, whereby it may convert its preferred units into common units of Eureka Holdings, (ii) transfer restrictions on Magnum Hunter’s ownership interests in Eureka Holdings (subject to certain exceptions), (iii) certain pre-emptive rights, rights of first refusal and co-sale rights in favor of Ridgeline and (iv) certain Securities Act registration rights in favor of Ridgeline.

These restrictive covenants, mandatory distribution requirements and other provisions in the Ridgeline investment documents may restrict our ability to pursue our business strategies with respect to Eureka Holdings, Eureka Pipeline and TransTex Hunter.

Magnum Hunter’s obligations under the MHR Senior Revolving Credit Facility are secured by substantially all of its assets and Eureka Pipeline’s obligations under its two credit facilities are secured by substantially all of its assets; Magnum Hunter's obligations under its Senior Notes indenture are guaranteed by certain of its domestic subsidiaries; any failure to meet these debt obligations could adversely affect our business, operations and financial condition.

Certain of our subsidiaries, including PRC Williston, LLC, Triad Hunter, LLC, Eagle Ford Hunter, Inc., Magnum Hunter Production, Inc., NGAS Hunter, LLC, Williston Hunter Canada, Inc., Williston Hunter, Inc., Williston Hunter ND, LLC, Bakken Hunter, LLC and Viking International Resources Co., Inc., have each guaranteed the performance of Magnum Hunter’s obligations under the MHR Senior Revolving Credit Facility. Magnum Hunter’s obligations under this credit facility have also been collateralized through the grant of a first priority lien on substantially all of the assets held by Magnum Hunter and these restricted subsidiaries.

Eureka Pipeline’s obligations under its revolving and term loan credit facilities have been guaranteed by Eureka Pipeline’s subsidiaries, and have been collateralized through the grant of first and second priority liens on substantially all of the assets held by Eureka Pipeline and its subsidiaries and the pledge of the equity of Eureka Pipeline owned by Eureka Holdings. An event of default under either of these two credit facilities will constitute an event of default under the other. The Eureka Pipeline credit facilities are non-recourse to Magnum Hunter and its restricted subsidiaries under the MHR Senior Revolving Credit Facility. However, an event of default under the MHR Senior Revolving Credit Facility which results in the acceleration of the outstanding debt under that facility will constitute an event of default under the Eureka Pipeline credit facilities.

Magnum Hunter’s obligations under its Senior Notes indenture are unsecured but are guaranteed by certain of its domestic subsidiaries that also guarantee its obligations under the MHR Senior Revolving Credit Facility. In addition, events of default under the indenture governing the Senior Notes include certain defaults under other agreements of Magnum Hunter and its subsidiaries for borrowed money, which agreements currently include the MHR Senior Revolving Credit Facility.

These debt obligations may be further collateralized through asset pledges by and/or guaranteed by certain future subsidiaries of Magnum Hunter or Eureka Pipeline, as applicable.

Our ability to meet these debt obligations 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 any such debt or to comply with the applicable debt covenants could result in a default under the related debt agreement, and under any other debt agreement or any commodity derivative contract under which such default is a cross-default, which could result in the acceleration of the payment of such debt, loss of our ownership interests in the secured properties, early termination of the commodity derivative contract (and an early termination payment obligation) and/or otherwise materially adversely affect our business, financial condition and results of operations.

We are subject to complex federal, state, local and foreign laws and regulations, including environmental laws, which could adversely affect our business.

Exploration for and development, exploitation, production, processing, gathering, transportation and sale of oil and natural gas in the U.S. and Canada are subject to extensive federal, state, local and foreign laws and regulations, including complex tax laws and

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environmental laws and regulations. Existing laws or regulations, as currently interpreted or reinterpreted in the future, or future laws, regulations or incremental taxes and fees, could harm our business, results of operations and financial condition. We may be required to make large expenditures to comply with environmental and other governmental regulations. Energy Hunter Securities, Inc., one of our wholly-owned subsidiaries, is also subject to the rules and regulations promulgated by the Financial Industry Regulatory Authority in connection with its broker-dealer activities relating to our private drilling and/or income partnership programs.

It is possible that new taxes on our industry could be implemented and/or tax benefits could be eliminated or reduced, reducing our profitability and available cash flow. In addition to the short-term negative impact on our financial results, such additional burdens, if enacted, would reduce our funds available for reinvestment and thus ultimately reduce our growth and future oil and natural gas production.

Matters subject to regulation include oil and gas production and saltwater disposal operations and our processing, handling and disposal of hazardous materials, such as hydrocarbons and naturally occurring radioactive materials, discharge permits for drilling operations, spacing of wells, environmental protection and taxation. We could incur significant costs as a result of violations of or liabilities under environmental or other laws, including third-party claims for personal injuries and property damage, reclamation costs, remediation and clean-up costs resulting from oil spills and pipeline leaks and ruptures and discharges of hazardous materials, fines and sanctions, and other environmental damages.

Certain U.S. 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.

Congress has recently considered, is considering, and may continue to consider, legislation that, if adopted in its proposed or similar form, would deprive some companies involved in oil and natural gas exploration and production activities of certain U.S. federal income tax incentives and deductions currently available to such companies. These changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for certain domestic production activities, and (iv) an extension of the amortization period for certain geological and geophysical expenditures.

It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could become effective and whether such changes may apply retroactively. Although we are unable to predict whether any of these or other proposals will ultimately be enacted, the passage of any legislation as a result of these proposals or any other similar changes in U.S. federal income tax laws could eliminate or postpone certain tax deductions that are currently available to us, and any such change could negatively affect our financial condition and results of operations.

Our ability to use net operating loss carry-forwards to offset future taxable income may be subject to certain limitations.

At December 31, 2012, we had net operating loss carry-forwards of approximately $531 million that expire in varying amounts through 2032. However, changes in the ownership of our stock (including certain transactions involving our stock that are outside of our control) could cause an “ownership change” within the meaning of Section 382 of the Internal Revenue Code of 1986, as amended, referred to as the Internal Revenue Code, which may significantly limit our ability to utilize our net operating loss carry-forwards. To the extent an ownership change has occurred or were to occur in the future, it is possible that the limitations imposed on our ability to use pre-ownership change losses could cause a significant net increase in our U.S. federal income tax liability and could cause U.S. federal income taxes to be paid earlier than otherwise would be paid if such limitations were not in effect.

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

Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, sand and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production. We commonly use hydraulic fracturing as part of our operations. Hydraulic fracturing typically is regulated by state oil and natural gas commissions, but the EPA has asserted federal regulatory authority pursuant to the Safe Drinking Water Act over certain hydraulic fracturing activities involving the use of diesel. In addition, legislation has been introduced before Congress to provide for federal regulation of hydraulic fracturing under the Safe Drinking Water Act and to require disclosure of the chemicals used in the hydraulic fracturing process. Several states are also considering implementing, and some states, including Texas, have implemented, new regulations pertaining to hydraulic fracturing, including the disclosure of chemicals used in connection therewith. For example, Texas recently enacted a law that requires hydraulic fracturing operators to disclose the chemicals used in the fracturing process on a well-by-well basis. Further, various municipalities in several states, including Pennsylvania, West Virginia and Ohio, have passed ordinances which seek to prohibit hydraulic fracturing. We believe that we follow applicable standard industry practices and legal requirements for groundwater protection in our hydraulic fracturing activities. Nonetheless, if new or more stringent federal, state or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development or production activities, and perhaps even be precluded from drilling wells.

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In addition, certain governmental reviews are either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices, and a committee of the U.S. House of Representatives has conducted an investigation of hydraulic fracturing practices. The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, with final results expected to be released in late 2014. Moreover, the EPA is developing effluent limitations for the treatment and discharge of wastewater resulting from hydraulic fracturing activities and plans to propose these standards by 2014. Other governmental agencies, including the U.S. Department of Energy and the U.S. Department of the Interior, are evaluating various other aspects of hydraulic fracturing. These ongoing or proposed studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the federal Safe Drinking Water Act or other regulatory mechanisms.

In April 2012, the EPA issued regulations specifically applicable to the oil and gas industry that will require operators to significantly reduce volatile organic compounds, or VOC, emissions from natural gas wells that are hydraulically fractured through the use of “green completions” to capture natural gas that would otherwise escape into the air. The EPA also issued regulations that establish standards for VOC emissions from several types of equipment at natural gas well sites, including storage tanks, compressors, dehydrators and pneumatic controllers, as well as natural gas gathering and boosting stations, processing plants, and compressor stations. In March 2013, the EPA proposed updates to these VOC performance standards to clarify the requirements for storage tanks used in crude oil and natural gas production.

To our knowledge, there has been no contamination of potable drinking water, or citations or lawsuits claiming such contamination, arising from our hydraulic fracturing operations. We do not have insurance policies in effect that are intended to provide coverage for losses solely related to hydraulic fracturing operations; however, we believe our general liability and excess liability insurance policies would cover third-party claims related to hydraulic fracturing operations and associated legal expenses in accordance with, and subject to, the terms of such policies.

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 natural gas liquids that we produce.

In December 2009, the EPA published its findings that emissions of greenhouse gases, or GHGs, present a danger to public 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 conditions. Based on these findings, in 2010 the EPA adopted two sets of regulations that restrict emissions of GHGs under existing provisions of the federal Clean Air Act, including one that requires a reduction in emissions of GHGs from motor vehicles and another that requires certain construction and operating permit reviews for GHG emissions from certain large stationary sources. The stationary source final rule addresses the permitting of GHG emissions from stationary sources under the Clean Air Act Prevention of Significant Deterioration, or PSD, construction and Title V operating permit programs, pursuant to which these permit programs have been “tailored” to apply to certain stationary sources of GHG emissions in a multi-step process, with the largest sources first subject to permitting. In addition, EPA adopted rules requiring the monitoring and reporting of GHGs from certain sources, including, among others, onshore and offshore oil and natural gas production facilities. We are evaluating whether GHG emissions from our operations are subject to the GHG emissions reporting rule and expect to be able to comply with any applicable reporting obligations.

Also, Congress has from time to time considered legislation to reduce emissions of GHGs, and almost one-half of the states already have taken legal measures to reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. The adoption of any legislation or regulations that requires reporting of GHGs or otherwise restricts emissions of GHGs from our equipment and operations could require us to incur significant added costs to reduce emissions of GHGs or could adversely affect demand for the oil, natural gas and natural gas liquids we produce.

Finally, some scientists have concluded that increasing concentrations of GHGs in the earth’s atmosphere may produce climate change that could have significant physical effect, such as increased frequency and severity of storms, droughts and floods and other climatic events. If such effects were to occur, they could have an adverse effect on our assets and operations.

Our estimated proved 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 proved reserve 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, natural gas and natural gas liquids prices, drilling and operating expenses, capital expenditures, taxes and availability of funds.

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Actual future production, oil, natural gas and natural gas liquids 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 our reserves. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil, natural gas and natural gas liquids prices and other factors, many of which are beyond our control.

We must obtain governmental permits and approvals for our 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 specific 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, development or production operations or our midstream operations. For example, we are often required to prepare and present to federal, state, local or foreign authorities data pertaining to the effect or impact that proposed exploration for or development or production of oil or natural gas, pipeline construction, natural gas compression, treating or processing facilities or equipment and other associated equipment 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, local and foreign 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 or midstream construction activities commence, 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 or pipeline construction 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.

Derivatives reform could have an adverse impact on our ability to hedge risks associated with our business.

The Dodd-Frank Wall Street Reform and Consumer Protection Act, or Dodd-Frank, which was enacted in 2010, established a framework for the comprehensive regulation of the derivatives markets, including the swaps markets. Since enactment of Dodd-Frank, the Commodity Futures Trading Commission, or CFTC, and the SEC have adopted regulations to implement this new regulatory regime, for which the phase-in has begun and is expected to continue over the next year. Among other things, entities that enter into derivatives will be subject to position limits for certain futures, options and swaps, recordkeeping and reporting requirements and possible credit support requirements. Although Dodd-Frank favors mandatory exchange trading and clearing, entities that enter into over-the-counter swaps to mitigate commercial risk, such as Magnum Hunter, may be exempt from the clearing mandate. Whether we are required to post collateral with respect to our derivative transactions will depend on our counterparty type, final rules to be adopted by the CFTC, SEC and the bank regulators, and how our activities fit within those rules. Many entities, including our counterparties, may be subject to significantly increased regulatory oversight and minimum capital requirements. These changes could materially alter the terms of our derivative contracts, reduce the availability of derivatives to protect against the risks we encounter, reduce our ability to monetize or restructure existing derivative contracts and increase our exposure to less creditworthy counterparties. If we are required to post cash or other collateral with respect to our derivative positions, we could be required to divert resources (including cash) away from our core businesses, which could limit our ability to execute strategic hedges and thereby result in increased commodity price uncertainty and volatility in our cash flow. Although it is difficult to predict the aggregate effect of the new regulatory regime, the new regime could increase our costs, limit our ability to protect against risks and reduce liquidity, all of which could impact our cash flows and results of operations.

Acquired properties may not be worth what we pay due to uncertainties in evaluating estimated recoverable reserves and other expected benefits, as well as potential liabilities.

Successful property acquisitions require an assessment of a number of factors beyond our control. These factors include exploration and development potential, future oil and natural gas prices, operating costs and potential environmental and other liabilities. These assessments are complex and inherently imprecise. Our review of the properties we propose to acquire may not reveal all existing or potential problems. In addition, our review may not allow us to fully assess the potential deficiencies of the properties. We do not typically inspect all acreage, wells, equipment or other assets we propose to acquire, and even when we inspect an asset we may not discover structural, subsurface, environmental or other problems that may exist or arise. We may not be entitled to contractual indemnification for pre-closing liabilities, including environmental liabilities, and any contractual indemnification to which we are

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entitled may not be effective. In some cases, we may acquire interests in properties on an “as is” basis with limited remedies for breaches of representations and warranties by the previous owners. If an acquired property is not performing as originally estimated, we may have an impairment which could have a material adverse effect on our financial position and future results of operations.

Our recent acquisitions and any future acquisitions may not be successful, may substantially increase our indebtedness and contingent liabilities and may create integration difficulties.

As part of our business strategy, we have acquired and intend to continue to acquire businesses or assets we believe complement our existing operations and business plans. We may not be able to successfully integrate these acquisitions into our existing operations or achieve the desired profitability from such acquisitions. These acquisitions may require substantial capital expenditures and the incurrence of additional indebtedness which may change significantly our capitalization and results of operations. Further, these acquisitions could result in:

• post-closing discovery of material undisclosed liabilities of the acquired business or assets, title or other defects with respect to acquired assets, discrepancies or errors in furnished financial statements or other information or breaches of representations made by the sellers;

• the unexpected loss of key employees or customers from acquired businesses;

• difficulties resulting from our integration of the operations, systems and management of the acquired business; and

• an unexpected diversion of our management’s attention from other operations.

If acquisitions are unsuccessful or result in unanticipated events, such as the post-closing discovery of the matters described above, or if we are unable to successfully integrate acquisitions into our existing operations, such acquisitions could adversely affect our financial condition, results of operations and cash flow. The process of integrating our operations could cause an interruption of, or loss of momentum in, the activities of our business. Members of our management may be required to devote considerable amounts of time to this integration process, which will decrease the time they will have to manage our existing business. If management is not able to effectively manage the integration process, or if any significant business activities are interrupted as a result of the integration process, our business could suffer.

We pursue acquisitions as part of our growth strategy and there are risks in connection with acquisitions.

Our growth has been attributable in part to acquisitions of producing properties and undeveloped acreage, either directly as asset acquisitions or indirectly through the acquisition of companies. We expect to continue to evaluate and, where appropriate, pursue acquisition opportunities on terms we consider favorable. However, we cannot assure you that suitable acquisition candidates will be identified in the future, or that we will be able to finance such acquisitions on favorable terms. In addition, we compete against other companies for acquisitions, and we cannot assure you that we will successfully acquire any material property interests. Further, we cannot assure you that future acquisitions by us will be integrated successfully into our operations or will be profitable.

The successful acquisition of producing properties and undeveloped acreage requires an assessment of numerous factors, some of which are beyond our control, including, without limitation:

• estimated recoverable reserves;

• exploration and development potential;

• future oil and natural gas prices;

• operating costs; and

• potential environmental and other liabilities.

In connection with such an assessment, we perform a review of the subject properties that we believe to be generally consistent with industry practices. The resulting assessments are inexact and their accuracy uncertain, and such a review may not reveal all existing or potential problems, nor will it necessarily permit us to become sufficiently familiar with the properties to fully assess their merits and deficiencies within the time frame required to complete the transactions. Inspections may not always be performed on every well or of every property, and structural and environmental problems are not necessarily observable even when an inspection is made.

Additionally, significant acquisitions can change the nature of our operations and business depending upon the character of the acquired properties, which may be substantially different in operating and geologic characteristics or geographic location than our existing properties. While our current operations are primarily focused in the West Virginia, Ohio, North Dakota, Saskatchewan and Kentucky regions, we may pursue acquisitions of properties located in other geographic areas.

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There are risks in connection with our sale of Eagle Ford Hunter, and there will be risks in connection with other dispositions we may pursue in the future.

We occasionally pursue dispositions of assets and properties, both to increase our cash position (or reduce our indebtedness) and to redirect our resources toward other purposes, either through asset sales or the sale of stock of one or more of our subsidiaries. In April 2013, we sold 100% of the stock of our Eagle Ford Hunter subsidiary to an affiliate of Penn Virginia. We are also exploring the possible sale of all or part of our midstream operations and certain non-core assets.

We expect to continue to evaluate and, where appropriate, pursue disposition opportunities on terms we consider favorable. However, we cannot assure you that suitable disposition opportunities will be identified in the future, or that we will be able to complete such dispositions on favorable terms. Further, we cannot assure you that our use of the net proceeds from such dispositions, including from our sale of Eagle Ford Hunter, will result in improved results of operations.

As with a successful acquisition, the successful disposition of assets and properties requires an assessment of numerous factors, some of which are beyond our control, including, without limitation:

• estimated recoverable reserves;

• exploration and development potential;

• future oil and natural gas prices;

• operating costs;

• potential seller indemnification obligations;

• the creditworthiness of the buyer; and

• potential environmental and other liabilities.

In connection with such an assessment, we perform a review of the subject properties that we believe to be generally consistent with industry practices. The resulting assessments are inexact and their accuracy uncertain, and such a review may not reveal all existing or potential benefits associated with a property, nor will it necessarily permit us to become sufficiently familiar with the properties to fully assess their merits and deficiencies within the time frame required to complete the transactions.

Additionally, significant dispositions can change the nature of our operations and business. The sale of Eagle Ford Hunter greatly reduced our presence in south Texas. While our current operations are primarily focused in the West Virginia, Ohio, North Dakota, Saskatchewan and Kentucky regions, we may pursue further dispositions of properties located in these areas in the future.

Our current Eureka Hunter Gas Gathering System operations and the expected future expansion of these operations subject us to additional governmental regulations.

We are currently continuing the construction of our Eureka Hunter Gas Gathering System, which provides or is expected to provide gas gathering services primarily in support of our Company-owned properties as well as other upstream producers’ operations in West Virginia and Ohio. We have completed certain sections of the pipeline and anticipate further expansion of the pipeline in the future, which expansion will be determined by various factors, including the prospects for commitments for gathering services from third-party producers, the availability of gas processing facilities, obtainment of rights-of-way, securing regulatory and governmental approvals, resolving any land management issues, completion of construction and connecting the pipeline to the producing sources of natural gas.

The construction, operation and maintenance of the Eureka Hunter Gas Gathering System involve numerous regulatory, environmental, political and legal uncertainties beyond our control and require the expenditure of significant amounts of capital. There can be no assurance that our pipeline construction projects will be completed on schedule or at the budgeted cost, or at all. The operations of our gathering system are also subject to stringent and complex federal, state and local environmental laws and regulations. These laws and regulations can restrict or impact our business activities in many ways, including restricting the manner in which we dispose of substances, requiring remedial action to remove or mitigate contamination, and requiring capital expenditures to comply with control requirements. Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial requirements and the issuance of orders enjoining future operations. Certain environmental statutes impose strict, joint and several liability for costs required to clean up and restore sites where substances and wastes have been disposed or otherwise released. Moreover, there exists

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the possibility that landowners and other third parties will file claims for personal injury and property damage allegedly caused by the release of substances or wastes into the environment.

There is inherent risk of the incurrence of environmental costs and liabilities in our business due to our handling of natural gas and other petroleum products, air emissions related to our operations, historical industry operations including releases of substances into the environment and waste disposal practices. For example, an accidental release from the Eureka Hunter Gas Gathering System could subject us to substantial liabilities arising from environmental cleanup, restoration costs and natural resource damages, claims made by landowners and other third parties for personal injury and property damage, and fines or penalties for related violations of environmental laws or regulations. Moreover, the possibility exists that stricter laws, regulations or enforcement policies could significantly increase our compliance costs and the cost of any remediation that may become necessary. We may not be able to recover some or any of these costs from insurance.

The use of geoscience, petro-physical and engineering analyses and other technical or operating data to evaluate drilling prospects is uncertain and does not guarantee drilling success or recovery of economically producible reserves.

Our decisions to explore, develop and acquire prospects or properties targeting the Marcellus Shale, Utica Shale, Bakken Shale, Eagle Ford Shale, Pearsall Shale and other areas depend on data obtained through geoscientific, petro-physical and engineering analyses, the results of which can be uncertain. Even when properly used and interpreted, data from whole cores, regional well log analyses and 2-D and 3-D seismic only assist our technical team in identifying hydrocarbon indicators and subsurface structures and estimating hydrocarbons in place. They do not allow us to know conclusively the amount of hydrocarbons in place and if those hydrocarbons are producible economically. In addition, the use of advanced drilling and completion technologies for the development of our unconventional resources, such as horizontal drilling and multi-stage fracture stimulations, requires greater expenditures than traditional development drilling strategies. Our ability to commercially recover and produce the hydrocarbons that we believe are in place and attributable to our properties will depend on the effective use of advanced drilling and completion techniques, the scope of our drilling program (which will be directly affected by the availability of capital), drilling and production costs, availability of drilling and completion services and equipment, drilling results, lease expirations, regulatory approval and geological and mechanical factors affecting recovery rates. Our estimates of unproved reserves, estimated ultimate recoveries per well, hydrocarbons in place and resource potential may change significantly as development of our oil and gas assets provides additional data.

We rely on information technology and any failure, inadequacy, interruption or security lapse of that technology could harm our ability to effectively operate our business.

In the ordinary course of our business, we use information technology to maintain, analyze and process, to varying degrees, our property information, reserve data, operating records (including amounts paid or payable to suppliers, working interest owners, royalty holders and others), drilling partnership records (including amounts paid or payable to limited partners and others), gas gathering, processing and transmission records, oil and gas marketing records and general accounting, legal, tax, corporate and similar records.  The secure maintenance of this information is critical to our business.  Our ability to conduct our business may be impaired if our information technology resources fail or are compromised or damaged, whether due to a virus, intentional penetration or disruption by a third party, hardware or software corruption or failure or error, service provider error or failure, natural disaster, intentional or unintentional personnel actions or other causes.  A significant disruption in the functioning of these resources could adversely impact our ability to access, analyze and process information, conduct operations in a normal and efficient manner and timely and accurately manage our accounts receivable and accounts payable, among other business processes, which could disrupt our operations, adversely affect our reputation and require us to incur significant expense to address and remediate or otherwise resolve these kinds of issues. The release of confidential business information also may subject us to liability, which could expose us to significant expense and have a material adverse effect on our financial results, stock price and reputation.  Portions of our information technology infrastructure also may experience interruptions, delays, cessations of service or errors in connection with systems integration or migration work that takes place from time to time.  We may not be successful in implementing new systems and transitioning data, which could cause business disruptions, result in increased expenses and divert the attention of management and key information technology resources.

Risks Related to Our Common Stock

The price of our common stock has fluctuated substantially since it first became listed on a national securities exchange in August 2006, and may fluctuate substantially in the future.

Our common stock is traded on the New York Stock Exchange, or NYSE, under the symbol “MHR”. On May 1, 2013, the last reported sale price of our common stock on the NYSE was $2.52 per share. The price of our common stock has fluctuated substantially since it first became listed on a national securities exchange in August 2006. From August 30, 2006 to May 1, 2013, the trading price at the close of the market (initially the American Stock Exchange and now the NYSE) of our common stock ranged from a low of $0.20 per share to a high of $8.57 per share. 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.

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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, production and operating results;

• acquisitions and dispositions of assets;

• results of our midstream operations;

• 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 common stock and related dilution to existing stockholders; 

• legal or regulatory proceedings or the threat thereof; and

• the other risks and uncertainties described in this “Risk Factors” section and elsewhere in this annual 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 our stockholders to resell shares of our common stock when they want or at attractive prices.

The market for our common stock may not provide investors with sufficient liquidity or a market-based valuation of our common stock.

The volume of trading in our common stock may not always provide investors sufficient liquidity in the event they wish to sell large blocks of common stock. There can be no assurance that an active market for our common stock will be available for trading in large volumes. If we are unable to maintain or further develop an active market for our common stock, our stockholders may not be able to sell our common stock at prices they consider to be fair or at times that are convenient for them, or at all.

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

In the future we may issue additional securities up to our total authorized and unissued amounts, including shares of our common stock or securities convertible into or exchangeable or exercisable for our common stock, resulting in the dilution of the ownership interests of our stockholders. We are currently authorized under our certificate of incorporation to issue up to 350,000,000 shares of common stock and up to 10,000,000 shares of preferred stock with such designations, preferences and rights as may be determined by our board of directors.

As of May 1, 2013, there were 169,619,879 shares of our common stock issued and outstanding, 4,000,000 shares of our non-convertible Series C Cumulative Perpetual Preferred Stock, or Series C Preferred Stock, issued and outstanding, 4,424,889 shares of our non-convertible Series D Cumulative Preferred Stock, or Series D Preferred Stock, issued and outstanding and 3,721,556 Depositary Shares representing our Series E Cumulative Convertible Preferred Stock, or Series E Preferred Stock, issued and outstanding.

We may issue additional shares of our common stock or securities convertible into or exchangeable or exercisable for our common stock in connection with hiring or retaining personnel, option or warrant exercises, future acquisitions or future placements of our securities for capital-raising or other business purposes.

Our certificate of incorporation and 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 and our executive officers, who collectively beneficially owned approximately 10% of the outstanding shares of our common stock as of May 1, 2013.

Provisions in our certificate of incorporation and 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 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;

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• 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 stockholders holding shares in the aggregate entitled to cast not less than 10% of the votes at such meeting; and

• allowing our directors, and not our stockholders, to fill vacancies on the board of directors, including vacancies resulting from removal of directors 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 May 1, 2013, our board of directors and executive officers collectively beneficially owned approximately 10% 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 influence over matters requiring stockholder approval, including the election of directors, any proposed merger, consolidation or sale of all or substantially all of our assets and certain other corporate matters and transactions.

The provisions in our certificate of incorporation and bylaws and of Delaware law, and the concentrated ownership of our common stock by our directors and 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 in the market value of our common stock to realize a gain on their investments.

We do not anticipate paying any cash dividends on our common stock in the foreseeable future. We currently intend to retain future earnings, if any, to finance the expansion of our businesses. 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 credit facilities and the indenture governing our Senior Notes limit the payment of dividends on our stock under certain circumstances without the prior written consent of the lenders or note holders. Moreover, the default under our Senior Notes indenture resulting from our late SEC filings currently prevents us from paying dividends on our equity securities. Accordingly, stockholders must look solely to appreciation in the market value of our common stock to realize a gain on their investment, which appreciation in value may never occur or may occur only from time to time and then only for limited periods of time.

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

Our 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 common stockholders. Any preferred stock that is issued may rank ahead of our common stock in terms of dividend rights, liquidation rights and/or voting rights. The terms of such preferred stock may also require us to redeem the preferred stock at the option of the holders of the preferred stock or mandatorily at certain times or under certain circumstances. If we issue additional 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 preferred stock, which will impact the rights of holders of our common stock if we liquidate.

As of May 1, 2013, we have issued and sold an aggregate of 4,000,000 shares of our Series C Preferred Stock, 4,424,889 shares of our Series D Preferred Stock and 3,721,556 Depositary Shares representing our Series E Preferred Stock. Under the certificates of designations of these series of preferred stock, if we liquidate, holders of our preferred stock (including the holders of the Depositary Shares) are entitled to receive payment of the stated liquidation preference of their shares, together with any accrued but unpaid dividends, before any payment is made to holders of our common stock.

Our outstanding warrants, stock options, stock appreciation rights and Depositary Shares, which are exercisable for or convertible into shares of our common stock, may be exercised or converted, which would dilute our existing common stockholders.

As of May 1, 2013, we had:

• (i) outstanding warrants that have an exercise price of $10.50 per warrant share, have a final maturity of October 2013 and can be redeemed by the Company at any time prior to their maturity for $0.001 per warrant share and are exercisable for an aggregate of 13,237,889 shares of our common stock; (ii) outstanding warrants that have an exercise price of $15.13 per warrant share and a final maturity of February 2014 and are exercisable for an aggregate of 97,780 shares of our common stock; and (iii) outstanding warrants that have an exercise price of $19.04 per warrant share and a final maturity of November 2014 and are exercisable for an aggregate of 40,608 shares of our common stock;

• outstanding employee and director stock options and stock appreciation rights that have exercise prices ranging from $0.51 to $7.95 per share and cover an aggregate of 18,902,730 shares of our common stock (and of which an aggregate of 10,988,949 stock options and stock appreciation rights, or approximately 58%, are exercisable as of May 1, 2013 and of which an aggregate of 1,479,000 stock options and stock appreciation rights, or approximately 7.8%, have exercise prices below $2.52, the closing sales price of our common stock on the NYSE on May 1, 2013); and

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• outstanding Depositary Shares representing our Series E Preferred Stock that have a conversion price (based on stated liquidation preference plus accrued and unpaid dividends) of $8.50 per share of common stock and are exercisable for an aggregate of 3,704,850 shares of our common stock.

Any such exercise or conversion will be dilutive to the ownership interests of our existing stockholders.

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 or exercisable for, shares of our common stock in the public markets and the issuance of shares of common stock and securities convertible into, or exchangeable or exercisable 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 exchangeable 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 or exercisable 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 our 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.

Current prohibitions on trading in our securities in certain jurisdictions of Canada will be in effect until we are current with our disclosure filings and successful in our applications to revoke the Canadian cease trade orders currently in effect.

The trading and purchasing of our securities in certain provinces of Canada, including Alberta, Manitoba, Ontario and Quebec, is currently prohibited due to the issuance in each such jurisdiction of a cease trade order to that effect resulting from our failure to file our audited financial statements, annual management's discussion and analysis and certification of annual filings for the year ended December 31, 2012. The securities commission of British Columbia has issued a similar order; however, the order permits a holder who is not an insider or control person of the Company to sell securities of the Company in certain circumstances.

Following the filing of this annual report and a report with respect to our first quarter 2013 financial results and condition on Form 10-Q, we intend to apply to revoke the cease trade orders in Canada currently in effect. Although we currently anticipate having the cease trade orders revoked following the filing of the outstanding reports described above, we may encounter unforeseen impediments during the process which could prolong the continuation of the prohibition on trading of our securities in the applicable Canadian jurisdictions. In addition, because we are considered to be a reporting issuer in each province of Canada, in addition to the provinces that have already issued cease trade orders, additional Canadian provinces could issue a cease trade order prior to us becoming current with all our continuous disclosure filings.

Item 1B. UNRESOLVED STAFF COMMENTS

None.

Item 2. PROPERTIES

Appalachian Basin Properties

The Appalachian Basin is considered one of the most mature oil and natural gas producing regions in the U.S. Our Appalachian Basin properties are located in West Virginia and Ohio, targeting the liquids rich Marcellus Shale and Utica Shale, and, to a lesser extent, in southern Appalachia.

We entered the Appalachian Basin in February 2010 through our acquisition of substantially all the assets of Triad Energy Corporation. We subsequently expanded our operations through various corporate and leasehold acreage acquisitions, including (i) the acquisition of NGAS in April 2011, which established our position in southern Appalachia, (i) the acquisition of assets from PostRock Energy Corporation and Windsor Marcellus LLC in late 2010 and early 2011, pursuant to which we acquired additional Marcellus Shale properties in Lewis, Braxton and Wetzel Counties, West Virginia, (iii) the expansion of our position in the Utica Shale in early 2012 through the acquisition of approximately 11,500 net acres in Noble and Washington Counties, Ohio and (iv) the acquisition of privately-held Viking International Resources Co., Inc. in November 2012, which added approximately 51,500 net acres to our existing position in Appalachia, including approximately 27,000 net acres in the Marcellus Shale and approximately 28,500 net acres prospective for the Utica Shale (a portion of which acreage overlaps our Marcellus Shale acreage).

As of May 1, 2013, we had approximately 81,000 net leasehold acres in the Marcellus Shale and approximately 79,000 net leasehold acres prospective for the Utica Shale (a portion of which acreage overlaps our Marcellus Shale acreage). We believe approximately 26,000 of these Utica Shale net acres are located in the wet gas window of the play. As of May 1, 2013, our 11 most recently completed Company-operated wells targeting the Marcellus Shale generated approximately 9,525 mcfepd and 5,800 mcfepd average IP-24 hour and IP-30 day rates, respectively.

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As of December 31, 2012, proved reserves attributable to our Appalachian Basin properties were 36.5 mmboe on an SEC basis, of which 66% were classified as proved developed producing, and 39.8 mmboe on a NYMEX basis. As of December 31, 2012, these proved reserves had a PV-10 value of $296.0 million (SEC basis) and $401.3 million (NYMEX basis).

Our capital budget for 2013 includes approximately $150 million for capital expenditures in the Appalachian Basin, including $135 million in the Marcellus Shale and Utica Shale, and of which a total of $15 million is budgeted for lease extensions. The Utica Shale budgeted amounts are for drilling activities to test and further develop our Utica Shale leasehold acreage.

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Marcellus Shale Properties

Our Marcellus Shale acreage is located principally in Tyler, Pleasants, Doddridge, Wetzel and Lewis Counties, West Virginia and in Washington, Monroe and Noble Counties, Ohio. As of May 1, 2013, the Company was operating 16 horizontal Marcellus Shale wells, and 10 horizontal wells (six net) were awaiting completion, one horizontal well (one-half net) was drilling and one drilling rig was operating on our Company-operated Marcellus Shale properties. As of May 1, 2013, approximately 76% of our mineral leases in the Marcellus Shale area were held by production. As of May 1, 2013, our 11 most recently completed Company-operated wells targeting the Marcellus Shale generated approximately 9,525 mcfepd and 5,800 mcfepd average IP-24 hour and IP-30 day rates, respectively.

The liquids rich natural gas produced in the Company’s core Marcellus Shale area (which has a btu content ranging from 1,125 to 1,435), coupled with a location near the energy-consuming regions of the mid-Atlantic and northeastern U.S., typically allow the Company to sell its natural gas at a premium to prevailing NYMEX spot prices. Historically, producers in the Appalachian Basin developed oil and natural gas from shallow Mississippian age sandstone and Upper Devonian age shales 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. However, in recent years, the application of horizontal well drilling and completion technology has led to the development of the Marcellus Shale, transforming the Appalachian Basin into one of the country’s premier natural 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 5,500 and 6,500 feet and ranges in thickness from 50 to 80 feet. It is considered the largest natural gas field in the country. Marcellus Shale gas is best produced from hydraulically fractured horizontal wellbores, exceeding 2,000 feet in lateral length, and involving multistage fracturing completions.

In January 2013, Triad Hunter entered into joint development and operating agreements with Eclipse Resources, pursuant to which Triad Hunter and Eclipse Resources agreed to jointly develop a contract area consisting of approximately 1,950 leasehold acres in the Marcellus Shale and Utica Shale in Monroe County, Ohio. Each party owns a 47% working interest in the contract area. Triad Hunter is the operator for the contract area. Eclipse Resources agreed to commit its share of natural gas production from the contract area to gathering by our Eureka Hunter Gas Gathering System. We plan to drill eight Marcellus Shale wells and three Utica Shale wells pursuant to this joint development program in 2013.

In December 2011, Triad Hunter entered into joint development and operating agreements with Stone Energy, pursuant to which Triad Hunter and Stone Energy agreed to jointly develop a contract area consisting of approximately 1,925 leasehold acres in the Marcellus Shale in Wetzel County, West Virginia. Each party owns a 50% working interest in the contract area. Stone Energy is the operator for the contract area. Stone Energy also contributed to the joint venture certain infrastructure assets, including improved roadways, certain central field processing units (including water handling) and gas flow lines, and agreed to commit its share of natural gas production from the contract area to gathering by our Eureka Hunter Gas Gathering System. As of May 1, 2013, Stone Energy had drilled and completed seven producing Marcellus Shale wells pursuant to this joint development program. We expect an additional four program wells to be on production in the summer of 2013.

In October 2011, Triad Hunter entered into a processing agreement with MarkWest pursuant to which MarkWest will provide long-term gas processing and related services for natural gas produced by Triad Hunter that is gathered through our Eureka Hunter Gas Gathering System. Triad Hunter commenced gas delivery to the Mobley Processing Plant through the Eureka Hunter Gas Gathering System in December 2012.

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The following table contains certain information regarding our completed Marcellus Shale horizontal wells as of May 1, 2013.

Well Name	County / Province	Formation	MHR Working Interest		First Production	Horizontal Lateral Length (Feet)	# of Frac Stages	IP-24 Hour Rate (Mcfe/d)	7 Day IP Rate (Mcfe/d)	30 Day IP Rate (Mcfe/d)
Operated
Weese #1H	Tyler, WV	Marcellus	100	%	12/31/2010	3550	12	7,210	4,559	4,205
Weese #3H	Tyler, WV	Marcellus	100	%	1/20/2011	3030	12	5,413	4,352	4,836
Ormet #1-9H	Monroe, OH	Marcellus	100	%	2/25/2011	3700	12	Tight hole	Tight hole	Tight hole
Ormet #2-9H	Monroe, OH	Marcellus	100	%	N/A	3250	16	N/A	N/A	N/A
Ormet #3-9H	Monroe, OH	Marcellus	100	%	N/A	4740	24	N/A	N/A	N/A
WVDNR #1102	Wetzel, WV	Marcellus	100	%	9/19/2011	4950	16	10,000	6,184	5,800
WVDNR #1103	Wetzel, WV	Marcellus	100	%	9/22/2011	5000	16	10,500	7,164	7,078
WVDNR #1104	Wetzel, WV	Marcellus	100	%	9/26/2011	5000	16	10,400	6,139	5,618
Roger Weese #1110	Tyler, WV	Marcellus	100	%	10/25/2011	4350	16	9,700	6,183	5,040
Everett Weese #1107	Tyler, WV	Marcellus	100	%	12/20/2011	5300	18	9,700	6,618	6,542
Everett Weese # 1108	Tyler, WV	Marcellus	100	%	12/20/2011	5200	16	9,600	6,913	6,337
Everett Weese #1109	Tyler, WV	Marcellus	100	%	12/20/2011	5550	18	9,500	7,239	6,361
Spencer Unit #1112H	Tyler, WV	Marcellus	100	%	11/19/2012	4310	17	9,471	5,852	5,614
Spencer Unit #1113H	Tyler, WV	Marcellus	100	%	11/19/2012	4000	27	7,998	6,004	5,274
Spencer Unit #1114H	Tyler, WV	Marcellus	100	%	11/19/2012	4720	19	9,563	5,640	5,329
Spencer Unit #1115H	Tyler, WV	Marcellus	100	%	4/11/2012	3900	16	8,340	6,320	4,716
Non-Operated
Lance Mills Unit 2 #5H	Wetzel, WV	Marcellus	50	%	6/5/2011	5350	13	3,360	3,114	2,789
Lance Mills Unit 2 #2H	Wetzel, WV	Marcellus	50	%	6/6/2011	5600	11	3,875	2,987	2,620
Mills Wetzel #8H	Wetzel, WV	Marcellus	50	%	Tested	3413	11	3,792	N/A	N/A
Mills Wetzel #10H	Wetzel, WV	Marcellus	50	%	Tested	2962	10	3,954	N/A	N/A
Mills Wetzel #11H	Wetzel, WV	Marcellus	50	%	Tested	3575	12	3,397	N/A	N/A

During 2013, we plan to drill a total of 27 gross (18 net) wells in the Marcellus Shale.

Utica Shale Properties

Our Utica Shale acreage is located principally in Tyler, Pleasants and Wood Counties, West Virginia and in Washington, Monroe, Morgan and Noble Counties, Ohio. As of May 1, 2013, we owned mineral rights to a total of approximately 79,000 net acres that are presently prospective for the Utica Shale. Approximately 47,000 of the net acres are located in Ohio (a portion of which acreage overlaps our Marcellus Shale acreage), and approximately 32,000 of the net acres are located in West Virginia (all of which overlaps our Marcellus Shale acreage).

General. The Utica Shale is located in the Appalachian Basin of the United States and Canada. The Utica Shale is a rock unit comprised of organic-rich calcareous black shale that was deposited about 440 million to 460 million years ago during the Late Ordovician period. It overlies the Trenton Limestone and is located a few thousand feet below the Marcellus Shale, which is considered to be the largest exploration play in the eastern United States.

The Utica Shale may be comparable or thicker and more geographically extensive than the Marcellus Shale, although reported drilling results in the play are still not sufficient to conclusively establish the geographical extent of the play. The potential source rock portion of the Utica Shale underlies portions of Kentucky, Maryland, New York, Ohio, Pennsylvania, Tennessee, West Virginia and Virginia in the United States and is also present beneath parts of Lake Ontario, Lake Erie and Ontario, Canada. Throughout the potential source rock area, the Utica Shale ranges in thickness from less than 100 feet to over 500 feet. Over the rock unit as a whole, there is a general thinning from east to west.

The Utica Shale is deeper than the Marcellus Shale. In some parts of Pennsylvania, the Utica Shale is estimated to be over two miles below sea level and up to 7,000 feet below the Marcellus Shale. However, the depth of the Utica Shale decreases to the west into Ohio and to the northwest under the Great Lakes and into Canada to less than approximately 2,000 feet below sea level. Most of our acreage is located at depths of 7,600 to 10,500 feet and approximately 3,000 feet below the Marcellus Shale.

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The Utica Shale is estimated to have higher carbonate and lower clay mineral content than the Marcellus Shale. The difference in mineralogy generally produces a different response to hydraulic fracturing treatments. Operation drillers have redesigned and improved the fracturing methods in the Utica Shale, to generally match or improve upon, to the extent deemed beneficial, those methods used in other natural gas shales with comparable carbonate content. For example, drillers have discovered methods to make the brittle carbonate zones in the Utica Shale fracture at generally higher rates than gas shale rock units in the Eagle Ford Shale in Texas. Drillers are researching methods to make other similar fracturing improvements in the Utica Shale.

The Point Pleasant formation in the Utica Shale is generally 100 to 150 feet thick and is our primary targeted reservoir for horizontal drilling in the play. This formation is primarily limestone with inter-bedded shales deposited within an organic rich marine environment. The Point Pleasant formation has the composition for hydrocarbon generation and brittleness. Combined with the organic content, or TOC, a 9% to14% porosity, thermal maturity and a significant geo-pressured condition, the Point Pleasant formation has the characteristics for an ideal unconventional reservoir.  The Point Pleasant formation appears to have a significant amount of hydrocarbons in place, and the techniques for successful drilling in the formation appear similar to those of the Eagle Ford Shale in Texas; longer laterals, more stages of fracture stimulation and more effective treatment of the horizontal lateral appear to be key to the optimization of recoverable reserves and return on investment.

Based on estimates published by the Ohio Department of Natural Resources, or ODNR, in 2012, the Utica Shale had a recoverable potential of 1.3 billion to 5.5 billion barrels of oil and 3.8 to 15.7 trillion cubic feet of natural gas in Ohio alone. During 2012, a number of oil and gas companies made significant investments in acquiring Utica Shale acreage in eastern Ohio. Recently, the ODNR reported that in the Utica Shale in Ohio there were 89 producing horizontal wells, 202 horizontal wells that had been drilled but were not yet completed or connected to a pipeline, 14 horizontal wells that were being drilled and 616 horizontal wells that had been permitted.

During 2012, most of the drilling activity in the Utica Shale occurred in eastern Ohio, where our acreage is located. Based on the initial drilling results, the Utica Shale is prospective for oil, natural gas and natural gas liquids. Specifically, early wells drilled in the Utica Shale indicate greater potential for production of significant amounts of natural gas liquids, which generally have a higher value, on an energy-equivalent basis, than natural gas.

Our Utica Drilling Activity. During 2013, Triad Hunter plans to drill a minimum of four wells in Washington County and Monroe County, Ohio to test the Utica Shale formation. In connection with this planned test development, Triad Hunter is currently drilling its first Utica Shale well, from the Farley Pad, which is located in northern Washington County, Ohio. The Farley Pad has been designed to drill up to four horizontal wells. Triad Hunter spud its first Utica Shale test well from the Farley Pad in April 2013, and expects to commence a 25 plus stage fracture stimulation of the well in July 2013. After Triad Hunter finishes fracing the well, it plans to shut in the well for approximately 30 to 40 days and then begin flow testing the well in August or September 2013.

The Company also commenced construction of a 16-well pad in Monroe County, Ohio in June 2013, known as the Stadler Pad. The Stadler Pad is being constructed under our joint venture agreement with Eclipse Resources. The Company expects that it will initially drill three Utica wells and eight Marcellus wells from the Stadler Pad; however, we retain flexibility to shift the mix of Marcellus and Utica wells based on drilling results. The Company will have test results from the initial wells in 2013, but doesn't expect production from these wells to begin flowing through the Eureka Hunter Gas Gathering System until all wells from the pad have been drilled and completed, which is anticipated to be in the fall of 2014.

In anticipation of favorable results from these wells, we have commissioned engineering drawings and drilling unit preparations for two additional planned Utica Shale drilling pads, the Crooked Tree Pad to be located in Noble County, Ohio, designed for up to 10 horizontal wells, and the Wood Chopper Pad to be located in Washington County, Ohio, designed for up to four horizontal wells.

We currently anticipate that our natural gas production from our Utica Shale wells will be gathered by our Eureka Hunter Gas Gathering System. Gas processing infrastructure is developing at a rapid pace in this region. Therefore, we expect that gas processing availability in close proximity to the wells will be available for our production. We will be required to install typical production equipment at our Utica Shale well locations, such as storage tank batteries, oil/gas/water separation equipment, vapor recovery line heaters and compressors.

Subject to well results of the Company and third-party operators in the area, Triad Hunter plans to significantly expand its drilling program in the Utica Shale in 2014.

Southern Appalachian Basin Properties

As of May 1, 2013, our southern Appalachian Basin properties included approximately 304,900 net acres, primarily in Kentucky. Our primary production from the southern Appalachian Basin properties comes from the Devonian Shale formation and the Mississippian Weir sandstone.

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The Devonian Shale formation is considered an unconventional target due to its low permeability; however, in recent years, the application of horizontal well drilling and completion technology has led to improved economics. The Devonian Shale generally produces little or no water, contributing to a low cost of operation. As of May 1, 2013, we had drilled 77 Devonian Shale horizontal wells, primarily in the Huron and Cleveland sections of the formation. Due to low commodity prices in 2012, we did not drill any Huron or Cleveland horizontal wells in 2012; however, we negotiated a postponement of certain drilling obligations covering approximately 223,500 net acres in these formations until the end of the first quarter of 2014.

The Mississippian Weir sandstone covers approximately 32,300 net acres of our southern Appalachian Basin properties. In 2012, we drilled four Weir horizontal wells with increasingly encouraging results as we extended our lateral lengths and continued to optimize our completion techniques. The Weir produces oil in addition to high btu natural gas. As of May 1, 2013, we were drilling one Weir well (one net).

Our Appalachian Basin properties also include (i) a non-operating interest in a coal bed methane project in the Arkoma Basin in Arkansas and Oklahoma, (ii) certain non-operated projects in West Virginia and Virginia and (iii) an operating interest in a New Albany Shale field in western Kentucky known as Haley’s Mill.

Williston Basin Properties

We acquired Nuloch Resources Inc., or NuLoch, in May 2011, establishing our initial presence in the Bakken/Three Forks Sanish formations in the Williston Basin in North Dakota and Saskatchewan, Canada. We expanded our presence in the Williston Basin through (i) our March 2012 acquisition of Eagle Operating, Inc.’s operating working interest ownership in certain oil and gas leases and wells in five counties in North Dakota, (ii) our May 2012 acquisition of Baytex Energy USA Ltd.’s non-operating working interest ownership in certain oil and gas leases and wells in Divide and Burke Counties, North Dakota and (iii) our December 2012 acquisition of Samson Resources Company’s operating and non-operating working interest ownership in certain oil and gas leases and wells in Divide County, North Dakota.

As of May 1, 2013, our Williston Basin properties included (a) approximately 178,000 net leasehold acres consisting of 124,600 net acres in the Bakken/Three Forks Sanish in North Dakota and 53,400 net acres in the Bakken/Three Forks Sanish in Saskatchewan, and (b) approximately 15,000 net leasehold acres comprising our North Dakota legacy properties described below.

As of May 1, 2013, we had drilled and completed approximately 252 gross (82.6 net) wells on our Bakken/Three Forks Sanish properties, including 210 gross (45.8 net) wells in the Bakken/Three Forks Sanish in North Dakota and 42 gross (36.8 net) wells in the Bakken/Three Forks Sanish in Saskatchewan. Of these wells, approximately 107 gross (21.3 net) wells in the Bakken/Three Forks Sanish in North Dakota, and approximately 24 gross (20.9 net) wells in the Bakken/Three Forks Sanish in Saskatchewan, were completed in 2012 and through May 1, 2013. As of May 1, 2013, we operated 47 of our Bakken/Three Forks Sanish wells, including five wells in the Bakken/Three Forks Sanish in North Dakota and 42 wells in the Bakken/Three Forks Sanish in Saskatchewan. As of May 1, 2013, we operated 181 gross (172 net) Madison formation wells on our North Dakota legacy properties.

As of December 31, 2012, proved reserves attributable to our Williston Basin properties were 23.7 mmboe on an SEC basis, of which 96% were oil and natural gas liquids and 41% were classified as proved developed producing, and 21.7 mmboe on a NYMEX basis. As of December 31, 2012, these proved reserves had a PV-10 value of $427.8 million (SEC basis) and $377.3 million (NYMEX basis).

Our capital expenditures budget for 2013 includes approximately $150 million for capital expenditures in the Williston Basin, including $128 million and $12 million in the Bakken/Three Forks Sanish in North Dakota and Saskatchewan, respectively, and of which a total of $10 million is budgeted for lease extensions. During 2013, we plan to drill a total of 65 gross (22.0 net) wells in the Bakken/Three Forks Sanish.

The Williston Basin is spread across North Dakota, Montana and parts of southern Canada with the U.S. portion of the basin encompassing approximately 143,000 square miles. The basin produces oil and natural gas from numerous producing horizons, including the Madison, Bakken, Three Forks Sanish and Red River formations. The Bakken formation is a Devonian age shale. The North Dakota Geological Survey and Oil and Gas Division estimates that the Bakken formation is capable of generating between 271 and 500 billion bbls of oil. The Bakken formation underlies portions of North Dakota and Montana and southern Canada and is generally found at vertical depths of 9,000 to 10,500 feet. Below the Lower Bakken Shale lies the Three Forks Sanish formations, which have also proven to contain highly productive reservoir rock. The Three Forks Sanish formations typically consist of interbedded dolomites and shale with local development of a discontinuous sandy member at the top, known as the Sanish sand. Economic crude oil development and production from the Bakken/Three Forks Sanish reservoirs are made possible through the combination of advanced horizontal drilling and fracture stimulation technology. Horizontal wells in these formations are typically drilled on 640 acre or 1,280 acre spacing with horizontal laterals extending 4,500 to 9,500 feet into the reservoir. Ultimately, a spacing unit may be developed with up to four horizontal wells in each formation. Fracture stimulation techniques generally utilize multi-stage mechanically diverted stimulations.

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We refer to our properties in North Dakota as our Williston Hunter U.S. properties and our properties in Canada (which include our Bakken/Three Forks Sanish properties in Saskatchewan as well as certain properties we operate in Alberta) as our Williston Hunter Canada properties.

Williston Hunter U.S. Properties

Bakken/Three Forks Sanish Properties in North Dakota. As of May 1, 2013, our Williston Hunter U.S. properties included approximately 124,600 net acres in the Bakken/Three Forks/Sanish formations in the Williston Basin in North Dakota. As of May 1, 2013, our Bakken/Three Forks Sanish properties in North Dakota included approximately 210 gross (45.8 net) productive wells, and we were operating five of these gross wells. As of May 1, 2013, eight horizontal wells (3.2 net) were awaiting completion, five wells (1.6 net) were being drilled, five gross (0.9 net) were being completed, and five drilling rigs were operating on our Bakken/Three Forks Sanish properties in North Dakota.

Our Williston Hunter U.S. property acreage in the Bakken/Three Forks Sanish is located in Divide and Burke Counties, North Dakota. In 2012, we significantly expanded our Williston Hunter U.S. position in the Bakken/Three Forks Sanish through the acquisitions of the Acquired Baytex Assets in Divide and Burke Counties, North Dakota and the Acquired Samson Assets in Divide County, North Dakota. The acquisition of the Acquired Samson Assets established Bakken Hunter as an operator in the Bakken/Three Forks Sanish in Divide County, North Dakota. As of May 1, 2013, (i) our five most recently completed third-party-operated one-mile wells in Divide County, North Dakota generated an average IP-24 hour rate of approximately 594 boepd, and (ii) our five most recently completed third-party-operated two-mile wells in Divide County North, Dakota generated an average IP-24 hour rate of approximately 732 boepd.

North Dakota Legacy Properties. The Company also holds operating working interests in approximately 15,000 net acres of waterflood properties located in Burke, Renville, Ward, Bottineau and McHenry Counties, North Dakota. We initially acquired non-operating working interests in these properties from Eagle Operating, Inc., or Eagle Operating, in 2006. We acquired Eagle Operating’s remaining working and operating interests in the properties in March 2012, effective as of April 1, 2011, giving us up to an approximate 95% operating working interest in the properties. As of May 1, 2013, we were operating approximately 181 wells on these properties. These properties produce primarily from the Madison formation in the Williston Basin.

Oneok Gas Gathering Arrangement. In March 2012, we entered into a gas purchase agreement with Oneok, pursuant to which Oneok is currently constructing a natural gas gathering system and related facilities in North Dakota for the gathering and processing by Oneok of associated natural gas production, including the associated natural gas production from certain of our oil properties in Divide County, North Dakota dedicated by us to Oneok for this purpose. This arrangement was expanded to include certain of our Acquired Baytex Assets and Acquired Samson Assets when we acquired those assets in May and December 2012, respectively. Pursuant to this arrangement, Oneok will purchase our natural gas and natural gas liquids production from the dedicated properties, and we will be responsible for certain well tie-in and electrical power costs associated with the Oneok system and certain minimum yearly gas sale volume requirements. The sale of our natural gas and natural gas liquids production to Oneok pursuant to this arrangement, once the Oneok facilities are complete, will allow us to realize revenues from our natural gas stream in the Divide County area. Oneok is currently building out its compressor station, 12-inch high-pressure discharge line and northern-most east/west gathering pipeline in Divide County. We expect the Oneok system to be operational with respect to certain of our Divide County properties in mid-2013. We also anticipate delivering certain of our Tableland Field associated natural gas production into the Oneok system.

A large part of the associated natural gas produced from oil properties in certain regions of North Dakota is currently being flared or otherwise not marketed because of the lack of available gas gathering and processing infrastructure in these regions. Current and anticipated future North Dakota state regulations on gas flaring restrict and may further restrict, and may possibly prohibit, oil production in North Dakota as to which associated natural gas is flared rather than gathered. We expect that our arrangement with Oneok will permit us to continue to produce crude oil from our properties in Divide County, North Dakota in compliance with these existing or future state regulations.

Williston Hunter Canada Properties

As of May 1, 2013, our Williston Hunter Canada properties included approximately 53,400 net acres in the Tableland Field in the Williston Basin in Saskatchewan and approximately 36,000 net acres in Alberta. As of May 1, 2013, the Williston Hunter Canada properties included approximately 88 gross (79.3 net) productive wells, 98% of which we operate. At May 1, 2013, one horizontal well (0.4 net) was drilling on our Williston Hunter Canada properties.

Saskatchewan. The Tableland Field properties target sweet light oil from the Bakken/Three Forks Sanish formations. At May 1, 2013, Williston Hunter Canada had approximately 53,400 net acres of largely contiguous land that is prospective for Bakken/Three Forks Sanish oil in the Tableland Field. As of May 1, 2013, Williston Hunter Canada had 42 producing oil wells (36.8 net), and one well (0.4 net) drilling in the Tableland Field. As of May 1, 2013, our eight most recently completed wells in the Tableland Field generated approximately 358 boepd average IP-24 hour rates.

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Alberta. Our Alberta properties target shallow natural gas and sweet light oil from the Enchant Second White Specks formation and the Kiskatinaw formation. Our Alberta properties include the Enchant Second White Specks and Balsam properties. At May 1, 2013, Williston Hunter Canada had approximately 36,000 net acres in Alberta. At May 1, 2013, Williston Hunter Canada had four producing oil wells (2.8 net) and no wells drilling in Alberta.

The following table contains certain information regarding our Bakken/Three Forks Sanish horizontal wells completed during the period from January 1, 2013 to May 19, 2013.

Well Name	County/Province	Formation	MHR Working Interest		First Production	Horizontal Lateral Length (Feet)	# of Frac Stages	IP-24 Hour Rate (Boe/d)	7 Day IP Rate (Boe/d)	30 Day IP Rate (Boe/d)
Tableland - Operated
91/08-01-001-10W2	Saskatchewan	Three Forks/Sanish	85.0	%	1/4/2013	1 Mile	28	279	222	192
91/01-06-001-09W2	Saskatchewan	Three Forks/Sanish	70.0	%	1/19/2013	1 Mile	27	110	96	76
91/01-13-001-10W2	Saskatchewan	Three Forks/Sanish	70.0	%	2/4/2013	1 Mile	27	297	252	211
92/08-11-001-10W2	Saskatchewan	Three Forks/Sanish	70.0	%	2/16/2013	1 Mile	28	194	165	146
91/09-09-001-10W2	Saskatchewan	Three Forks/Sanish	88.0	%	2/20/2013	1 Mile	26	555	306	235
North Dakota - Non-Operated
Prochnick 15-35HSB (2-11-163-100)	Divide	Three Forks/Sanish	5.9	%	2/8/2013	2 Mile	26	1,256	945	813
Prochnick 16-35HS (2-11-163-100)	Divide	Three Forks/Sanish	5.9	%	2/8/2013	2 Mile	20	1,005	848	634
Prochnick 15-35HSA (2-11-163-100)	Divide	Three Forks/Sanish	5.9	%	2/22/2013	2 Mile	20	629	549	449
William Bailard 0112-1H (1-12-163-99)	Divide	Bakken	16.7	%	2/24/2013	2 Mile	40	922	791	659
Bakke 3229-3TFH (32-29-164-99)	Divide	Bakken	33.8	%	3/4/2013	1 Mile	26	627	536	437
Leo 32-29-162-97H 1NC	Divide	Three Forks/Sanish	10.0	%	3/14/2013	2 Mile	32	511	348	274
Bakke 3229-2TFH (32-29-164-99)	Divide	Three Forks/Sanish	33.8	%	3/16/2013	1 Mile	26	367	238	321
Leo 5-8-161-97H 1XN	Divide	Three Forks/Sanish	9.4	%	3/19/2013	2 Mile	36	476	308	262
Pulvermacher 3-10-161-99 1XN	Divide	Three Forks/Sanish	19.1	%	3/20/2013	2 Mile	36	530	436	315
Pulvermacher 34-27-161-99 1XN	Divide	Three Forks/Sanish	9.6	%	3/23/2013	2 Mile	36	454	377	—
Thomte 0508-3TFH (5-8-163-99)	Divide	Bakken	33.8	%	3/23/2013	2 Mile	40	1,166	1,060	867
Karen Bailard 3625-1H (36-25-164-99)	Divide	Bakken	16.7	%	3/27/2013	1 Mile	26	911	618	559
Almos Farms 0112-2H (1-12-162-99)	Divide	Three Forks/Sanish	47.5	%	3/28/2013	2 Mile	27	684	629	526
Thomte 0508-2TFH (5-8-163-99)	Divide	Three Forks/Sanish	33.8	%	3/29/2013	2 Mile	36	736	578	536
Almos Farms 0112-1MBH (1-12-162-99)	Divide	Bakken	47.5	%	3/29/2013	2 Mile	40	684	629	526
Bakke 3229-4TFH (32-29-164-99)	Divide	Three Forks/Sanish	47.5	%	4/9/2013	1 Mile	26	432	322	292
Bakke 3229-5MBH (32-29-164-99)	Divide	Bakken	39.3	%	4/9/2013	1 Mile	26	498	403	336
Gjovig 0508-5MBH (5-8-163-99)	Divide	Bakken	39.3	%	4/10/2013	2 Mile	40	360	—	—
Border Farms 3130-5TFH (31-30-164-99)	Divide	Bakken	34.1	%	4/19/2013	1 Mile	26	626	472	—
Border Farms 3130-4TFH (31-30-164-99)	Divide	Three Forks/Sanish	47.5	%	4/22/2013	1 Mile	26	529	458	371
Pulvermacher 33-28-162-99 1BP	Divide	Three Forks/Sanish	9.8	%	4/24/2013	2 Mile	31	388	273	—
Bakke 3229-6TFH (32-29-164-99)	Divide	Three Forks/Sanish	39.3	%	4/25/2013	1 Mile	25	330	—	—

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Well Name	County / Province	Formation	MHR Working Interest		First Production	Horizontal Lateral Length (Feet)	# of Frac Stages	IP-24 Hour Rate (Boe/d)	7 Day IP Rate (Boe/d)	30 Day IP Rate (Boe/d)
Titan 3625 2TFH (36-25-164-99)	Divide	Three Forks/Sanish	16.7	%	4/27/2013	1 Mile	26	302	224	168
Thomte 0508-6TFH (5-8-163-99)	Divide	Three Forks/Sanish	33.8	%	5/4/2013	2 Mile	40	432	324	—
Montclair 0112-2TFH (1-12-163-99)	Divide	Three Forks/Sanish	16.7	%	5/7/2013	2 Mile	40	683	381	—
J Olson 22-15-162-98H 2DM	Divide	Three Forks/Sanish	36.3	%	5/14/2013	2 Mile	36	872	817	—
J Olson 27-34-162-98H 2XM	Divide	Three Forks/Sanish	35.7	%	5/19/2013	2 Mile	36	820	—	—

Eagle Ford Shale Properties

We made our initial entry into the oil window of the Eagle Ford Shale in Gonzales, Lavaca, Fayette, Lee, and Atascosa Counties in south Texas in October 2009 with our acquisition of Sharon Resources, Inc., renamed Eagle Ford Hunter, Inc., or Eagle Ford Hunter. We subsequently expanded our position in this prolific area through additional leasing activities and two joint ventures.

On April 24, 2013, we sold our core properties in the oil window of the Eagle Ford Shale in Gonzales and Lavaca Counties, Texas to an affiliate of Penn Virginia Corporation, or Penn Virginia, for a total purchase price of $422.1 million, paid to us in the form of $379.8 million in cash (after initial purchase price adjustments) and $42.3 million in Penn Virginia common stock (valued, for purposes of the purchase price calculation, at a price of $4.23 per share). We refer to this sale as our sale of the Eagle Ford Properties or our Eagle Ford Properties Sale.

The properties sold to the Penn Virginia affiliate included approximately 19,000 net Eagle Ford Shale leasehold acres, and our operating and non-operating leasehold working interests in certain existing wells, in Gonzales and Lavaca Counties, Texas. The transaction was structured as a sale by us to the Penn Virginia affiliate of all of the outstanding capital stock of Eagle Ford Hunter. The effective date of the transaction was January 1, 2013.

Prior to the closing of the transaction, Eagle Ford Hunter transferred to Shale Hunter, LLC, one of our wholly-owned subsidiaries, all of the assets and properties held by Eagle Ford Hunter other than the properties in Gonzales and Lavaca Counties purchased by the Penn Virginia affiliate. As a result, as of May 1, 2013, we continued to own (a) approximately 7,000 net Eagle Ford Shale mineral acres located primarily in Fayette, Lee and Atascosa Counties, and (b) leasehold working interests in certain existing producing, development and test wells located on these properties. As of May 1, 2013, we were operating and producing from three gross (2.4 net) horizontal wells on Eagle Ford Shale properties.

As of December 31, 2012, after giving effect to the Eagle Ford Properties Sale, proved reserves attributable to our Eagle Ford Shale properties were 0.5 mmboe on an SEC basis, of which 89% were oil and natural gas liquids and 47% were classified as proved developed producing, and 0.4 mmboe on a NYMEX basis. As of December 31, 2012, these proved reserves had a PV-10 value of $9.6 million (SEC basis) and $8.9 million (NYMEX basis).

The Company has an average working interest of 96.75% and an average net revenue interest of 72.56% in the Alright area of the Eagleville Field in southwestern Atascosa County, near Charlotte, Texas. This area is central to an active Eagle Ford Shale area called the four corners, which includes acreage in Atascosa, Frio, McMullen and LaSalle Counties, Texas.

Approximately 5,100 of our net leasehold acres in Atascosa County, Texas are prospective for the development of both the Eagle Ford Shale and the Pearsall Shale. The Pearsall Shale is located approximately 2,500 feet beneath the Eagle Ford Shale at depths ranging from 7,000 to 12,000 feet and is approximately 300 to 400 feet in thickness. The Pearsall Shale is different in composition to the Eagle Ford Shale, composed of more silica with interbedded organic shale and limestone. We believe that our Pearsall Shale acreage is located within the wet gas to rich condensate window of the play, which is bounded by the Charlotte fault trend eight miles to the north and the Karnes fault trend to the south. Our internal technical analysis, core samples and recent third-party offset well results indicate potential for both Eagle Ford Shale and Pearsall Shale productivity on this acreage. In the fourth quarter of 2012, we drilled and completed a horizontal well on this acreage to the Eagle Ford Shale, and in connection therewith performed an evaluation of the Pearsall Shale, including log runs and core analysis. In the first quarter of 2013, we participated (through a 31% non-operating working interest) in the drilling and completion of our first Pearsall Shale well. The well is operated by Marathon Oil Corporation, and we anticipate that the well will be on production around mid-2013.

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Other Properties

Other Texas and Louisiana Assets

The Company owns certain other scattered miscellaneous oil and gas properties in Texas (outside of the Eagle Ford Shale area) and Louisiana. We have not allocated any significant capital to these assets for 2013.

Midstream Operations

Eureka Hunter Gas Gathering System

Eureka Pipeline acquired assets from Triad Energy Corporation in 2010 that included gas gathering systems and pipeline rights-of-way in West Virginia and Ohio. We have developed and continue to develop these assets into our Eureka Hunter Gas Gathering System, which helps support our existing and anticipated future Marcellus Shale and Utica Shale acreage positions, as well as the expanding gathering needs of third-party producers. As of May 1, 2013, our Eureka Hunter Gas Gathering System included a total of approximately 79 miles of completed pipeline located in northwestern West Virginia and southeastern Ohio. The Eureka Hunter Gas Gathering System and associated rights-of-way run through Pleasants, Tyler, Ritchie, Wetzel, Marion, Harrison, Doddridge, Lewis and Monongalia Counties in West Virginia and Washington County, Ohio, in certain liquids rich portions of the Marcellus Shale and Utica Shale. The first completed six-mile section of the Eureka Hunter Gas Gathering System was turned to sales in December 2010.

The Eureka Hunter Gas Gathering System is being constructed primarily out of new 20-inch and 16-inch high-pressure steel pipe with an estimated 350 mmcfpd of initial throughput capacity. As of May 1, 2013, the Eureka Hunter Gas Gathering System consisted of 79 miles of 20-inch and 16-inch mainline, of which 45 miles is currently active. As of June 10, 2013, we were flowing approximately 100,000 mcf of natural gas per day through the Eureka Hunter Gas Gathering System.

In 2012, we completed the construction of our Pursley lateral section of the pipeline up to the Ohio River, which is a 20-inch lateral section of pipeline extending approximately 19 miles northerly through Tyler and Wetzel Counties, West Virginia, extending to the Ohio River, near Monroe County, Ohio. In January 2013, we successfully bored under the Ohio River to continue the construction of the lateral into Ohio.

In the fourth quarter of 2012, we completed the construction of our Lewis-Wetzel lateral, which is a 20-inch lateral section of pipeline extending approximately seven and one quarter miles originating near the eastern end of the mainline extending northerly through the Wetzel Wildlife Refuge in Wetzel County, West Virginia and terminating at our new Eureka Carbide Facility, near the community of Carbide in Wetzel County.

We completed the initial construction of the Eureka Carbide Facility in 2012. This facility includes (a) an 8-inch low-pressure liquids gathering section of pipeline extending approximately two and one third miles for gathering wellhead produced condensate and liquids from wells located in the Lewis Wetzel Wildlife area, (b) a 10-inch low-pressure gas gathering section of pipeline extending approximately two and one third miles for gathering gas production from wells located in the Lewis Wetzel Wildlife area and (c) equipment utilized to handle and stabilize liquids extracted from the pipeline during routine pigging operations as well as liquids gathered by the Lewis Wetzel condensate gathering system. The Eureka Carbide Facility facilitates our gathering of production from producing wells of Triad Hunter and Stone Energy in Wetzel County, West Virginia.

In the fourth quarter of 2012, we completed the construction of our Mobley lateral section of the pipeline, which is a 20-inch lateral section extending approximately eight miles originating at the Eureka Carbide Facility extending easterly and terminating at the inlet of the Mobley Processing Plant in Wetzel County, West Virginia, in order to provide access for gas processing at the plant.

In 2012, we began construction of our Doddridge lateral section of the pipeline, which is a 16-inch lateral section of pipeline extending southerly from the mainline into northwest Doddridge County, West Virginia. As of May 1, 2013, we had completed approximately 3.5 miles of the Doddridge lateral.

In 2012, we began construction of our Ritchie lateral section of the pipeline, which is a 16-inch lateral section of pipeline extending southerly from the western end of the mainline into northwest Richie County, West Virginia. As of May 1, 2013, we had completed approximately 15 miles of the Ritchie lateral.

We have budgeted approximately $100 million for Eureka Hunter Gas Gathering System projects in 2013. We anticipate these funds will be utilized primarily for pipeline construction projects in Ohio, including the construction of wet gas, dry gas and condensate gathering lines that will extend approximately 11 miles westerly from the Ohio River near Sardis, Ohio, and a separate lateral section that will extend approximately eight miles northerly and will run parallel to the Ohio River terminating near Triad Hunter’s Ormet area of operations.

Mobley Processing Plant

In late 2011, Triad Hunter entered into certain midstream services agreements with MarkWest, pursuant to which MarkWest agreed to provide long-term gas processing and related services for natural gas produced by both Triad Hunter and other producers and

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gathered through our Eureka Hunter Gas Gathering System. In December 2012, following completion of MarkWest’s 200 mmcfe per day Mobley Processing Plant in Wetzel County, West Virginia, Eureka Pipeline began flowing natural gas production through the Eureka Hunter Gas Gathering System for processing at the Mobley Processing Plant. Eureka Pipeline has supplied and expects to continue to supply the Mobley Processing Plant with both Company and third-party natural gas produced primarily from the Marcellus Shale formation. MarkWest also provides natural gas liquids handling and fractionation services for Mobley Processing Plant products at its nearby fractionation facility. These agreements with MarkWest allow Eureka Pipeline to offer third-party producers in the Marcellus Shale not only gas gathering services through our Eureka Hunter Gas Gathering System, but also access to natural gas processing at the Mobley Processing Plant. Also, our ability to process our natural gas at the Mobley Processing Plant has provided and is expected to continue to provide us with a significant uplift in the realized price for our liquids-rich gas stream. Effective as of April 2013, we have committed to approximately 95% of the processing capacity of the 200 mmcfe per day Mobley Processing Plant.

TransTex Hunter Treating and Processing

TransTex Hunter is a full service provider for the natural gas treating and processing needs of producers. TransTex Hunter currently operates in Texas, Louisiana, Oklahoma and West Virginia and anticipates possible future operations in Arkansas, Mississippi and Ohio. As of May 1, 2013, TransTex Hunter owned over 35 natural gas treating and processing plants in varying sizes and capacities designed to remove carbon dioxide, or CO2, and hydrogen sulfide, or H2S, from the natural gas stream. TransTex Hunter’s services also include the installation and maintenance of Joule-Thomson, or JT, plants, refrigeration plants and cryogenic plants designed to remove the heavier hydrocarbons from the natural gas stream for dew point control or for making the hydrocarbons marketable. TransTex Hunter’s customers include small, independent producers, as well as large, publicly-traded companies. Currently, TransTex Hunter is building small- and medium-size gas processing equipment to allow it to meet anticipated producer demand for gas processing units that can be utilized by producers until larger cryogenic processing plants are available, which typically require much longer construction lead times.

Other Gas Gathering and Processing

Gas Gathering. Natural gas production from our Magnum Hunter Production, Inc., or Magnum Hunter Production, properties is delivered through gas gathering and midstream facilities owned by Seminole Energy Services, L.L.C. under gas gathering and sales agreements with Seminole Energy and affiliates, referred to as the Seminole Energy gathering agreements. The Seminole Energy gathering agreements provide Magnum Hunter Production with long-term operating rights and firm capacity rights for daily delivery of up to 30,000 mcf of controlled gas through Seminole Energy’s Appalachian gathering system, which interconnects with Spectra Energy Partners’ East Tennessee Interstate pipeline network at Rogersville, Tennessee. This ensures continued deliverability from our connected fields, representing over 90% of our Magnum Hunter Production natural gas production, to major East Coast natural gas markets.

The Seminole Energy gathering agreements were restructured in connection with our acquisition of NGAS in April 2011. The restructured agreements substantially reduced the gas gathering fees payable by Magnum Hunter Production for all throughput volumes from future wells in the reserve areas dedicated to Seminole Energy under these agreements.

Gas Processing. Eureka Pipeline owns a 50% interest in a liquids extraction plant in Rogersville, Tennessee, used for the processing of natural gas delivered through Seminole Energy’s Appalachian gathering system. The Rogersville processing plant extracts natural gas liquids at levels enabling us to flow dry pipeline quality natural gas into the interstate network. The Rogersville processing plant is currently configured for throughput at rates up to 25,000 mcf per day, which can be increased to accommodate production growth and relief of constrained regional supplies.

Magnum Hunter Production owns a 50% interest in a nitrogen rejection facility in western Kentucky, used for the processing of Magnum Hunter Production’s Illinois Basin production. The nitrogen rejection facility is part of the infrastructure for Magnum Hunter Production’s New Albany Shale project in western Kentucky.

Both the Rogersville processing plant and the western Kentucky nitrogen rejection facility are co-owned and are operated by Seminole Energy. Gas processing fees are volume dependent and are shared with Seminole Energy.

Oil Field Services

Our wholly-owned subsidiary, Alpha Hunter Drilling, LLC, or Alpha Hunter Drilling, owns and operates portable, trailer-mounted drilling rigs capable of drilling to depths of between 6,000 to 19,000 feet, which are used primarily for vertical section (top-hole) air drilling in the Appalachian Basin. The drilling rigs are used for the Company’s Appalachian Basin operations and to provide drilling services to third parties. At May 1, 2013, Alpha Hunter Drilling’s operating fleet consisted of four Schramm T200XD drilling rigs and one new Schramm T500XD drilling rig. We took delivery of the Schramm T500XD rig in May 2013. This new rig is a portable, robotic drilling rig capable of drilling to depths (both vertically and horizontally) of up to 19,000 feet. This new rig can be used to drill the horizontal sections of wells.

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These drilling rigs primarily drill the top-holes of the Company's and third parties' Marcellus Shale wells in preparation for larger drilling rigs, which drill the horizontal sections of the wells. This style of drilling has proved to reduce overall drilling costs, by minimizing mobilization and demobilization charges and significantly decreasing the overall time to drill horizontal wells on each pad site.

At June 1, 2013, three of the Schramm T200XD drilling rigs were under contract to a large producer in the Appalachian Basin area for the top-hole drilling of multiple wells, one Schramm T200XD drilling rig was in transition from demobilization in south Texas (and scheduled to go out for work in late June 2013) and the Schramm T500XD drilling rig was under contract to the Company for drilling top-holes for its Marcellus Shale and Utica Shale drilling program. Currently, when a Company-used drilling rig is idle, Alpha Hunter Drilling seeks to lease the rig on the spot market.

Marketing and Pricing

General

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.

The Company generally markets its U.S. and Canadian oil and natural gas production under “month-to-month” or “spot” contracts.

We also derive revenue from our midstream operations.

Marketing of U.S. Production

We market crude oil produced from our Company-operated properties in North Dakota through a marketing and distribution firm under “month-to-month” or “spot” contracts, pursuant to which we receive spot market prices for the production. The crude oil is produced to tanks and then trucked to market. The crude oil produced from our third-party operated properties in North Dakota is sold by the operator along with the other well production. The production is typically transported to market by rail.

We generally sell our natural gas production on “month-to-month” or “spot” pricing contracts to a variety of buyers, including large marketing companies, local distribution companies and industrial customers. We diversify our markets to help reduce buyer credit risk and to ensure steady daily deliveries of our natural gas production. As natural gas production increases in our core operating areas, especially in the Appalachian Basin region, we believe that we and other producers in these areas will find it increasingly important to find markets that have the ability to move natural gas volumes through an increasingly capacity-constrained infrastructure.

Our natural gas liquids (other than ethane, when and if extracted) extracted and fractionated by MarkWest through its Mobley Processing Plant and related fractionation facility are or will be marketed by MarkWest at prevailing market prices. We will be responsible for the marketing of such ethane, if and when extracted, depending on when the Mobley Processing Plant goes into ethane recovery mode. We expect that several markets will be available at that time for ethane sales.

Marketing of Canadian Production

Our oil production in Alberta and Saskatchewan is sold through an international crude oil marketing firm. Our oil production is mostly 38 – 42 degrees API gravity and is considered “sweet” since it contains only a small percentage of sulfur. Typically, clean oil is hauled from our facilities to a truck terminal where it enters the North American pipeline system and is sold to purchasers at monthly spot prices. The majority of our oil production is sold at a bench mark price at Cromer, Canada and adjusted for equalization and all applicable transportation charges to Cromer. We have begun to ship some of our oil production from our Saskatchewan properties by rail, and we receive a price for this production similar to the benchmark price at Cromer after adjustments.

Our Canadian natural gas production is sold through a marketing consulting firm. We currently sell gas from our Alberta properties to a buyer at “spot” natural gas prices less transportation, fuel and measurement variance costs.

We sell a small amount of natural gas liquids extracted from some of our Alberta natural gas production to the processing plant operator at current spot prices.

Marketing of Midstream Services

Eureka Pipeline markets its gathering services to area producers primarily through “one on one” industry contacts generated through general industry knowledge and new contacts made through participation in industry conferences, as well as by tracking drilling permits. The Eureka Pipeline business development team monitors exploration efforts within reach of the Eureka Hunter Gas Gathering System and is in regular contact with companies that may benefit from the gathering services offered by Eureka Pipeline. Eureka Pipeline plans to continue these same marketing efforts as it expands the Eureka Hunter Gas Gathering System into Ohio.

TransTex Hunter markets its plants and services in very much the same manner as that of Eureka Pipeline. Much of TransTex Hunter's business growth comes from existing customers seeking additional plants and services.  New business is generated by the TransTex

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Hunter marketing team by regularly visiting with producers that have new or expanded drilling and production operations in those areas served by TransTex Hunter, by tracking drilling permits and through other producer referrals. TransTex Hunter also expands its presence by participating in industry conferences and trade shows and by helping to sponsor industry events that benefit charities and local community needs in its areas of operations.  

Pricing

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 uneconomic for us to commence or continue drilling for crude oil and natural gas. Historically, the prices received for oil and natural gas have fluctuated widely. Among the factors that can cause these fluctuations are:

• uncertainty in the global economy;

• changes in global supply and demand for oil and natural gas;

• the condition of the United States, Canadian and global economies;

• the actions of certain foreign countries;

• the price and quantity of imports of foreign oil and liquid natural gas;

• political conditions, including embargoes, war or civil unrest in or affecting oil producing activities of certain countries;

• the level of United States and global oil and natural gas exploration and production activity;

• the level of United States and global oil and natural gas inventories;

• production or pricing decisions made by the Organization of Petroleum Exporting Countries, or OPEC;

• weather conditions;

• technological advances affecting energy consumption or production; and

• the price and availability of alternative fuels.

Derivatives

We use commodity derivatives instruments, which we refer to as derivative contracts or derivatives, 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, preferred stock dividend payments and capital expenditures. 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 derivatives strategies that provide downside commodity price protection without unduly limiting our revenue potential in an environment of rising commodity prices. We use derivatives primarily to manage price risks and returns on certain acquisitions and drilling programs. Our policy is to use derivatives to cover an appropriate portion of our production at prices we deem attractive.

Derivatives may expose us to risk of significant financial loss in certain situations, including circumstances where:

• our production and/or sales of oil and natural gas are less than expected;

• payments owed under a derivative contract come due prior to receipt of the covered month’s production revenue; or

• the counterparty to the derivative contract defaults on its contract obligations.

In addition, derivative contracts we may enter into may limit the benefit we would receive from increases in the prices of oil and natural gas; if, for example, the increase in prices extends above the applicable ceiling under the derivative contract. Also, derivative contracts we may enter into may not adequately protect us from declines in the prices of oil and natural gas; if, for example, the decline in price does not extend below the applicable floor under the derivative contract.

Furthermore, should we choose not to engage in derivatives transactions in the future (to the extent we are not otherwise obligated to do so under our credit facilities), or we are unable to engage in such transactions due to a cross-default under a debt agreement, we may be adversely affected by volatility in oil and natural gas prices.

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As of December 31, 2012, we had the following derivatives in place:

			Weighted Avg
Natural Gas	Period	MMBTU/day	Price per MMBTU
Collars	Jan 2013 - Dec 2013	12,500	$4.50 - $5.96(1)
Swaps	Jan 2013 - Dec 2013	15,500	$3.52
Ceilings sold (call)	Jan 2014 - Dec 2014	16,000	$5.91
			Weighted Avg
Crude Oil	Period	Bbls/day	Price per Bbl
Collars	Jan 2013 - Dec 2013	2,763	$81.38 - $97.61
Three-way collar (2)	Jan 2014 - Dec 2014	663	$65.00 - $85.00 - $91.25
Three-way collar (2)	Jan 2015 - Dec 2015	259	$70.00 - $85.00 - $91.25
Three-way collar (2)	Jan 2013 - Dec 2013	2,000	$60.63 - $80.00 - $100.00
Three-way collar (2)	Jan 2014 - Dec 2014	4,000	$64.94 - $85.00 - $102.50
Three-way collar (3)	Jan 2013 - Dec 2013	763	$65.00 - $91.25 - $101.25
Swaps	Jan 2013 - Dec 2013	1,000	$91.46
Floors sold (put)	Jan 2013 - Dec 2013	1,438	$65.00
(1)  Weighted averages prices for sold put and sold call, respectively.
(2)  These three-way collars are a combination of three options: a sold put, a purchased put, and a sold call.
(3)  This three-way collar is a combination of three options: a sold put, a purchased call, and a sold call.

Magnum Hunter Production Drilling Partnerships

Prior to our acquisition of NGAS in April 2011, NGAS had, from 1992 through 2010, sponsored approximately 38 private drilling partnerships for accredited investors to participate in certain of its drilling initiatives. Generally, under these NGAS drilling partnerships, proceeds from the private placement of interests in each investment partnership, together with an NGAS capital contribution, were contributed to a separate joint venture or “program” that NGAS formed with that partnership to conduct the drilling operations.

In December 2011, our subsidiary, Magnum Hunter Production, Inc., or Magnum Hunter Production, completed its first sponsored drilling partnership, Energy Hunter Partners 2011-A, Ltd., raising approximately $12.9 million from accredited investors. In December 2012, Magnum Hunter Production completed its second sponsored drilling partnership, Energy Hunter Partners 2012-A Drilling & Production Fund, Ltd., raising approximately $20.3 million from accredited investors.

These two drilling partnerships were structured to allow the investors to participate with Magnum Hunter Production in certain Company drilling initiatives in certain operating regions of the Company, including unconventional resource plays. The drilling partnership participates in the designated project wells through a joint venture operating partnership, referred to as the program, with Magnum Hunter Production, which serves as the managing general partner of both the drilling partnership and the program. Proceeds from the private placement of interests in the drilling partnership, together with Magnum Hunter Production’s capital contributions, are contributed to the program to fund the program’s share of drilling and completion costs of the project wells. Generally, interests in the program are shared proportionately until distributions to the drilling partnership reach a certain percentage of its investment in the program (or in individual wells), after which Magnum Hunter Production will earn an additional reversionary interest in the program, the amount of which depends on the timing of such payout. The program participates in the drilling and completion of the project wells on a "cost plus" basis.

Magnum Hunter Production plans to sponsor an additional drilling and/or income partnership or partnerships in 2013 to participate in Company drilling initiatives. Our sponsored programs and any future sponsored programs are designed to enable us to accelerate the development of our properties without relinquishing control over drilling and operating decisions, while also enabling us to hold valuable acreage for future development.

Reserves

Our oil and natural gas properties are primarily located in (i) the Appalachian Basin in West Virginia, Ohio and Kentucky, with substantial acreage in the Marcellus Shale and Utica Shale areas in West Virginia and Ohio; and (ii) the Williston Basin in North Dakota and Canada. Cawley, Gillespie & Associates, Inc., independent petroleum consultants, which we refer to as CG&A, has

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estimated our oil and natural gas reserves and the present value of future net revenues therefrom as of December 31, 2012. These estimates were determined based on prices and costs as of or for the twelve-month period ended December 31, 2012. Since January 1, 2012, we have not filed, nor were we required to file, any reports concerning our oil and gas reserves with any federal authority or agency, other than the SEC and Canadian regulatory authorities. 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 become available.

Proved Reserves

In December 2008, the SEC released its finalized rule for “Modernization of Oil and Gas Reporting.” The 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 rule, companies are required to report on the independence and qualifications of their reserve preparers or auditors, 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 as defined in Rule 4.10(a) of Regulation S-X and Item 1200 of Regulation S-K promulgated by the SEC, as of December 31, 2012.

	Net Reserves (SEC Prices at 12/31/12)
Category	Oil	NGL	Gas	PV-10
	(mbbls)	(mbbls)	(mmcf)	($mm)
Proved Developed	16,355	6,262	125,526	$	707.1
Proved Undeveloped	20,472	2,863	37,094	$	274.1
Total Proved	36,827	9,125	162,620	$	981.2

The following table sets forth our estimated proved reserves, based on NYMEX futures strip pricing, as of December 31, 2012.

	Net Reserves (NYMEX Futures Prices at 12/31/12)
Category	Oil	NGL	Gas	PV-10
	(mbbls)	(mbbls)	(mmcf)	($mm)
Proved Developed	16,143	6,521	133,670	$	758.8
Proved Undeveloped	18,621	3,021	45,050	$	254.2
Total Proved	34,764	9,542	178,720	$	1,013.0

All of our reserves are located within the continental U.S. and Canada. 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 proved 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 financial statements for the year ended December 31, 2012 in conjunction with the following reserve estimates.

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

	2012		2011		2010
Description
Proved Developed Reserves
Oil (mbbls)	16,354.6		7,718.9		3,720.3
NGLs (mbbls)	6,262.6		1,459.8		—
Natural Gas (mmcf)	125,526.6		90,198.2		18,887.7
Proved Undeveloped Reserves
Oil (mbbls)	20,472.4		9,405.4		3,104.0
NGLs (mbbls)	2,862.7		3,125.8		—
Natural Gas (mmcf)	37,094.3		49,039.0		20,564.2
Total Proved Reserves (mboe)(1)(2)	73,055.6		44,916.1		13,399.7
PV-10 Value ($mm)(3)	$	981.2	$	616.9	$	177.8
Standardized Measure ($mm)	$	847.7	$	474.0	$	128.0

_______________

(1) The estimates of reserves in the table above conform to the guidelines of the SEC. Estimated recoverable proved reserves have been determined without regard to any economic impact that may result from our financial derivative activities. These calculations were prepared using standard geological and engineering methods generally accepted by the petroleum industry. The reserve information shown is estimated. The certainty of any reserve estimate is a function of the quality of available geological, geophysical, engineering and economic data, and the precision of the engineering and geological interpretation and judgment. The estimates of reserves, future cash flows and present value are based on various assumptions, and are inherently imprecise. Although we believe these estimates are reasonable, actual future production, cash flows, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves may vary substantially from these estimates.

(2) We converted natural gas to oil equivalent at a ratio of six mcf to one boe.

(3) Represents the present value, discounted at 10% per annum, or PV-10, of estimated future cash flows before income tax of our estimated proved reserves. The estimated future cash flows set forth above were determined by using reserve quantities of proved reserves and the periods in which they are expected to be developed and produced based on prevailing economic conditions. With respect to the 2012 PV-10 value in the table above, the estimated future production is priced based on the 12-month un-weighted arithmetic average of the first-day-of-the-month price for the period January through December 2012, using $94.71 per bbl and $2.75 per mmbtu and adjusted by lease for transportation fees and regional price differentials. Management believes that the presentation of the non-GAAP financial measure of PV-10 provides useful information to investors because it is widely used by professional analysts and sophisticated investors in evaluating oil and natural gas companies. For more information regarding the use of PV-10, see “Non-GAAP Measures; Reconciliations” below.

As of December 31, 2012, our proved undeveloped reserves, or PUDs, on an SEC basis totaled 23.3 mmboe of crude oil and ngls and 37.1 bcf of natural gas for a total of 29.5 mmboe. Changes in PUDs that occurred during the year were due to increased drilling activity and acquisitions in our Eagle Ford Shale, Marcellus Shale, Utica Shale and Bakken/Three Forks Sanish areas.

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The following table summarizes the changes in our proved reserves for the year ended December 31, 2012:

Proved Reserves (mboe)	For the Year  EndedDecember 31, 2012
Proved reserves—beginning of year	44,916
Revisions of previous estimates	16,842
Extensions and discoveries	3,506
Production	(4,814)
Purchases of reserves in place	12,626
Sales of reserves in place	(21)
Proved reserves—end of year	73,055
Proved developed reserves—beginning of year	24,212
Proved developed reserves—end of year	43,538

SEC Rules Regarding Reserves Reporting

In December 2008, the SEC adopted revisions to its rules designed to modernize 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.

Reserve Estimation

CG&A evaluated our oil and gas reserves on a consolidated basis as of December 31, 2012. The technical persons responsible for preparing our proved reserves estimates meet the requirements with regard 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. CG&A does not own an interest in any of our properties and is not employed by us on a contingent basis.

We maintain an internal staff of petroleum engineers and geoscience professionals who work closely with CG&A 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 CG&A periodically throughout the year to discuss the assumptions and methods used in the proved reserve estimation process. We provide historical information to CG&A 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 is completed in accordance with our internal control procedures, which include the verification of input data used by CG&A, as well as extensive management review and approval. All of our reserve estimates are reviewed and approved by our vice president of reservoir engineering. Our vice president of reservoir engineering holds a B.S. in chemical engineering from Ohio State University with more than 30 years of experience, was a member of the University of Texas External Advisory Committee for Petroleum and Geosystems Engineering and has served in various officer and board of director capacities for the Society of Petroleum Engineers. Reserve estimates for each of our Appalachia, Williston Hunter and Eagle Ford divisions are also reviewed and approved by the president of that division.

The technologies used in the estimation of our proved reserves are commonly employed in the oil and gas industry and include seismic and micro-seismic operations, reservoir simulation modeling, analyzing well performance data and geological and geophysical mapping.

62

Acreage and Productive Wells Summary

The following table sets forth our gross and net acreage of developed and undeveloped oil and natural gas leases as of December 31, 2012 (and includes the Eagle Ford Shale properties we subsequently sold in April 2013).

	DevelopedAcreage(1)		UndevelopedAcreage(2)		Total Acreage
	Gross	Net	Gross	Net	Gross	Net
Appalachian Basin (3)	270,266	247,983.0	292,793	241,934.0	563,059	489,917.0
Eagle Ford Shale	11,080	5,309.0	44,805	20,546.0	55,885	25,855.0
Williston Basin
Williston Hunter U.S.	138,688	45,158.0	169,039	77,687.0	307,727	122,845.0
Williston Hunter Canada	12,840	11,296.0	37,481	36,983.0	50,321	48,279.0
Other U.S.(4)	7,764	1,631.0	—	—	7,764	1,631.0
Other Canada (5)	24,790	19,689.0	20,640	16,499.0	45,430	36,188.0
Total at December 31, 2012	465,428	331,066.0	564,758	393,649.0	1,030,186	724,715.0

_______________

(1) Developed acreage is the number of acres allocated or assignable to producing wells or wells capable of production.        

(2) Undeveloped acreage is lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas, regardless of whether such acreage includes proved reserves.    

(3) Approximately 40,110 gross acres and 34,649 net acres overlap in our Utica Shale and Marcellus Shale areas.            

(4) Other U.S. pertains to certain miscellaneous properties in Texas (outside of the Eagle Ford Shale area) and Louisiana, for which no capital expenditures have been budgeted in 2013. See “Item 2. Properties-Other Properties”.                

(5) Other Canada pertains to our Alberta properties.                

The following table sets forth our gross and net acreage of developed and undeveloped oil and natural gas leases as of May 1, 2013, following our Eagle Ford Properties Sale in April 2013 and taking into account our drilling activities during 2013:

	DevelopedAcreage(1)		UndevelopedAcreage(2)		Total Acreage
	Gross	Net	Gross	Net	Gross	Net
Appalachian Basin (3)	270,091	247,771.0	291,622	242,645.0	561,713	490,416.0
Eagle Ford Shale	1,248.3	766.0	11,393.8	6,033.5	12,642	6,799.5
Williston Basin
Williston Hunter U.S.	168,017	64,477.0	169,039	75,388.0	337,056	139,865.0
Williston Hunter Canada	12,840	11,296.0	42,665	42,166.0	55,505	53,462.0
Other U.S.(4)	1,503.6	795.5	—	—	1,503.6	795.5
Other Canada (5)	24,790	19,689.0	20,640	16,499.0	45,430	36,188.0
Total at May 1, 2013	478,489.8	344,794.4	535,359.8	382,731.5	1,013,849.6	727,526.0

_______________

(1) Developed acreage is the number of acres allocated or assignable to producing wells or wells capable of production.        

(2) Undeveloped acreage is lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas, regardless of whether such acreage includes proved reserves.    

(3) Approximately 40,110 gross acres and 34,649 net acres overlap in our Utica Shale and Marcellus Shale areas.            

(4) Other U.S. pertains to certain miscellaneous properties in Texas (outside of the Eagle Ford Shale area) and Louisiana, for which no capital expenditures have been budgeted in 2013. See “Item 2. Properties-Other Properties”

(5) Other Canada pertains to our Alberta properties.        

Substantially all of the leases summarized in the preceding tables 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.

63

The following table sets forth the gross and net acres of undeveloped land subject to leases summarized in the preceding December 31, 2012 table that will expire during the periods indicated if not ultimately held by production by drilling efforts.

Year Ending December 31,	Expiring Acreage
	Gross	Net
2013	121,824	68,524
2014	126,791	88,473
2015	36,349	30,542
2016	72,488	61,014
2017	10,533	6,028
Thereafter	16,639	9,065

Productive wells consist of producing wells and wells capable of production, including shut-in wells and gas wells awaiting pipeline connection to commence deliveries and oil wells awaiting connection to production facilities.

The following table sets forth the number of productive oil and gas wells attributable to the Company's properties as of December 31, 2012:

	ProducingOil Wells		ProducingGas Wells		Total ProducingWells
	Gross	Net	Gross	Net	Gross	Net
Eagle Ford Shale	42	21.4	—	—	42	21.4
Appalachian Basin	847	791.6	3,040	1,954.5	3,887	2,746.1
Williston Basin
Williston Hunter U.S.	288	136.4	—	—	288	136.4
Williston Hunter Canada	38	34.0	—	—	38	34.0
Other U.S. (1)	4	0.8	20	2.4	24	3.2
Other Canada (2)	4	3.0	45	41.0	49	44.0
Total	1,223	987.2	3,105	1,997.9	4,328	2,985.1

_______________

(1) Other U.S. pertains to certain miscellaneous properties in Texas (outside of the Eagle Ford Shale area) and Louisiana, for which no capital expenditures have been budgeted in 2013. See “Item 2. Properties-Other Properties”.

(2) Other Canada pertains to our Alberta properties.

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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, except for certain of our activities in the Eagle Ford Shale and Marcellus Shale where we also utilized the drilling equipment of our subsidiary, Alpha Hunter Drilling.

	2012				2011				2010
	Gross		Net		Gross		Net		Gross		Net
Exploratory Wells:
Productive	55		19.2		51		19.7		8		6.7
Unproductive	—		—		—		—		—		—
Total Exploratory	55		19.2		51		19.7		8		6.7
Developmental Wells:
Productive	84		33.5		47		19.8		67		6.7
Unproductive	—		—		—		—		—		—
Total Development	84		33.5		47		19.8		67		6.7
Productive	139		52.7		98		39.5		75		13.4
Unproductive	—		—		—		—		—		—
Total	139		52.7		98		39.5		75		13.4
Success Ratio(1)	100	%	100	%	100	%	100	%	100	%	100	%

_______________

(1) The success ratio is calculated as follows: (total wells drilled—non-productive wells—wells awaiting completion)/(total wells drilled—wells awaiting completion).

As of May 1, 2013, we were in the process of drilling or completing two gross (1.5 net) wells on our Appalachian Basin properties, 19 gross (16.1 net) wells on our Williston Basin properties and one gross (0.3 net) wells on our Eagle Ford Shale properties.

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Oil and Gas Production, Prices and Costs

The following table shows the approximate net production attributable to our oil and gas interests, the average sales price and the average lease operating expense attributable to our total oil and gas production and for fields that contain 15% of our total proved reserves. Production and sales information relating to properties acquired is reflected in this table only since the closing date of the acquisition and may affect the comparability of the data between the periods presented.

		2012		2011		2010
Buffalo Field (1)	Oil Production (Bbls)	2,280		4,131		—
	Natural Gas Production (Mcf)	4,434,407		1,979,842		—
	Total Production (Boe)	741,348		334,104		—
	Oil Average Sales Price	$	72.79	$	80.90	—
	Natural Gas Average Sales Price	$	3.20	$	4.39	—
	Average Lease Operating Expense per Boe	$	2.44	$	5.01	—
Divide Field (2)	Oil Production (Bbls)	535,695		79,203		—
	Natural Gas Production (Mcf)	13,373		2,406		—
	Total Production (Boe)	537,924		79,604		—
	Oil Average Sales Price	$	80.17	$	84.92	—
	Natural Gas Average Sales Price	$	2.26	$	5.32	—
	Average Lease Operating Expense per Boe	$	11.04	$	15.20	—
Middlebourne Field (3)	Oil Production (Bbls)	49,823		11,927		3,917
	Natural Gas Production (Mcf)	6,198,272		1,974,524		265,598
	NGL Production (Bbls)	24,659		—		—
	Total Production (Boe)	1,107,527		341,015		48,184
	Oil Average Sales Price	$	83.30	$	88.69	$	70.95
	Natural Gas Average Sales Price	$	3.24	$	4.93	$	6.35
	NGL Average Sales Price	$	33.67	—		—
	Average Lease Operating Expense per Boe	$	5.00	$	5.58	$	11.22
Peach Creek Area Field (4)	Oil Production (Bbls)	700,965		247,273		14,722
	Natural Gas Production (Mcf)	166,792		64,695		—
	NGL Production (Bbls)	44,344		5,992		—
	Total Production (Boe)	773,107		264,048		14,722
	Oil Average Sales Price	$	102.30	$	94.11	$	79.95
	Natural Gas Average Sales Price	$	3.32	$	3.85	—
	NGL Average Sales Price	$	29.90	$	50.74	—
	Average Lease Operating Expense per Boe	$	8.79	$	5.75	$	6.52
Total Company	Oil Production (Bbls)	2,140,590		775,642		316,120
	Natural Gas Production (Mcf)	14,824,260		6,854,947		952,175
	NGL Production (Bbls)	202,477		92,982		—
	Total Production (Boe)	4,813,777		2,011,113		474,817
	Oil Average Sales Price	$	89.28	$	90.32	$	72.41
	Natural Gas Average Sales Price	$	3.19	$	4.59	$	5.07
	NGL Average Sales Price	$	34.74	$	51.30	—
	Average Lease Operating Expense per Boe	$	10.67	$	13.46	$	21.90

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_______________

(1)    This field is part of our Marcellus Shale acreage. This field consisted of 4,695 gross (4,666 net) acres in Wetzel County, West Virginia with 25 gross (18 net) producing wells as of May 1, 2013.

(2) This field is part of our Bakken/Three Forks Sanish formations acreage. This field consisted of 251,355 gross (112,412 net) acres in Divide County, North Dakota, with 191 gross (42.1 net) producing wells as of May 1, 2013.

(3) This field is part of our Marcellus Shale acreage. This field consisted of 14,700 gross (10,500 net) acres in Tyler County, West Virginia, with 11 gross (10.8 net) producing wells as of May 1, 2013.

(4) This field was part of our Eagle Ford Shale acreage, which was sold pursuant to our Eagle Ford Properties Sale in April 2013.

Title to Properties

We believe that we have satisfactory title to all of our producing properties in accordance with generally accepted industry standards. As is customary in the industry, in the case of undeveloped properties, often only minimal investigation of record title is made at the initial time of lease acquisition. A more comprehensive mineral title opinion review, a topographic evaluation and infrastructure investigations are made before the consummation of an acquisition of producing properties and before commencement of drilling operations on undeveloped properties. Individual properties may be subject to burdens that we believe do not materially interfere with the use or affect the value of the properties. Burdens on properties may include:

• customary royalty interests;

• liens incident to operating agreements and for current taxes;

• obligations or duties under applicable laws;

• development obligations under oil and gas leases;

• net profit interests;

• overriding royalty interests;

• non-surface occupancy leases; and

• lessor consents to placement of wells.

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Non-GAAP Measures; Reconciliations

This annual report contains certain financial measures that are non-GAAP measures. We have provided reconciliations within this report of the non-GAAP financial measures to the most directly comparable GAAP financial measures. These non-GAAP financial measures should be considered in addition to, but not as a substitute for, measures for financial performance prepared in accordance with GAAP that are presented in this report.

PV-10 is the present value of the estimated future cash flows from estimated total proved reserves after deducting estimated production and ad valorem taxes, future capital costs, abandonment costs, net of salvage value, and operating expenses, but before deducting any estimates of future income taxes. The estimated future cash flows are discounted at an annual rate of 10% to determine their “present value”. We believe PV-10 to be an important measure for evaluating the relative significance of our oil and gas properties and that the presentation of the non-GAAP financial measure of PV-10 provides useful information to investors because it is widely used by professional analysts and investors in evaluating oil and gas companies. Because there are many unique factors that can impact an individual company when estimating the amount of future income taxes to be paid, we believe the use of a pre-tax measure is valuable for evaluating the Company. We believe that PV-10 is a financial measure routinely used and calculated similarly by other companies in the oil and gas industry. However, PV-10 should not be considered as an alternative to the standardized measure as computed under GAAP.

The standardized measure of discounted future net cash flows relating to our total proved oil and gas reserves as of December 31, 2012 is as follows:

	As ofDecember 31, 2012, unaudited
	(in thousands)
Future cash inflows	$	4,248,384
Future production costs	(1,520,260		)
Future development costs	(603,809		)
Future income tax expense	(230,500		)
Future net cash flows	1,893,815
10% annual discount for estimated timing of cash flows	(1,046,162		)
Standardized measure of discounted future net cash flows related to proved reserves	$	847,653
Reconciliation of Non-GAAP Measure
PV-10	$	981,203
Less income taxes:
Undiscounted future income taxes	(230,500		)
10% discount factor	96,950
Future discounted income taxes	133,550
Standardized measure of discounted future net cash flows	$	847,653

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After giving effect to the Eagle Ford Properties Sale:

	As ofDecember 31, 2012, unaudited
	(in thousands)
Future cash inflows	$	3,193,153
Future production costs	(1,249,681		)
Future development costs	(376,598		)
Future income tax expense	(158,340		)
Future net cash flows	1,408,534
10% annual discount for estimated timing of cash flows	(775,344		)
Standardized measure of discounted future net cash flows related to proved reserves	$	633,190
Reconciliation of Non-GAAP Measure
PV-10	$	753,431
Less income taxes:
Undiscounted future income taxes	(158,340		)
10% discount factor	38,099
Future discounted income taxes	(120,241		)
Standardized measure of discounted future net cash flows	$	633,190

Item 3. LEGAL PROCEEDINGS

On April 23, 2013, Anthony Rosian, individually and on behalf of all other persons similarly situated, filed a class action complaint in the United States District Court, Southern District of New York, against the Company and certain of its officers, two of whom also serve as directors.  On April 24, 2013, Horace Carvalho, individually and on behalf of all other persons similarly situated, filed a similar class action complaint in the United States District Court, Southern District of Texas, against the Company and certain of its officers, two of whom also serve as directors.  Several substantially similar putative class actions have been filed in the Southern District of New York and in the Southern District of Texas. All such cases are collectively referred to as the Securities Cases. The complaints in the Securities Cases allege that the Company made certain false or misleading statements in its filings with the SEC, including statements related to the Company's internal and financial controls, the calculation of non-cash share-based compensation expense, the late filing of the Company's 2012 Form 10-K,  the dismissal of Magnum Hunter's previous independent registered accounting firm, and other matters identified in the Company's April 16, 2013 Form 8-K, as amended.  The complaints demand that the defendants pay unspecified damages to the class action plaintiffs, including damages allegedly caused by the decline in the Company's stock price between February 22, 2013 and April 22, 2013.  The Company and the individual defendants intend to vigorously defend the Securities Cases.  It is possible that additional putative class action suits could be filed over these events.

In addition, on May 10, 2013, Steven Handshu filed a shareholder derivative suit in the 151st Judicial District Court of Harris County, Texas on behalf of the Company against the Company's directors and senior officers. On June 6, 2013, Zachariah Hanft filed another shareholder derivative suit in the Southern District of New York on behalf of the Company against the Company's directors and senior officers. These suits are collectively referred to as the Derivative Cases.  The Derivative Cases assert that the individual defendants unjustly enriched themselves and breached their fiduciary duties to the Company by publishing allegedly false and misleading statements to the Company's investors regarding the Company's business and financial position and results, and allegedly failing to maintain adequate internal controls.   The complaints demand that the defendants pay unspecified damages to the Company, including damages allegedly sustained by the Company as a result of the alleged breaches of fiduciary duties by the defendants, as well as disgorgement of profits and benefits obtained by the defendants, and reasonable attorneys', accountants' and experts' fees and costs to the plaintiff.  The Derivative Cases are in their preliminary stages.  It is possible that additional shareholder derivative suits could be filed over these events.

The Company also received an April 26, 2013 letter from the SEC stating that the SEC's Division of Enforcement was conducting an inquiry regarding the Company's internal controls, change in outside auditors and public statements to investors and asking the Company to preserve documents relating to these matters.  The Company is complying with this request.

Item 4. MINE SAFETY DISCLOSURES.

Not applicable.

69

PART II

Item 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Common Stock Trading Summary

Our common stock trades on the NYSE under the symbol “MHR.” The following table summarizes the high and low reported sales prices on days in which there were trades of our common stock on the NYSE for each quarterly period for the last two fiscal years. On May 1, 2013, the last reported sale price of our common stock, as reported on the NYSE, was $2.52 per share.

	High		Low
2012:
First quarter	$	7.71	$	5.31
Second quarter	6.76		3.55
Third quarter	5.24		3.42
Fourth quarter	4.69		3.29
2011:
First quarter	$	8.62	$	6.44
Second quarter	8.66		5.76
Third quarter	7.90		3.28
Fourth quarter	5.59		2.33

Holders

As of May 1, 2013, based on information from our transfer agent, American Stock Transfer and Trust Company, we had 314 holders of record of the outstanding shares of our common stock, which record holders included Cede & Co., as nominee of The Depository Trust and Clearing Corporation, or DTC. As of that same date, Cede & Co., as nominee of the DTC, was the sole holder of record of the outstanding shares of our Series C Preferred Stock, Series D Preferred Stock and Depositary Shares representing our Series E Preferred Stock. Cede & Co., as nominee of the DTC, holds securities, including our common and preferred stock and our Depositary Shares, on behalf of numerous direct and indirect beneficial owners.

Dividends

We have not paid any cash dividends on our common stock since our inception and do not contemplate paying cash dividends on our common stock in the foreseeable future. Also, we are restricted from declaring or paying any cash dividends on our common stock under our MHR Senior Revolving Credit Facility and the indenture governing our Senior Notes. It is anticipated that earnings, if any, will be retained for the future operation of our business.

Securities Authorized for Issuance Under Equity Compensation Plans

The following table provides information with respect to shares of our common stock issuable under our equity compensation plans as of December 31, 2012:

	Number of Securitiesto be Issued UponExercise ofOutstanding Options,Warrants and Rights	Weighted-AverageExercise Price ofOutstanding Options,Warrants andRights		Number of SecuritiesRemaining Available forFuture Issuance UnderEquity Compensation Plans(Excluding SecuritiesReflected in Column(a))
	(a)	(b)		(c)
Equity compensation plans approved by security holders	14,846,994	$	6.01	1,469,349
Equity compensation plans not approved by security holders	—	—		—
Total	14,846,994	$	6.01	1,469,349

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The Company’s stock incentive plan provides for the grant of stock options, shares of restricted common stock, unrestricted shares of common stock, performance stock and stock appreciation rights. Awards under the stock incentive plan may be made to any employee, officer or director of the Company or any subsidiary or to consultants and advisors to the Company or any subsidiary. For additional information regarding our stock incentive plan, see "Note 11 — Share-Based Compensation” to our consolidated financial statements.

Share Performance Graph

The following performance graph and related information shall not be deemed “soliciting material” or to be “filed” with the SEC, nor shall such information be incorporated by reference into any future filings under the Securities Act or Exchange Act, except to the extent that the Company specifically incorporates it by reference into such filing.

The following graph illustrates changes over the five-year period ended December 31, 2012 in cumulative total stockholder return on our common stock as measured against the cumulative total return of the S&P 500 Index and the Dow Jones U.S. Exploration and Production Index. The results assume $100 was invested on December 31, 2007, and that dividends were reinvested.

COMPARISON OF 5 YEAR CUMULATIVE TOTAL RETURNS

	December 31,
	2007	2008	2009	2010	2011	2012
Magnum Hunter Resources Corporation	100.00	16.66	78.27	363.59	272.17	199.64
S & P 500	100.00	63.00	79.68	91.68	93.62	106.06
Dow Jones US Expl & Production	100.00	59.88	84.17	98.25	94.14	98.24

71

Item 6. SELECTED FINANCIAL DATA

The following selected consolidated financial data should be read in conjunction with the Company’s consolidated financial statements and related notes and Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

	Year Ended December 31,
	2012			2011			2010			2009			2008
	(In thousands, except per-share data)
Income Statement Data
Revenues	$	270,971		$	113,680		$	29,350		$	6,844		$	11,590
Loss from continuing operations	(139,360		)	(79,389		)	(22,681		)	(15,569		)	(9,468		)
Income from discontinued operations	230			2,977			2,350			445			2,582
Gain on sale of discontinued operations	2,409			—			6,660			—			—
Net loss	(136,721		)	(76,412		)	(13,671		)	(15,124		)	(6,886		)
Dividends on preferred stock	(34,706		)	(14,007		)	(2,467		)	(26		)	(734		)
Net loss attributable to common shareholders	$	(167,414	)	$	(90,668	)	$	(16,267	)	$	(15,150	)	$	(7,620	)
Basic and Diluted Earnings (Loss) Per Share
Continuing operations	$	(1.09	)	$	(0.83	)	$	(0.39	)	$	(0.40	)	$	(0.28	)
Discontinued operations	0.02			0.03			0.14			0.01			0.07
Net loss per share	$	(1.07	)	$	(0.80	)	$	(0.25	)	$	(0.39	)	$	(0.21	)
Statement of Cash Flows Data
Net cash provided by (used in)
Operating activities	$	58,011		$	33,838		$	(1,168	)	$	3,372		$	3,437
Investing activities	(1,009,207		)	(361,715		)	(118,281		)	(16,624		)	(10,379		)
Financing activities	996,442			342,193			117,721			9,413			(2,338		)
Balance Sheet Data
Total assets	$	2,198,632		$	1,168,760		$	248,967		$	66,584		$	61,665
Long-term debt	886,769			285,824			25,699			13,000			21,500
Other long-term obligations	155,677			124,609			4,834			2,673			1,590
Redeemable preferred stock	200,878			100,000			70,236			5,374			—
Shareholders’ equity	711,652			490,652			103,322			39,318			35,078

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

The following discussion is intended to assist you in understanding our results of operations and our financial condition. Our consolidated financial statements and the accompanying notes included elsewhere in this report contain additional information that should be referred to when reviewing this material. Statements in this discussion may be forward-looking. These forward-looking statements involve risks and uncertainties, which could cause actual results to differ from those expressed. See “Cautionary Notice Regarding Forward-Looking Statements” at the beginning of this report and “Risk Factors” in Item 1A for additional discussion of some of these factors and risks.

Business Overview

We are an independent oil and gas company engaged in the exploration for and the exploitation, acquisition, development and production of crude oil, natural gas and natural gas liquids resources in the United States and Canada. We are presently active in three of the most prolific unconventional shale resource plays in North America, specifically, the Marcellus Shale in West Virginia and Ohio; the Utica Shale in southeastern Ohio and western West Virginia; and the Williston Basin/Bakken Shale in North Dakota and Saskatchewan, Canada. Our oil and natural gas reserves and operations are primarily concentrated in West Virginia, Ohio, North Dakota, Saskatchewan, Kentucky and Texas. We are also engaged in midstream and oil field services operations, primarily in West Virginia, Ohio and Texas.

Our principal business strategy is to (a) exploit our substantial inventory of lower risk, liquids-weighted drilling locations, (b) acquire and develop long-lived proved reserves and undeveloped leases with significant exploitation and development opportunities primarily located in close proximity to our existing core areas of operation and (c) selectively monetize our assets at opportune times and attractive prices. Since the current management team assumed leadership of the Company in May 2009 and completely refocused our business strategy, we have substantially increased our assets and production base through a combination of acquisitions, joint ventures and ongoing development drilling efforts. We believe the increased scale in all our core resource plays allows for ongoing cost recovery and production efficiencies as we exploit and monetize our asset base. We are focused on the further development and exploitation of our asset base, selective “bolt-on” acquisitions of additional operated properties in our core operating regions, expansion of our midstream operations and, ultimately, the possible monetization of our assets.

In April 2013, we monetized our core properties in the oil window of the Eagle Ford Shale in Gonzales and Lavaca Counties in south Texas through a sale of these properties to an affiliate of Penn Virginia Corporation, or Penn Virginia, for a total purchase price of $422.1 million, paid to us in the form of $379.8 million in cash (before customary purchase price adjustments) and $42.3 million in Penn Virginia common stock (valued, for purposes of the purchase price calculation, at a price of $4.23 per share). We refer to this sale as our sale of the Eagle Ford Properties or our Eagle Ford Properties Sale. As a result of our sale of the Eagle Ford Properties, we are now strategically focused on our Marcellus Shale, Utica Shale and Williston Basin/Bakken Shale plays.

We have reallocated our 2013 capital expenditure budget of $100 million previously allocated to the Eagle Ford Shale to our other shale plays, resulting in a capital expenditure budget of $150 million for the Marcellus Shale and Utica Shale plays and $150 million for the Williston Basin/Bakken Shale play, for a total 2013 upstream capital expenditure budget of $300 million.

We are exploring the possible monetization in 2013 or 2014 of all or part of our midstream operations. We have also identified a number of non-core properties, which we believe represent approximately $100 million to $200 million in aggregate value, for possible divestiture in 2013 and 2014.

Our midstream operations are conducted through our majority-owned subsidiary, Eureka Hunter Holdings, LLC, or Eureka Holdings. Eureka Holdings conducts its operations primarily through the following two subsidiaries: (i) Eureka Hunter Pipeline, LLC, or Eureka Pipeline, which owns and operates a gas gathering system in West Virginia and Ohio, referred to as our Eureka Hunter Gas Gathering System; and (ii) TransTex Hunter, LLC, or TransTex Hunter, which is engaged primarily in the business of treating natural gas at the wellhead for third party producers in Texas and other states. We have obtained financing for our midstream operations through an equity purchase commitment from an unaffiliated third party (which also gives us the right to make capital contributions in conjunction with or alongside the capital contributions from the third party) and two separate credit facilities on a non-recourse basis to Magnum Hunter.

We also conduct oil field services operations through our wholly-owned subsidiary, Alpha Hunter Drilling, LLC, or Alpha Hunter Drilling, which owns and operates five drilling rigs that are used primarily for vertical section (top-hole) air drilling in the Appalachian Basin. Alpha Hunter Drilling recently took delivery of a new drilling rig that can also drill the horizontal sections of wells in the shale plays where we are active.

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Summary of Principal Upstream Properties

Appalachian Basin

As of May 1, 2013, our Appalachian Basin properties included approximately 561,713 gross (490,416 net) acres, located primarily in the Marcellus Shale, Utica Shale and southern Appalachian Basin. At December 31, 2012, proved reserves attributable to our Appalachian Basin properties were 36.5 mmboe on an SEC basis, of which 31% were oil and liquids and 66% were classified as proved developed producing, and 39.8 mmboe on a NYMEX basis. As of May 1, 2013, our Appalachian Basin properties included approximately 3,887 gross (2,746.1 net) productive wells, of which we operated approximately 83%.

Williston Basin

As of May 1, 2013, our Williston Basin properties included approximately 392,561 gross (193,327 net) acres. As of December 31, 2012, proved reserves attributable to our Williston Basin properties were 23.7 mmboe on an SEC basis, of which 96% were oil and natural gas liquids and 41% were classified as proved developed producing, and 21.7 mmboe on an NYMEX basis. As of May 1, 2013, our Williston Basin properties included approximately 395 gross (210.1 net) productive wells, of which we operated approximately 47%.

Summary of Midstream Operations

Eureka Pipeline

As of May 1, 2013, our Eureka Hunter Gas Gathering System included approximately 79 miles of completed gathering pipeline, located in northwestern West Virginia and crossing into Ohio, in the Marcellus Shale and Utica Shale. We continue to develop this gathering system.

TransTex Hunter

TransTex Hunter is primarily engaged in the business of treating natural gas at the wellhead for third-party producers, with a focus on associated natural gas produced from various oil shale plays.

Summary of Oil Field Services Operations

As of May 1, 2013, our wholly-owned subsidiary, Alpha Hunter Drilling, owned and operated four Schramm T200XD drilling rigs and one new Schramm T500XD drilling rig. The drilling rigs are used for the Company’s Appalachian Basin operations and to provide drilling services to third parties. These drilling rigs primarily drill the top-holes of wells in preparation for larger drilling rigs, which drill the horizontal sections of the wells.

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2012 Highlights and 2013 Outlook

Our activities in 2012 included several notable acquisitions, including the acquisitions of the Acquired Baytex Assets and the Acquired Samson Assets, the Utica Acreage Acquisition and the Virco Acquisition. In addition, in 2012, we significantly increased our drilling capital expenditure program to approximately $300 million, which was focused primarily on oil and liquids rich natural gas projects due to the decline in natural gas prices. We have this flexibility because a substantial portion of our natural gas acreage is held by production. As a result of these acquisitions and increased capital expenditures and our shift in strategy to a more liquids focus:

• Our production mix consisted of approximately 57% oil and liquids in the fourth quarter of 2012 compared to 35% oil and liquids in the first quarter of 2012.

• Our production increased 139% from 5,510 average boepd for 2011 to 13,188 average boepd for 2012 as a result of acquisitions and the increased capital expenditures.

• Our revenues increased commensurately at a rate of 138% in 2012, compared with 2011.

In April 2013, we sold our core Eagle Ford Shale properties to an affiliate of Penn Virginia for approximately $422.1 million, including $379.8 million in cash (before customary purchase price adjustments) and $42.3 million in Penn Virginia common stock. As a result, our strategic focus is now on the liquids rich portions of the Marcellus and Utica Shales in Appalachia and oil production in the Bakken Shale in North Dakota and Saskatchewan. Our 2013 upstream capital budget of $300 million is allocated approximately $150 million for each of the Appalachian Basin and Williston Basin divisions.

In the Appalachian Basin area, we intend to drill 27 gross (18 net) Marcellus Shale wells in 2013, with the vast majority of these wells expected to come on line in the second half of 2013. Our focus in the Marcellus Shale will be primarily in northwest West Virginia in Tyler and Wetzel Counties and in southeastern Ohio in Monroe County. We commenced drilling activity in the Utica Shale in April 2013, and, subject to our drilling results in 2013, we expect to significantly expand our drilling efforts in the play in 2014. We expect to have drilling results from our initial Utica Shale well in August or September 2013. We plan to drill and complete three additional horizontal wells in the Utica Shale in 2013. We currently expect to process our liquids rich gas production from the Marcellus Shale and Utica Shale at the Mobley Processing Plant (or other anticipated closer gas processing facilities) using our gathering capacity on our Eureka Hunter Gas Gathering System.

In the Williston Basin area, we plan to drill approximately 65 gross (22.0 net) wells in 2013. Our focus will be in northwest Divide County, North Dakota. We believe this area has the potential for the highest rate of return in our current inventory of properties in the Williston Basin. We are focusing our efforts primarily on developing the middle Bakken zone in this area. Currently, we have booked only a relatively small amount of proved reserves in this area.

We have targeted additional strategic divestitures to further strengthen our capital position and focus on our three core shale plays. We are exploring the monetization in 2013 or 2014 of the Eureka Hunter Gas Gathering System. We have also identified non-core properties in our portfolio, which we believe represent approximately $100 million to $200 million in aggregate value, for possible divestiture in 2013 and 2014. These potential divestitures would allow us to significantly expand our activities in our core shale areas in the Marcellus, Utica and Bakken, while at the same time substantially improving our financial position and balance sheet.

The net proceeds from our Eagle Ford Properties Sale and expected net proceeds in 2013 and 2014 from sales of non-strategic properties will lessen the impact of our reduced ability to access the capital markets using short-form registration statements or “at-the-market” offerings as a result of this annual report not having been filed within, and our Form 10-Q for the quarter ended March 31, 2013 to be filed after, the time frames permitted by the SEC. See “Risk Factors - Our failure to timely file certain periodic reports with the SEC limits our access to the public markets to raise debt or equity capital.” We also expect our credit facilities to furnish us with additional liquidity, although our ability to access such facilities could be curtailed or eliminated if (i) we fail to file such Form 10-Q by the lenders' extended deadline of July 12, 2013 or within any additional extended time period our lenders may in the future provide us or (ii) an uncured cross-default under such facilities results from any uncured “event of default” under the indenture relating to our Senior Notes stemming from our late SEC filings. See “Risk Factors - Our existing Senior Notes indenture defaults restrict our ability to utilize certain exceptions to the restrictive covenants contained therein and, under certain circumstances, may result in the acceleration of the Senior Notes issued under our indenture and the outstanding debt under our credit facilities, which would have a material adverse effect on our business, financial condition and liquidity.”

Internal Controls

The Company's management, including the Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer, with the assistance of outside consultants, has conducted an assessment of the effectiveness of the Company's internal control over financial reporting as of December 31, 2012 based on the criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Management excluded from our assessment the internal control over financial reporting of Virco, which was acquired on November 2, 2012 and of TransTex Hunter, the assets of which were initially acquired on April 2, 2012. The subsidiaries excluded from management's assessment of internal controls over financial reporting made up combined total assets of approximately 8 percent and 3 percent of total revenue of the corresponding consolidated financial statement amounts as of and for the year ended December 31, 2012. Based on its assessment, management has concluded

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that, as of December 31, 2012, the Company's internal control over financial reporting was not effective due to the material weaknesses described in Item 9A of this annual report . The Company believes that such weaknesses are attributable primarily to its recent rapid growth. Management is actively addressing these issues and has developed a detailed remediation plan for this purpose.

Partly as a result of these weaknesses, the Company was unable to file this annual report and its Form 10-Q for the quarter ended March 31, 2013 by the required SEC filing deadlines. The Company expects to file its Form 10-Q for the quarter ended March 31, 2013 within 30 days of the filing of this annual report, but not later than July 12, 2013.

In addition, as previously publicly disclosed, the Company did not design effective controls over share-based compensation expense, which is recorded in the Company's general and administrative expenses. Specifically, the Company did not design effective controls related to the review of supporting details, including the accuracy of the vesting inputs and calculations and the journal entries for share-based compensation expenses. This control deficiency resulted in a misstatement of the Company's general and administrative expense and share-based compensation related disclosures for the three- and six-month periods ended June 30, 2012 and resulted in the restatement of the financial statements for such fiscal periods.

The board of directors, the audit committee of the board and senior management of the Company consider it essential that they provide the appropriate “tone at the top” to assure the Company achieves effective and comprehensive internal controls over financial reporting.  To further such objective, the board of directors, the audit committee and senior management have adopted a proactive “hands on” approach to address the Company's internal control deficiencies, including the development of a detailed remediation plan. As part of this plan, the Company has hired, and will continue to dedicate substantial resources to hire, additional accounting personnel with greater expertise, has engaged outside consultants and a "Big Four" accounting firm to assist it and is investing in new information systems.

See "Item 9A - Controls and Procedures" in this annual report for a more detailed description of the material weaknesses in the Company's internal controls identified by management and the remediation measures being taken by the Company to address these weaknesses.

Critical Accounting Policies and Estimates

The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting policies generally accepted in the U.S. The preparation of our consolidated financial statements requires us to make estimates and assumptions that affect our reported results of operations and the amount of reported assets, liabilities and proved oil and gas reserves. Some accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. Actual results may differ from the estimates and assumptions used in the preparation of our consolidated financial statements. Described below are the most significant policies we apply in preparing our consolidated financial statements, some of which are subject to alternative treatments under U.S. GAAP. We also describe the most significant estimates and assumptions we make in applying these policies. See "Note 3 – Summary of Significant Accounting Policies" to our consolidated financial statements.

Oil and Gas Activities—Successful Efforts

Accounting for oil and gas activities is subject to unique rules. We use the successful efforts method of accounting for our oil and gas activities. The significant principles for this method are:

• Geological and geophysical evaluation costs are expensed as incurred.

• Dry holes for exploratory wells are expensed, and dry holes for developmental wells are capitalized.

• Capitalized costs relating to proved oil and gas properties, including wells and related equipment and facilities, are evaluated for impairment based on an analysis of undiscounted future net cash flows in accordance with ASC 360, Accounting for the Impairment or Disposal of Long Lived Assets. If undiscounted cash flows are insufficient to recover the net capitalized costs relating to proved properties, then we recognize an impairment charge to proved property impairment expense equal to the difference between the net capitalized costs relating to proved properties and their estimated fair values based on the present value of the related future net cash flows.

• Capitalized costs relating to unproved oil and gas properties are evaluated for impairment based on an analysis of undiscounted future net cash flows in accordance with ASC 932, Property, Plant and Equipment. The Company impairs an unproved lease if it becomes probable that its carrying value will not be recovered based on management's outlooks. By their nature, unproved properties' impairment assessments are judgmental unless active exploration of the project is underway or clear intent exists to allow the underlying leaseholds to expire before exploring them for proved reserves. If impairment indicators exist, inquiries become more critical and demanding. Factors that affect the impairment assessments include but may not be limited to: results of exploration activities, commodity price outlooks, planned future sales, expirations or extensions of all or a portion of the projects, and capital budgeting considerations. For properties assessed, if the property is surrendered or the lease expires without identifying proved reserves, the cost of the property is recognized as a charge to exploration and abandonment expense.

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Proved Reserves

For the year ended December 31, 2012, we engaged Cawley, Gillespie & Associates, Inc., independent petroleum engineers, to prepare independent estimates of the extent and value of the proved reserves associated with our oil and gas properties in accordance with guidelines established by the SEC, including the 2008 revisions designed to modernize oil and gas reserve reporting requirements. We adopted these revisions effective December 31, 2009.

Estimates of proved oil and gas reserves directly impact financial accounting estimates including depletion, depreciation and amortization expense, evaluation of impairment of properties and the calculation of plugging and abandonment liabilities. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations. The process of estimating quantities of proved reserves is very complex, requiring significant subjective decisions in the evaluation of all geological, engineering and economic data for each reservoir. The data for any reservoir may change substantially over time due to results from operational activity. Proved reserve volumes at December 31, 2012, were estimated based on the un-weighted, arithmetic average of the closing price on the first day of each month for the 12-month period prior to December 31, 2012 for oil and natural gas in accordance with the SEC’s reserve rules. The average price used for oil was $94.71 and for natural gas was $2.75.

See also "Item 1. Business” and "Item 2. Properties—Proved Reserves” and "Note 16—Other Information" to our consolidated financial statements for additional information regarding our estimated proved reserves.

Derivative Instruments and Commodity Derivative Activities

Marked-to-market at fair value, derivative contracts are included on our consolidated balance sheets as current or non-current assets or liabilities based on the anticipated timing of cash settlements under the related contracts. We record changes in such fair value in earnings on our consolidated statements of operations under the caption entitled “Gain (loss) on derivative contracts, net.”

Although we have not designated our derivative instruments as cash-flow hedges, we use those instruments to reduce our exposure to fluctuations in commodity prices related to our oil and gas production. We record both realized and unrealized gains and losses under those instruments in other revenues on our consolidated statements of operations. Unrealized gains and losses result from changes in the fair market value of the derivative contracts from period to period, and represent non-cash gains or losses. Changes in commodity prices could have a significant effect on the fair value of our derivative contracts.

We estimate the fair values of swap contracts based on the present value of the difference in exchange-quoted forward price curves and contractual settlement prices multiplied by notional quantities. We internally valued the collar contracts using industry-standard option pricing models and observable market inputs. We use third-party valuations providers to determine the fair values of the contracts that are reflected on our consolidated balance sheets. Realized gains and losses are also included in “Gain (loss) on derivative contracts” on our consolidated statements of operations.

Changes in the derivative’s fair value are currently recognized in the statement of operations unless specific commodity derivative hedge accounting criteria are met and such strategies are designated. We continue not to designate our derivative instruments as cash-flow hedges.

We are exposed to credit losses in the event of nonperformance by the counterparties on our commodity derivatives positions and have considered the exposure in our internal valuations. However, we do not anticipate nonperformance by the counterparties over the term of the commodity derivatives positions.

The following table summarizes the net gain (loss) on our derivative contracts for the years ended December 31, 2012, 2011 and 2010:

		For the Year Ended December 31,
		2012		2011			2010
	(in thousands)
Realized gain (loss)		$	11,294	$	(2,136	)	$	3,877
Unrealized gain (loss)		10,945		(4,210		)	(3,063		)
Net gain (loss)		$	22,239	$	(6,346	)	$	814

A hypothetical 10% increase in the NYMEX floating prices would have resulted in a $27.8 million decrease in the December 31, 2012 fair value of the derivative liabilities recorded on our balance sheet and a corresponding increase to the loss on commodity derivatives in our statement of operations. A hypothetical 10% decrease in the NYMEX floating prices would have a resulted in a $24.2 million increase in the December 31, 2012 fair value of the derivative liabilities recorded on our balance sheet and would have increased the gain on commodity derivatives in our statement of operations by the corresponding amount.

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The Company also has preferred stock derivative liabilities resulting from certain conversion features, redemption options, and other features of the Series A Convertible Preferred Units of Eureka Hunter Holdings, LLC, and a convertible security embedded derivative asset primarily due to the conversion feature of the promissory note received by us as partial consideration for the sale of Hunter Disposal, LLC. See "Note 3—Summary of Significant Accounting Policies,” "Note 4—Fair Value of Financial Instruments,” "Note 5—Financial Instruments and Derivatives,” and "Note 12—Shareholders’ Equity", for more information on our derivative instruments.

Asset Retirement Obligation

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

Our liability is determined using significant assumptions, including current estimates of plugging and abandonment costs, annual inflation of these costs, the productive lives of wells and our risk-adjusted interest rate. Changes in any of these assumptions can result in significant revisions to the estimated asset retirement obligation. Our liability for asset retirement obligations was approximately $30.9 million and $20.6 million at December 31, 2012 and 2011, respectively. See "Note 9—Asset Retirement Obligations” to our consolidated financial statements for more information.

Share-Based Compensation

The Company estimates the fair value of share-based payment awards made to employees and directors, including stock options, restricted stock and employee stock purchases related to employee stock purchase plans, on the date of grant using an option-pricing model. The value of the portion of the award that is ultimately expected to vest is recognized as an expense ratably over the requisite service periods. Awards that vest only upon achievement of performance criteria are recorded only when achievement of the performance criteria is considered probable. We estimate the fair value of each share-based award using the Black-Scholes option pricing model or a lattice model. These models are highly complex and dependent on key estimates by management. The estimates with the greatest degree of subjective judgment are the estimated lives of the stock-based awards, the estimated volatility of our stock price, and the assessment of whether the achievement of performance criteria is probable. For the years ended December 31, 2012, 2011 and 2010, we recognized approximately $15.7 million, $25.1 million, and $6.4 million in non-cash stock compensation, respectively. See "Note 11—Share-Based Compensation” to our consolidated financial statements for additional information.

Impairment and Disposition of Long Lived Assets

The Company accounts for the impairment and disposition of long-lived assets in accordance with ASC 360, Accounting for the Impairment or Disposal of Long-Lived Assets. ASC 360 requires that the Company’s long-lived assets, including its proved oil and gas properties, be assessed for potential impairment in their carrying values whenever events or changes in circumstances indicate such impairment may have occurred. An impairment charge to current operations is recognized when the estimated undiscounted future net cash flows of the asset are less than its carrying value. Any such impairment is recognized based on the differences in the carrying value and estimated fair value of the impaired asset.

The guidance provides for future revenue from the Company’s oil and gas production to be estimated based upon prices at which management reasonably estimates such products will be sold. These estimates of future product prices may differ from current market prices of oil and gas. Any downward revisions to management’s estimates of future production or product prices could result in an impairment of the Company’s proved oil and gas properties in subsequent periods.

The long-lived assets of the Company which are subject to evaluation consist primarily of oil and gas properties. Impairment reviews are performed quarterly by management. The Company recognized a non-cash, pre-tax charge against earnings related to the impairment of proved property of approximately $4.1 million, $21.8 million, and $0.3 million, for the years ended December 31, 2012, 2011, and 2010, respectively.

Capitalized costs relating to unproved oil and gas properties are evaluated for impairment based on an analysis of undiscounted future net cash flows in accordance with ASC 932, Property, Plant and Equipment. The Company impairs an unproved lease if it becomes probable that its carrying value will not be recovered based on management's outlooks. During 2012, the Company's exploration and abandonment expense was primarily attributable to $70.6 million in leasehold impairments and $43.8 million in leasehold abandonment expense, which included $33.6 million and $10.2 million associated with the Company's unproved properties in the Williston Basin and Appalachian Basin. The significant components of the Company's 2011 leasehold abandonment expense included unproved acreage abandonments of $802,000 and $306,000 in the Appalachian Basin and Eagle Ford Shale areas, respectively, and $1.5 million of exploration costs.

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By their nature, unproved properties' impairment assessments are judgmental unless active exploration of the project is underway or clear intent exists to allow the underlying leaseholds to expire before exploring them for proved reserves. If impairment indicators exist, inquiries become more critical and demanding. Factors that affect the impairment assessments include but may not be limited to: results of exploration activities, commodity price outlooks, planned future sales, expirations or extensions of all or a portion of the projects, and capital budgeting considerations. For properties assessed, if the property is surrendered or the lease expires without identifying proved reserves, the cost of the property is recognized as a charge to exploration and abandonment expense.

The Company recognized a non-cash, pre-tax charge against earnings related to expirations of leaseholds for properties that we chose not to develop of approximately $43.8 million and $1.1 million for the years ended December 31, 2012 and 2011, respectively. See "Note 3—Summary of Significant Accounting Policies” to our consolidated financial statements for additional information.

Goodwilland Intangible Assets

Goodwill represents the excess of the purchase price of an entity over the estimated fair value of the assets acquired and the liabilities assumed. Intangible assets consist primarily of the fair value of the acquired gas treating agreements and customer relationships in the TransTex Gas Services, LP assets acquisition.  The intangible assets were valued at fair value using a discounted cash flow model with a discount rate of 13%.  Such assets are being amortized over the weighted average term of 8.5 years.  The customer relationships are being amortized with a 12.5 year life.The Company assesses the carrying amount of goodwill and intangible assets by testing for impairment annually on April 1, or whenever interim impairment indicators arise. Amortizable intangible assets are required to be evaluated at least annually for impairment. Other intangible assets are evaluated for impairment when events or changes in circumstances indicate the carrying value may not be recoverable. At December 31, 2012, our other intangible assets were not impaired.

Revenue Recognition

Revenues associated with sales of crude oil and liquids, natural gas, petroleum products, and other items are recognized when earned. Revenues are considered earned when the products are delivered, which occurs when the customer has taken title and has assumed the risks and rewards of ownership, prices are fixed or determinable and collectability is reasonably assured.

Revenues from the production of crude oil and natural gas properties in which we have an interest with other producers are recognized based on the actual volumes we sold during the period. Any differences between volumes sold and entitlement volumes, based on our net working interest, which are deemed to be non-recoverable through remaining production, are recognized as accounts receivable or accounts payable, as appropriate. Cumulative differences between volumes sold and entitlement volumes are not significant.

Revenues from field servicing activities are recognized at the time the services are provided and earned as provided in the various contract agreements. Gas gathering revenues are recognized at the time the natural gas is delivered at the destination point.

Income Taxes

Income taxes are accounted for in accordance with FASB ASC 740, under which deferred income taxes are recognized for the future tax effects of temporary differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities using the enacted statutory tax rates in effect at year-end. The effect on deferred taxes for a change in tax rates is recognized in earnings in the period that includes the enactment date. A valuation allowance for deferred tax assets is recorded when it is more likely than not that the benefit from the deferred tax asset will not be realized.

Uncertain Income Tax Positions

Under accounting standards for uncertainty in income taxes (ASC 740-10), a company recognizes a tax benefit in the financial statements for an uncertain tax position only if management's assessment is that the position is “more likely than not” (i.e., a likelihood greater than 50 percent) to be allowed by the tax jurisdiction based solely on the technical merits of the position. The term “tax position” in the accounting standards for income taxes refers to a position in a previously filed tax return or a position expected to be taken in a future tax return that is reflected in measuring current or deferred income tax assets and liabilities for interim or annual periods. No material uncertain tax positions existed at December 31, 2012.

Effects of Inflation

Inflation in the United States has been relatively low in recent years and did not have a material impact on our results of operations for the years ended December 31, 2012, 2011 and 2010. Although the impact of inflation has been insignificant in recent years, it is still a factor in the U.S. economy and may increase the cost to acquire or replace property, plant and equipment. It may also increase the cost of labor or supplies. To the extent permitted by competition, regulation and our existing agreements, we have and will continue to pass along increased costs to our customers in the form of higher prices.

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Results of Operations

The following table sets forth summary information regarding oil, natural gas and natural gas liquids revenues, production, average product prices and average production costs and expenses for the last three fiscal years. See the “Glossary of Oil and Natural Gas Terms” section of this annual report for explanations of the terms used below.

		Years Ended December 31,
		2012		2011		2010
Oil and gas revenue and production
Revenues (in thousands except per unit)
Oil	US	$	152,138	$	60,193	$	22,892
	Canada	38,974		9,864		—
Gas	US	46,696		30,544		4,823
	Canada	552		834		—
NGLs	US	7,004		4,737		—
	Canada	30		33		—
	Total oil and gas sales	$	245,394	$	106,205	$	27,715
Production
Oil (mbbls)	US	1,684		671		316
	Canada	456		105		—
Gas (mmcfs)	US	14,612		6,654		952
	Canada	212		201		—
NGLs(mboe)	US	202		91		—
	Canada	1		1		—
MBOE		4,814		2,011		475
BOE/DAY		13,152		5,510		1,301
Average prices
Oil (per bbl)	US	$	90.35	$	89.76	$	72.41
	Canada	$	85.33	$	93.92	$	0
Gas (per mcf)	US	$	3.20	$	4.60	$	5.07
	Canada	$	2.59	$	4.15	$	0
NGL (per boe)	US	$	34.71	$	51.35	$	0
	Canada	$	46.32	$	46.08	$	0
	Total average price (per boe)	$	50.98	$	52.81	$	58.37
Costs and expenses (per boe)
Lease operating		$	10.67	$	13.1	$	22.51
Severance tax and marketing		$	3.13	$	3.72	$	5.01
Exploration and abandonment		$	24.35	$	1.32	$	1.98
Impairment of properties		$	0.85	$	10.84	$	0.64
General and administrative (1)		$	13.38	$	31.28	$	52.17
Depletion, depreciation and accretion		$	28.22	$	24.25	$	18.44
Midstream and Oil Field Services segments (in thousands)
Oil Field Services segment revenue		$	12,333	$	7,149	$	1,222
Oil Field Services segment expense		$	10,037	$	6,759	$	1,272
Midstream segment revenue		$	13,040	$	494	$	163
Midstream segment expense		$	8,028	$	373	$	214

(1) General and administrative expense includes:

(i) acquisition related expenses of $4.7 million ($0.99 per boe) in 2012, 8.9 million ($4.42 per boe) in 2011, and $2.2 million ($4.69 per boe) in 2010; and

(ii) non-cash stock compensation of $15.7 million ($3.26 per boe) in 2012, $25.1 million ($12.46 per boe) in 2011, and $6.4 million ($13.32 per boe) in 2010.

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Years ended December 31, 2012 and 2011

Oil and gas production. Production increased by 139%, or 2,803 mboe, to 4,814 mboe for the year ended December 31, 2012 compared to the year ended December 31, 2011. Our average daily production was 13,152 boepd during 2012, representing an overall increase of 139%, or 7,642 boepd compared to 5,510 boepd for 2011. The increase in production in 2012 compared to 2011 is primarily attributable to acquisitions as well as organic growth through the Company’s expanded drilling program. Production for 2012, on a boe basis, was 49% oil and ngls and 51% natural gas compared to 43% oil and ngls and 57% natural gas for 2011. The change was attributable to increased focus on the development of oil production in the Eagle Ford Shale and Williston Basin regions.

U.S. Upstream segment. In the U.S. Upstream Production operating segment, production increased 131%, from 1,872 mboe to 4,321 mboe for the year ended December 31, 2012 compared to the year ended December 31, 2011. Production for 2012 on a boe basis was 44% oil and ngls and 56% natural gas compared to 41% oil and ngls and 59% natural gas for 2011. Our average daily production increased from 5,128 boepd, to 11,806 boepd during 2012 compared to 2011. This increase in production for the U.S. Upstream segment in 2012 compared to 2011 is primarily attributable to the Acquired Baytex Assets and Acquired Eagle Assets as well as organic growth through the Company’s expanded drilling program.

Canadian Upstream segment. Production increased in the Canadian Upstream operating segment by 254%, or 354 mboe, to 493 mboe for the year ended December 31, 2012 from 139 mboe for the year ended December 31, 2011. Production from the Canadian segment comprised 93% oil and ngls and 7% natural gas on a boe basis in 2012 compared to 76% oil and ngls and 24% natural gas on a boe basis in 2011. The Canadian operating segment initiated production as part of Magnum Hunter in 2011, due to the NuLoch acquisition completed in the first half of 2011.

Oil and gas sales. Oil and gas sales increased 131%, or $139.2 million, for the year ended December 31, 2012 to $245.4 million from $106.2 million for the year ended December 31, 2011. The increase in oil and gas sales principally resulted from increases in our oil and natural gas production as a result of acquisitions and expanded drilling completed throughout the year in our unconventional resource plays. The average price we received for our production decreased from $52.81 per boe to $50.98 per boe, or 3% primarily due to lower natural gas prices. The $139.2 million increase in revenues comprised an increase of approximately $151.1 million attributable to increased production volumes of 2,803 mboe, partially offset by a decrease of $11.9 million due to a decrease in price of $1.83 per boe produced. The prices we receive for our products are generally tied to commodity index prices. We periodically enter into commodity derivative contracts in an attempt to offset some of the variability in prices (see the discussion of commodity derivative activities below).

Midstream operations. Revenue from the midstream operations segment (which, in 2012, consisted of both the Eureka Pipeline and TransTex Hunter operations) increased by $13.5 million, or 540%, for the year ended December 31, 2012 to $15.9 million from $2.5 million for the year ended December 31, 2011. The increase in revenues resulted from the acquisition of the TransTex Gas Services assets in April 2012, as well as increased volume of natural gas product gathered by our pipeline gathering system, as Eureka Pipeline gathered approximately 10.0 million mmbtu in 2012 compared with approximately 7.2 million mmbtu in 2011. TransTex Hunter added $6.8 million of revenue related primarily to treating natural gas at the wellhead for third-party producers in Texas and other states.

Oil field services. Drilling services revenue increased by 37%, or $3.5 million, for the year ended December 31, 2012 to $13.0 million from $9.4 million for the year ended December 31, 2011. Revenues from continuous operations in oilfield services comprised drilling services.

Other income. Other revenues, consisting primarily of gas regulated, retail gas billing revenues from the Appalachian region of the U.S. Upstream segment, increased by $372,000 for the year ended December 31, 2012.

Lease operating expense. Our lease operating expenses, or LOE, increased $25.0 million, or 95%, for the year ended December 31, 2012 to $51.4 million ($10.67 per boe) from $26.4 million ($13.10 per boe) for the year ended December 31, 2011. The increase in total LOE is attributable to increased volume produced, which caused an increase in cost of $29.9 million, reduced by lower cost per boe produced, which offset the effect of the increase in volume by $5.0 million. The decrease in overall LOE per boe cost is due to the impact of the lower per boe cost of the new production brought online during 2012 through our ongoing drilling program in our unconventional resource plays.

Severance taxes and marketing. Our severance taxes and marketing increased by $7.6 million, or 101%, for the year ended December 31, 2012 to $15.0 million from $7.5 million for the year ended December 31, 2011. The increase in production taxes and marketing was due to the increase in oil and gas sales as explained above.

Exploration and abandonments. We record exploration costs, geological and geophysical, and unproved property impairments and leasehold expiration as exploration and abandonment expense.We recorded $117.2 million of exploration and abandonment expense for the year ended December 31, 2012, compared to $2.6 million for the year ended December 31, 2011. During 2012, the Company's exploration and abandonment expense was primarily attributable to $43.8 million of leasehold abandonment expense, which included $33.6 million and $10.2 million associated with the Company's unproved properties in the Williston and Appalachian Basins, respectively, and $2.9 million of exploration costs. The Williston Basin impairment is primarily due to the large acreage position

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we initially acquired and results to date in the area, which led us to focus on other areas, thereby letting certain acreage expire in that region. Leasehold abandonment expense also includes impairment charges of $70.6 million related to unproved properties of $62.2 million, $7 million, and $1.4 million in the Company's Williston and Appalachian Basins and south Texas, respectively, primarily due to declines in gas prices and downward adjustments to the economically recoverable resource potential. The significant components of the Company's 2011 leasehold abandonment expense included unproved acreage abandonments of $802,000 and $306,000 in the Appalachian Basin and South Texas areas, respectively, and $1.5 million of exploration costs.

During the quarter ended March 31, 2013, the Company recognized an additional $4.7 million lease abandonment expense related to leases that expired on approximately 700 acres in the Williston Basin region that we planned to renew as of December 31, 2012, but failed to renew as a result of logistical difficulties.

Impairment of proved oil and gas properties.We review for impairment our long-lived assets to be held and used, including proved oil and gas properties accounted for under the successful efforts method of accounting. In 2012, we recognized proved property impairment charges of $4.1 million primarily related to $3.9 million in the Williston Basin. In 2011, the $21.8 million impairment charge related to certain proved oil and gas properties acquired as part of our acquisition of NGAS in 2011 due to a significant decline in natural gas prices at December 31, 2011, which was a 26% decrease compared to NYMEX natural gas index prices at the end of 2010. 

Depletion, depreciation and accretion. Our depletion, depreciation and accretion expense, or DD&A, increased $87.1 million, or 179%, to $135.8 million for the year ended December 31, 2012 from $48.8 million for the year ended December 31, 2011 due to increases in property, plant and equipment as a result of our capital expenditures program and acquisitions, and increased production in 2012. Our DD&A per boe increased by $3.97, or 16%, to $28.22 per boe for the year ended December 31, 2012, compared to $24.25 per boe for the year ended December 31, 2011. The increase in DD&A per boe was primarily attributable to production from newer wells coming online during the year in the Eagle Ford Shale, Marcellus Shale, and Williston Basin at a higher cost to drill and complete than wells completed in prior years.

General and administrative. Our general and administrative expenses, or G&A, increased $1.5 million, or 2%, to $64.4 million ($13.38 per boe) for the year ended December 31, 2012 from $62.9 million ($31.28 per boe) for the year ended December 31, 2011. G&A expenses increased overall during 2012 due to expansion activities of the Company. Non-cash stock compensation totaled approximately $15.7 million ($3.26 per boe) for the year ended December 31, 2012 and $25.1 million ($12.46 per boe) for the year ended December 31, 2011. The decrease in non-cash stock compensation was caused by the issuance of fewer stock options in total, and the stock options that were issued had longer vesting terms than the options issued during the prior year. Also included in G&A for 2012 are acquisition-related costs of $4.7 million ($0.99 per boe) for the 2012 period, which were for legal, consulting and other charges principally related to the Acquired Baytex Assets and the Virco Acquisition. In 2011, we had $8.9 million ($4.42 per boe) of acquisition-related costs, which were for legal, consulting and other charges principally related to the acquisitions of NGAS and NuLoch.

Interest expense, net. Our interest expense, net of interest income, increased by 333%, from $12 million to $51.8 million for the year ended December 31, 2012 compared to the year ended December 31, 2011. Our higher average debt level during 2012 accounted for $31.7 million of the increase, the remaining $8.1 million is the result of the amortization of financing costs related to the Senior Notes, the MHR Senior Revolving Credit Facility, Eureka Pipeline's outstanding term loan and Magnum Hunter's now paid-off term loan. Interest on projects lasting six months or greater is capitalized. In 2012, $4.4 million of interest was capitalized. We did not capitalize interest in 2011 or 2010. 

Commodity derivative activities. Realized gains and losses from our commodity derivative activity increased our earnings by $11.3 million and decreased our earnings by $2.1 million for the years ended December 31, 2012 and 2011, respectively. Realized gains and losses are derived from the relative movement of oil and gas prices on the products we sell in relation to the range of prices in our derivative contracts for the respective years. The unrealized gain on commodity derivatives was $1.9 million for 2012 and a loss of $4.2 million for 2011. As commodity prices increase, the fair value of the open portion of those positions decreases, and vice versa. As commodity prices decrease, the fair value of the open portion of those positions increases. We continue not to designate our derivative instruments as cash-flow hedges for 2012 and 2011.

At December 31, 2012, the Company had preferred stock embedded derivative liabilities resulting from certain conversion features, redemption options, and other features of our Series A Convertible Preferred Units of Eureka Hunter Holdings, LLC. See "Note 4 – Fair Value of Financial Instruments" and "Note 13 — Redeemable Preferred Stock", for more information. This contract resulted in an unrealized gain of $8.7 million in 2012. Also at December 31, 2012, the Company had an embedded derivative asset related to a convertible security, primarily due to the conversion feature of the promissory note received as partial consideration for the sale of Hunter Disposal, LLC. See "Note 4 – Fair value of Financial Instruments", "Note 7 – Discontinued Operations" and "Note 17 – Related Party Transactions", for additional information. An unrealized loss of $141,000 is recorded for this contract in 2012. Both contracts originated in 2012 and have resulted in no cash outlays as of December 31, 2012.

We record our open derivative instruments at fair value on our consolidated balance sheets as either current or long term assets or liabilities, depending on the timing of expected cash flows. We record all realized and unrealized gains and losses on our consolidated statements of operations under the caption entitled “Gain (loss) on derivative contracts, net”. Our realized gain during 2012 was

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$11.3 million compared with a realized loss of $2.1 million in 2011. Our unrealized gain in 2012 was $10.9 million compared with an unrealized loss in 2011 of $4.2 million.

Net income (loss) attributable to non-controlling interest. Net loss attributable to non-controlling interest was $4.0 million in 2012 versus net income of $249,000 in 2011. This represents 12.5% of the net income or loss incurred by our subsidiary, PRC Williston, LLC, and 40% of the net loss incurred by our subsidiary, Eureka Hunter Holdings, LLC. We record a non-controlling interest in the results of operations of PRC Williston, LLC because we are contractually obligated to make distributions to the holders of a non-controlling interest in this subsidiary whenever we make distributions to ourselves from this subsidiary.

Deferred tax benefit. The Company recorded a deferred tax benefit at the applicable statutory rates of $23.0 million during the year ended December 31, 2012, as a result of the operating loss incurred by Williston Hunter Canada, Inc. and Williston Hunter, Inc., during the period.The Company recorded a deferred tax benefit at the applicable statutory rates of $696,000 during the year ended December 31, 2011, as a result of the operating loss incurred by Williston Hunter Canada, Inc. and Williston Hunter, Inc., during the period. These entities recorded the deferred tax benefit because they are separate tax entities from Magnum Hunter Resources Corporation and its other subsidiaries. There are no deferred tax benefits recorded for Magnum Hunter Resources Corporation and its U.S. based subsidiaries for the year ended December 31, 2011 because the deferred tax benefits are fully reserved.

Loss from continuing operations. We incurred net losses from continuing operations of $139.4 million and $79.4 million in 2012 and 2011, respectively. Our 2012 revenues increased $157.3 million to $271 million compared to $113.7 million in 2011. However, this increase was more than offset by increases in operating expenses. Our 2012 operating loss increased $71.7 million, to $135 million, compared to $63.4 million in 2011. The increase in the loss is principally due to an increase in exploration and abandonment expense of $114.6 million, related to the expiration of leases we chose not to develop, increased depreciation, depletion and accretion costs of $87 million, related to additional capital expenditures of $643 million over 2011, and an increase in interest expense of $39.9 million related to increased borrowing, partially offset by a gain on derivative contracts of $22.2 million. In 2012, non-cash stock compensation expense decreased to $15.7 million from $25.1 million in 2011, and acquisition related expenses decreased to $4.7 million from $8.9 million in 2011.

Income from discontinued operations. On February 17, 2012, we closed the sale of Hunter Disposal, LLC, previously a wholly owned subsidiary. We have reclassified $230,000 and $3.0 million of net operating income (net of interest expense) of the divested subsidiary to discontinued operations for the year ended December 31, 2012 and 2011, respectively. We have also reclassified the gain on sale of $2.4 million to discontinued operations for the year ended December 31, 2012.

Dividends on preferred stock. Dividends on our Series C, Series D, and Series E Preferred Stock were $34.7 million in 2012 versus $14.0 million in 2011. The Series E Preferred Stock had a stated value of $94.4 million and none outstanding as of December 31, 2012 and 2011, respectively, and carries a cumulative dividend rate of 8.0% per annum. The Series D Preferred Stock had a stated value of $210.4 million and $71.9 million at December 31, 2012 and 2011, respectively, and carries a cumulative dividend rate of 8.0% per annum. The Series C Preferred Stock had a stated value of $100.0 million at December 31, 2012 and 2011, and carries a cumulative dividend rate of 10.25% per annum. The Series A Convertible Preferred Units of Eureka Hunter Holdings, LLC had a liquidation preference of $167.4 million and zero as of December 31, 2012 and 2011, respectively, and carry a cumulative dividend rate of 8.0% per annum.

Net loss attributable to common shareholders. Net loss attributable to common shareholders was $167.4 million in 2012 versus $90.7 million in 2011. Our net loss per common share, basic and diluted, was $1.07 per share in 2012 compared to $0.80 per share in 2011. Our weighted average shares outstanding increased by 42.6 million shares, or 38%, to approximately155.7 million shares, principally as a result of the shares issued for cash which allowed us to procure financing for the Acquired Baytex Assets. Our net loss per share from continuing operations was $1.09 per share for the year ended December 31, 2012, compared to a loss from continuing operations of $0.83 per share for the year ended December 31, 2011.

Years ended December 31, 2011 and 2010

Oil and gas production. Production increased by 324%, or 1,536 mboe, to 2,011 mboe for the year ended December 31, 2011 from 475 mboe for the year ended December 31, 2010. Production for 2011, on a boe basis, was 43% oil and ngls and 57% natural gas compared to 67% oil and ngls and 33% natural gas for 2010. The change in the percent of oil and gas produced was due to the acquisition of NGAS in the first half of 2011 and success in our Marcellus Shale development program. Our average daily production was 5,510 boepd during 2011 compared to 1,301 boepd for 2010 representing an overall increase of 324%, or 4,209 boepd. The increase in production in 2011 compared to 2010 is primarily attributable to the acquisitions of NuLoch and NGAS in the first half of 2011 as well as organic growth as a result of the Company’s successful ongoing drilling program.

U.S. Upstream segment. Production increased in the U.S. Upstream operating segment by 294%, or 1,397 mboe, for the year ended December 31, 2011 from 475 mboe for the year ended December 31, 2010. Production for 2011 on a boe basis was 41% oil and ngls and 59% natural gas compared to 67% oil and ngls and 33% natural gas for 2010. Our average daily production increased by 294%, or 3,828 boepd, to 5,129 boepd during 2011 compared to 1,301 boepd for 2010. This increase in production for the U.S. Upstream segment in 2011 compared to 2010 is primarily attributable to the acquisitions of NuLoch and NGAS as well as organic growth through the Company’s ongoing drilling programs.

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Canadian Upstream segment. The Canadian operating segment initiated production in 2011, as it was part of the NuLoch acquisition completed in the first half of 2011. This segment provided 139 mboe of production for the year ended December 31, 2011. Production from the Canadian segment comprised 76% oil and ngls and 24% natural gas on a boe basis.

Oil and gas sales. Oil and gas sales increased 283%, or $78.5 million, for the year ended December 31, 2011 to $106.2  million from $27.7 million for the year ended December 31, 2010. The increase in oil and gas sales principally resulted from increases in our oil and natural gas production as a result of acquisitions and new drilling completed throughout the year in the unconventional resource plays. The average price we received for our production decreased from $58.37 per boe to $52.81 per boe, or 9.5%. Of the $78.5 million increase in revenues, approximately $5.2  million was attributable to an increase in oil prices partially offset by a decrease in gas prices, and $73.3 million was attributable to the increase in production volumes of 1,536 mboe in 2011. The prices we receive for our products are generally tied to commodity index prices. We periodically enter into commodity derivative contracts in an attempt to offset some of the variability in prices (see the discussion of commodity derivative activities below).

Oilfield services revenue. Oilfield services revenue increased by 485%, or $5.9 million, for the year ended December 31, 2011 to $7.1 million from $1.2 million for the year ended December 31, 2010. Oilfield services revenues are comprised of drilling services from continuing operations.

Midstream operations. Revenue from the midstream operations segment (which, in 2011 and 2010, consisted solely of the Eureka Pipeline operations) increased by $331,000, or 204%, for the year ended December 31, 2011 to $494,000 from $163,000 for the year ended December 31, 2010. The increase in revenues resulted from the increased volume of natural gas products gathered by the pipeline system, as Eureka Pipeline gathered approximately 7.2 million mmbtu in 2011 compared to approximately 20,021 mmbtu in 2010.

Other income. Other revenues decreased by $418,000 for the year ended December 31, 2011.

Lease operating expense. Our lease operating expenses, or LOE, increased $15.7 million, or 147%, for the year ended December 31, 2011 to $26.3 million ($13.10 per boe) from $10.7 million ($22.51 per boe) for the year ended December 31, 2010. The increase in total LOE is attributable to increased volume produced, which accounted for an increase in cost of $34.6 million, reduced by lower cost per boe produced, which offset the volume effect by $18.9 million. The decrease in overall LOE per boe cost is due to the impact of the lower per boe cost of the new production brought online during 2011 through our ongoing drilling program in our unconventional resource plays.

Severance taxes and marketing. Our severance taxes and marketing increased by $5.1 million, or 214%, for the year ended December 31, 2010 to $7.5 million from $2.4 million for the year ended December 31, 2010. The increase in production taxes and marketing was due to the increase in oil and gas sales as explained above.

Exploration and abandonment expense. We record exploration costs, geological and geophysical, and unproved property impairments and leasehold expiration as exploration and abandonment expense. In 2011, we incurred impairment charges associated with our undeveloped acreage of $306,000 and $802,000 in our Eagle Ford Shale and Appalachian Basin regions, respectively, due to expiring acreage that we chose not to develop. The 2010 impairment was primarily due to a write-down of our investment in the Giddings Field. We also recorded $1.5 million of geological and geophysical exploration expense for the year ended December 31, 2011, compared to $942,000 for the year ended December 31, 2010. We experienced higher geological and geophysical costs in 2011 as a result of the acquisitions of NGAS and NuLoch.

Impairment of proved oil and gas properties.We review for impairment our long-lived assets to be held and used, including proved oil and gas properties accounted for under the successful efforts method of accounting. As a result of this review of the recoverability of the carrying value of our assets, we recorded an impairment of oil and gas properties of $21.8 million and $306,000 for 2011 and 2010, respectively. The 2011 impairment charge related to certain proved oil and gas properties acquired as part of our acquisition of NGAS in 2011 due to a significant decline in natural gas prices at December 31, 2011, which was a 26% decrease compared to NYMEX natural gas index prices at the end of 2010. 

Depletion, depreciation and accretion. Our depletion, depreciation and accretion expense, or DD&A, increased $40.0 million, or 457% to $48.8 million for the year ended December 31, 2011 from $8.8 million for the year ended December 31, 2010 due to increased production in 2011. Our DD&A per boe increased by $5.81, or 31.0%, to $24.25 per boe for the year ended December 31, 2011, compared to $18.44 per boe for the year ended December 31, 2010. The increase in DD&A per boe was primarily attributable to the higher cost to drill, complete, and equip our Eagle Ford Shale, Marcellus Shale and Bakken Shale wells, which are horizontally drilled wells and require more expensive completion techniques than traditional, vertically-drilled wells.

General and administrative. Our general and administrative expenses, or G&A, increased $38.1 million, or 154%, to $62.9  million ($31.28 per boe) for the year ended December 31, 2011 from $24.8 million ($52.17 per boe) for the year ended December 31, 2010. G&A expenses increased overall during 2011 due to expansion activities of the Company. Non-cash stock compensation totaled approximately $25.1 million ($12.46 per boe) for the year ended December 31, 2011 and $6.4 million ($13.32 per boe) for the year ended December 31, 2010. Also included in G&A for 2011 are acquisition-related costs of $8.9 million ($4.42 per boe) for the 2011 period, which were for legal, consulting, and other charges principally related to the acquisitions of NGAS and NuLoch. In 2010, we had $2.2 million ($4.69 per boe) of acquisition-related expenses related to the acquisition of Triad Energy. These costs were

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expensed due to accounting standards which require that acquisition costs must be expensed rather than capitalized as part of the cost of the asset being acquired for years beginning in 2010.

Interest expense, net. Our interest expense, net of interest income, increased $8.4 million, or 234%, to $12.0 million for the year ended December 31, 2011 from $3.5 million for the year ended December 31, 2010. Approximately $2.7 million of this increase is the result of a non-cash write off of the unamortized balance of deferred financing fees from the credit facility that was replaced by the MHR Senior Revolving Credit Facility in April 2011. Approximately $1.0 million of the increase is the result of amortization of financing costs related to the MHR Senior Revolving Credit Facility, Eureka Pipeline’s outstanding term loan and Magnum Hunter’s now paid-off term loan.The remaining $4.7 million increase is the result of our higher average debt level during 2011 and the increased amount of interest, all attributable to Magnum Hunter’s now paid-off term loan that we obtained in September 2011.

Commodity derivative activities. Realized gains and losses from our commodity derivative activity decreased our earnings by $2.1 million and increased our earnings by $3.9 million for the years ended December 31, 2011 and 2010, respectively. Realized gains and losses are derived from the relative movement of oil and gas prices on the products we sell in relation to the range of prices in our derivative contracts for the respective years. The unrealized loss on commodity derivatives was $4.2 million for 2011 and $3.1 million for 2010. As commodity prices increase, the fair value of the open portion of those positions decreases, and vice versa. As commodity prices decrease, the fair value of the open portion of those positions increases. Historically, we have not designated our derivative instruments as cash-flow hedges. We record our open derivative instruments at fair value on our consolidated balance sheets as either unrealized gains or losses on commodity derivatives. We record all realized and unrealized gains and losses on our consolidated statements of operations under the caption entitled “Gain (loss) on derivative contracts”. Our gain or loss from realized and unrealized derivative contracts was a loss of $6.3 million and a gain of $814,000 for the years ended December 31, 2011 and 2010, respectively.

Net income attributable to non-controlling interest. Net income attributable to non-controlling interest was $249,000 in 2011 versus net income of $129,000 in 2010. This represents 12.5% of the net income or loss incurred by our subsidiary, PRC Williston, LLC. We record a non-controlling interest in the results of operations of this subsidiary because we are contractually obligated to make distributions to the holders of a non-controlling interest in this subsidiary whenever we make distributions to ourselves from the subsidiary.

Deferred tax benefit. The Company recorded a deferred tax benefit at the applicable statutory rates of $696,000 during the year ended December 31, 2011, as a result of the operating loss incurred by Williston Hunter Canada, Inc. and Williston Hunter, Inc., during the period. These entities recorded the deferred tax benefit because they are separate tax entities from Magnum Hunter Resources Corporation and its other subsidiaries. There are no deferred tax benefits recorded for Magnum Hunter Resources Corporation and its U.S. based subsidiaries for the year ended December 31, 2011 because the deferred tax benefits are fully reserved.

Loss from continuing operations. We had a loss from continuing operations of $79.4 million in 2011 versus a loss of $22.7 million in 2010, an increase of $56.7 million in loss, or 250%. This was due to an increase in operating loss of $43.4 million, principally due to an increase in G&A expense and DD&A expense.

Income from discontinued operations. We reclassified $3.0 million of income from Hunter Disposal, LLC to discontinued operations during the year ended December 31, 2011. On October 29, 2010, we closed on a divestiture of our Cinco Terry property effective October 1, 2010. As a result of this divestiture, we recognized income from discontinued operations of $8.5 million in 2010, consisting of a gain on sale of $6.7 million and reclassification of $1.9 million of operating income less interest expense associated with the property to discontinued operations. We also reclassified $553,000 of income for the year ended December 31, 2010, from Hunter Disposal, LLC to discontinued operations as it was sold in February of 2012.

Dividends on preferred stock. Dividends on our Series C and Series D Preferred Stock were $14.0 million in 2011 versus $2.5 million in 2010. The Series D Preferred Stock had a stated value of $71.9 million and $0 at December 31, 2011 and 2010, respectively, and carries a cumulative dividend rate of 8.0% per annum. The Series C Preferred Stock had a stated value of $100.0 million and $70.2 million at December 31, 2011 and 2010, respectively, and carries a cumulative dividend rate of 10.25% per annum. We commenced the issuance of Series C Preferred Stock in December 2009 and sold the last remaining authorized shares in January 2011. We redeemed all outstanding Series B Preferred Stock in June 2010.

Net loss attributable to common shareholders. Net loss attributable to common shareholders was $90.7 million in 2011 versus $16.3 million in 2010. Our net loss per common share, basic and diluted, was $0.80 per share in 2011 compared to $0.25 per share in 2010. Our weighted average shares outstanding increased by 49.2 million shares, or 77%, to approximately 113.2 million shares, principally as a result of the shares issued to acquire NuLoch and NGAS. Our net loss per share from continuing operations was $0.83 per share for the year ended December 31, 2011, compared to a loss from continuing operations of $0.39 per share for the year ended December 31, 2010.

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Liquidity and Capital Resources

We generally rely on cash generated from operations, borrowings under our MHR Senior Revolving Credit Facility and, to the extent that credit and capital market conditions will allow, future public and private equity and debt offerings to satisfy our liquidity needs. Our ability to fund planned capital expenditures and to make acquisitions depends upon our future operating performance, availability of borrowings under our MHR Senior Revolving Credit Facility, and more broadly, the availability of equity and debt financing, which is affected by prevailing economic conditions in our industry and financial, business and other factors, some of which are beyond our control. We cannot predict whether additional liquidity from equity or debt financings beyond our MHR Senior Revolving Credit Facility will be available or available on terms acceptable to us, or at all, in the foreseeable future.

Our cash flow from operations is driven by commodity prices and production volumes and the effect of commodity derivatives. Prices for oil and natural gas are affected by national and international economic and political environments, national and global supply and demand for hydrocarbons, seasonal influences of weather and other factors beyond our control. Our working capital is significantly influenced by changes in commodity prices, and significant declines in prices will cause a decrease in our production volumes and exploration and development expenditures. Cash flows from operations are primarily used to fund exploration and development of our oil and gas properties.

We intend to fund 2013 capital expenditures, excluding any acquisitions, primarily out of cash on hand, internally-generated cash flows, liquidation of some or all of our 10 million shares of Penn Virginia stock at times when management determines prices are attractive, and as necessary, borrowings under our MHR Senior Revolving Credit Facility. We may also raise additional funds in the public or private debt and equity markets. As of December 31, 2012, we had $112.5 million available to borrow under our MHR Senior Revolving Credit Facility. At December 31, 2012, the Company was in compliance with covenants under this credit facility requiring a ratio of consolidated current assets to consolidated current liabilities as defined of not less than 1.0 to 1.0.

For the year ended December 31, 2012, our primary sources of cash were from financing activities and cash on hand at the beginning of the year. Approximately $596.9 million of cash was provided by Senior Note issuances, along with $546.0 million of borrowings under our revolving credit facility and other debt agreements, while we repaid $542.7 million outstanding under our revolving credit facility and other debt agreements, for the year ended December 31, 2012. During such year, we funded our acquisitions and drilling program, repaid debt under our MHR Senior Revolving Credit Facility and paid deferred financing costs related to such facility using net proceeds of $149.7 million from the issuance of Series A Preferred Units of Eureka Holdings; net proceeds of $148.2 million from our issuance of common stock; net proceeds of $122.4 million from our issuance of Series D Preferred Stock; net proceeds of $22.2 million from our issuance of Depositary Shares evidencing our Series E Preferred Stock; $57.6 million of cash on hand; and $2.9 million of proceeds from the sale of assets.

For the year ended December 31, 2011, our primary sources of cash were from financing activities, proceeds from asset sales and cash on hand at the beginning of the year. Approximately $116.3 million of cash from sales of common and preferred stock and the proceeds from exercises of warrants, along with $493.9 million of borrowings under our revolving credit facility, $8.7 million of proceeds from sale of assets, and $14.9 million of cash on hand, were used to fund our acquisitions and drilling program, repay debt under our revolving credit facility, and pay deferred financing costs related to our credit facility.

For the year ended December 31, 2010, our primary sources of cash were from financing activities, proceeds from asset sales, and cash on hand at the beginning of the year. Approximately $117.6 million of cash from sales of common and preferred stock and the proceeds from exercises of warrants, along with $101.6 million of borrowings under our revolving credit facility, $21.2 million of proceeds from sale of assets, and $2.3 million of cash on hand, were used to fund our acquisitions and drilling program, repay debt under our revolving credit facility, redeem our Series B Preferred Stock, and pay deferred financing costs related to our credit facility.

The following table summarizes our sources and uses of cash for the periods noted:

	Years Ended December 31,
	2012			2011			2010
	(In thousands)
Cash flows provided by (used in) operating activities	$	58,011		$	33,838		$	(1,167	)
Cash flows used in investing activities	(1,009,207		)	(361,715		)	(118,281		)
Cash flows provided by financing activities	996,442			342,193			117,720
Effect of foreign currency translation	(2,474		)	(19		)	—
Net increase (decrease) in cash and cash equivalents	$	42,772		$	14,297		$	(1,728	)

We define liquidity as funds available under our MHR Senior Revolving Credit Facility plus year-end cash and cash equivalents. At December 31, 2012, we had $225.0 million in long-term debt outstanding under our MHR Senior Revolving Credit Facility, compared to $142.0 million in long-term debt outstanding under this facility at December 31, 2011.

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The following table summarizes our liquidity position at December 31, 2012 compared to December 31, 2011:

	At December 31,
	2012						2011
	(In thousands)
	Magnum			Eureka			Magnum			Eureka
	Hunter			Hunter			Hunter			Hunter
Borrowing base under MHR Senior Revolving Credit Facility	$	337,500		$	—		$	200,000		$	—
Borrowing base under Eureka Pipeline second lien term loan	—			50,000			—			50,000
Cash and cash equivalents	21,348			36,275			13,131			1,720
Borrowings under MHR Senior Revolving Credit Facility	(225,000		)	—			(142,000		)	—
Borrowings under Eureka Pipeline second lien term loan	—			(50,000		)	—			(31,000		)
Liquidity	$	133,848		$	36,275		$	71,131		$	20,720

Factors that will affect our liquidity in 2013 include proceeds from the Eagle Ford Properties Sale, proceeds from the 10 million shares of Penn Virginia common stock, with a market value of $42.3 million on June 1, 2013, that we intend to monetize, and expected increases in operating cash flows on our remaining assets as a result of the successful results of our 2012 drilling program and acquisitions. We also expect to have increased salary and other administrative costs associated with the increased number of employees resulting from our acquisitions, partially offset by a decrease in costs associated with the operations of Eagle Ford Hunter, which was sold in April 2013. On May 1, 2013, the Company’s borrowing base under the MHR Senior Revolving Credit Facility was $265 million. With respect to the effect of our late SEC filings on liquidity, see "Effect of Late SEC Filings on Liquidity and Capital Resources."

We intend to fund 2013 capital expenditures, excluding any acquisitions, primarily out of cash on hand, internally-generated cash flows, liquidation of some or all of our 10 million shares of Penn Virginia common stock at times when management determines prices are attractive, and as necessary, borrowings under our MHR Senior Revolving Credit Facility. We may also raise additional funds in the public or private debt and equity markets. As of December 31, 2012, we had $112.5 million available to borrow under our MHR Senior Revolving Credit Facility. At December 31, 2012, the Company was in compliance with covenants under this credit facility requiring a ratio of consolidated current assets to consolidated current liabilities (as defined) of not less than 1.0 to 1.0.

Operating Activities

Net cash provided by operating activities for the years ended December 31, 2012 and 2011 was $58 million and $33.8 million, respectively. Net cash used in operating activities in 2010 was $1.2 million. The increases in net cash provided by operating activities in both 2012 and 2011 were primarily due to increases in oil and gas sales in each year and realized derivative gains in 2012. In 2012, cash flow provided by operating activities included net income of $2.6 million from discontinued operations, which included the gain of $2.2 million. These discontinued operations will not have a material impact on future cash flows from operating activities.

Investing Activities

Net cash used in investing activities during 2012 was $1.0 billion, as compared to net cash used in investing activities of $361.7 million and $118.3 million during 2011 and 2010, respectively. The increase in net cash flow used in investing activities during 2012, as compared to 2011, is primarily due to (i) a $366.3 million increase in cash paid for acquisition of assets (primarily attributable to the Acquired Baytex Assets and Virco Acquisition), (ii) a $276.7 million increase in additions to oil and gas properties associated with the Company's capital programs, and (iii) the $4.5 million decrease in proceeds received from the sale of assets. During the year ended December 31, 2012, the Company's investing activities were funded by net cash provided by operating activities, cash on hand, borrowings under long-term debt, and issuances of preferred shares.

Capital expenditures of $291.9 million in 2011 were comprised of (i) $267.5 million for capital expenditures under our 2011 capital expenditures budget, (ii) $78.5 million for acquisitions of assets (primarily related to the NGAS acquisition), and (iii) proceeds from the sale of assets of $8.7 million.

In 2010, $59.5 million of funds from investing activities were used to acquire the Triad Energy assets, and $21.2 million of net proceeds were provided from the sale of our interests in the Cinco Terry property.

Financing Activities

Net cash provided by financing activities was $996.4 million, $342.2 million, and $117.7 million during 2012, 2011, and 2010 respectively. During 2012, the significant components of financing activities included (i) $596.9 million of in net proceeds from the issuance of our Senior Notes, (ii) $546.0 million in net proceeds on borrowings on debt, and (iii) the issuance of 7,590,000 shares of the Series A Preferred Units of Eureka Hunter Holdings, LLC for net proceeds of $149.7 million, 35,000,000 shares of common stock for net proceeds of $148.2 million, 2,771,263 shares of our Series D Preferred Stock for net proceeds of $122.4 million, and

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1,000 shares of our Series E Preferred Stock for net proceeds of $22.2 million, and (iv) $2.3 from the exercises of stock options and warrants. These items were partially offset by cash used in financing activities of $26.8 million to pay dividends, $20.3 million in deferred financing costs, and $1.8 million to settle a contingency related to the Virco Acquisition, after which 70 shares of our Series E Preferred Stock placed in escrow were released and included in treasury shares.

During 2011 the significant components of financing activities included $493.9 million borrowings under our credit facilities and other debt agreements, and proceeds of $94.8 million from the sale of preferred shares, $13.9 million from the sale of common stock, and $7.6 million from the exercise of common stock options and warrants. Also during 2011, we repaid $242.5 million of amounts outstanding under our revolving credit facility, paid dividends of $14.0 million and used cash of $11.6 million for payment of deferred financing costs.

During 2010 the significant components of financing activities included $101.6 million borrowings under our credit facilities and other debt agreements, and proceeds of $63.4 million from the sale of preferred shares, $38.7 million from the sale of common stock, and $16.2 million from the exercise of common stock options and warrants. Also during 2010, we repaid $84.9 million of amounts outstanding under our revolving credit facility, used $11.3 million to purchase treasury stock, paid dividends of $2.5 million and used cash of $2.9 million for payment of deferred financing costs.

As of May 1, 2013, we had $600 million aggregate principal amount of our Senior Notes outstanding. In connection with the May and December 2012 offerings of the Senior Notes, we entered into registration rights agreements pursuant to which we agreed to complete, by May 16, 2013, a registered exchange offer of the Senior Notes for the same principal amount of a new issue of Senior Notes with substantially identical terms, except the new Senior Notes will be registered and generally freely transferable under the Securities Act. In addition, we agreed to file, under certain circumstances, a shelf registration statement to cover re-sales of the new Senior Notes. We have been required to pay penalty interest on our Senior Notes since May 16, 2013 as a result of our failure to complete the exchange offer for our Senior Notes, and we may encounter additional difficulties in completing such exchange offer for our Senior Notes due to our loss of eligibility to incorporate information by reference in our SEC registration statements.

We believe that cash flows from operations and borrowings under our MHR Senior Revolving Credit Facility and other debt agreements will finance substantially all of our capital needs through 2013. We may also use our MHR Senior Revolving Credit Facility for possible acquisitions and temporary working capital needs. Further, we may decide to access the public or private equity or debt markets for potential acquisitions, working capital or other liquidity needs, if such financing is available on acceptable terms.

Equity and Debt Financings

We raised substantial cash in the total amount of $1.1 billion in net proceeds, after offering discounts, commissions and placement fees, but before other offering expenses, through equity and debt transactions from January 1, 2012 through February 28, 2013. Those transactions included:

• $596.9 million in net proceeds from the private offerings of our Senior Notes;

• $546 million in proceeds from debt borrowings, partially offset by repayments of $542 million;

• $148.2 million in net proceeds from a public offering of our common stock, at a public offering price of $4.50 per share;

• $132.1 million in net proceeds from issuances of our Series D Preferred Stock, at an average gross sales price of $48.60 per share;

• $22.8 million in net proceeds from issuances of Depositary Shares representing our Series E Preferred Stock, at an average gross sales price of $24.98 per Depositary Share;

• $169.5 million in net proceeds from issuances of Series A Preferred Units of Eureka Holdings, and

• $2.3 million in net proceeds from the exercise of common stock warrants and options.

We plan to continue raising both preferred and common equity in the future depending on our working capital needs, capital expenditure program, acquisition activities, the condition of the capital markets and our ability to access the capital markets given the restrictions on our capital raising activities resulting from our late SEC filings. See "Effect of Late SEC Filings on Liquidity and Capital Resources."

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2013 Capital Expenditures Budget

The following table sets forth our capital expenditures budget for 2013. We intend to fund 2013 capital expenditures, excluding any acquisitions, primarily out of available cash, internally-generated cash flows, proceeds from asset sales, including the Eagle Ford Properties Sale, and, as necessary, borrowings under our revolving credit facility and public or private issuances of equity or debt securities.

	Year Ending December 31, 2013
	(in millions)
Upstream Operations
Appalachian Basin drilling	$	150
Williston Basin drilling	$	150
Midstream Operations
Eureka Pipeline (1)	100
Total capital expenditures	$	400
(1)Expected to be financed through equity and debt that are non-recourse to Magnum Hunter, and Company capital contributions

Our capital expenditures budget for 2013 is subject to change depending upon a number of factors, including economic and industry conditions at the time of drilling, prevailing and anticipated prices for oil and gas, the results of our development and exploration efforts, the availability of sufficient capital resources for drilling prospects, our financial results, the availability of leases on reasonable terms, our ability to obtain permits for drilling locations and our ability to obtain commitments from third-party producers for gas treating and gathering services.

Credit Facilities

MHR Senior Revolving Credit Facility

On April 13, 2011, the Company entered into a Second Amended and Restated Credit Agreement, referred to, as amended, as the MHR Senior Revolving Credit Facility, by and among the Company, Bank of Montreal, as Administrative Agent, and the lenders party thereto.

The MHR Senior Revolving Credit Facility provides for an asset‑based, senior secured revolving credit facility maturing on April 13, 2016. The MHR Senior Revolving Credit Facility is governed by a semi-annual borrowing base redetermination derived from the Company’s proved crude oil and natural gas reserves, and based on such redeterminations, the borrowing base may be decreased or may be increased up to a maximum commitment level of $750 million. Currently, the next scheduled redetermination of the borrowing base is in November 2013.

As of May 1, 2013, the aggregate borrowing base under this facility was $265 million. The borrowing base is subject to certain automatic reductions upon the issuance of additional Senior Notes and in certain other circumstances.

The facility may be used for loans and, subject to a $10 million sublimit, letters of credit. The facility provides for a commitment fee of 0.5% based on the unused portion of the borrowing base under the facility.

Borrowings under the facility will, at the Company’s election, bear interest at either: (i) an alternate base rate, referred to as alternate base rate, "ABR," equal to the higher of (A) the Prime Rate, (B) the Federal Funds Effective Rate plus 0.5% per annum and (C) the London Interbank Offered Rate, "LIBOR," for a one month interest period on such day plus 1.0%; or (ii) the adjusted LIBOR, which is the rate stated on Reuters British Bankers Association London Interbank Offered Rate, "BBA LIBOR," market for one, two, three, six or twelve months, as adjusted for statutory reserve requirements for Eurocurrency liabilities, plus, in each of the cases described in clauses (i) and (ii) above, an applicable margin ranging from 1.25% to 2.75% for ABR loans and from 2.25% to 3.75% for adjusted LIBOR loans.

Upon any payment default, the interest rate then in effect shall be increased on such overdue amount by an additional 2% per annum for the period that the default exists plus the rate applicable to ABR loans.

The MHR Senior Revolving Credit Facility contains negative covenants that, among other things, restrict the ability of the Company to, with certain exceptions: (1) incur indebtedness; (2) grant liens; (3) make certain restricted payments; (4) change the nature of its business; (5) dispose of its assets; (6) enter into mergers, consolidations or similar transactions; (7) make investments, loans or advances; (8) pay cash dividends, unless certain conditions are met, and subject to a “basket” of $45 million per year available for payment of dividends on preferred stock; and (9) enter into transactions with affiliates.

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The facility also requires the Company to satisfy certain financial covenants, including maintaining (1) a ratio of consolidated current assets to consolidated current liabilities (as defined) of not less than 1.0 to 1.0; (2) a ratio of earnings before interest, taxes, depreciation, depletion, amortization and exploration expenses, or "EBITDAX", to interest expense of not less than 2.5 to 1.0; and (3) a ratio of total debt to EBITDAX of not more than (i) 4.75 to 1.0 for the fiscal quarter ended December 31, 2012, (ii) 4.50 to 1.00 for the fiscal quarter ended March 31, 2013, (iii) 4.25 to 1.0 for the fiscal quarter ending June 30, 2013 and (iv) 4.25 to 1.0 for the fiscal quarter ending September 30, 2013 and for each fiscal quarter ending thereafter, unless, in the case of this clause (iv) only, a “material asset sale” shall have occurred during any such fiscal quarter in which case the ratio of total debt to EBITDAX shall not exceed 4.0 to 1.0 for such fiscal quarter. A “material asset sale” is any asset sale resulting in the receipt of net cash proceeds in excess of $15 million, other than asset sales made in the ordinary course of the Company’s and its restricted subsidiaries’ partnership drilling programs. The Company is also limited to certain maximum notional amounts in respect of commodity hedging agreements pursuant to the terms of the facility.

The obligations of the Company under the facility may be accelerated upon the occurrence of an Event of Default (as such term is defined in the facility). Events of Default include customary events for a financing agreement of this type, including, without limitation, payment defaults, defaults in the performance of affirmative or negative covenants, the inaccuracy of representations or warranties, bankruptcy or related defaults, defaults relating to judgments and the occurrence of a change in control of the Company.

Subject to certain permitted liens, the Company’s obligations under the MHR Senior Revolving Credit Facility have been secured by the grant of a first priority lien on no less than 80% of the value of the proved oil and gas properties of the Company and its restricted subsidiaries.

In connection with the facility, the Company and its restricted subsidiaries also entered into certain customary ancillary agreements and arrangements, which, among other things, provide that the indebtedness, obligations and liabilities of the Company arising under or in connection with the facility are unconditionally guaranteed by such subsidiaries.

Eureka Pipeline Credit Facilities

On August 16, 2011, Eureka Pipeline, a wholly‑owned subsidiary of Eureka Holdings, a majority‑owned subsidiary of the Company, entered into (i) a First Lien Credit Agreement, referred to as the Eureka Pipeline Revolver or the revolver, by and among Eureka Pipeline, the lenders party thereto from time to time, and SunTrust Bank, as administrative agent, and (ii) a Second Lien Term Loan Agreement, referred to as the Eureka Pipeline Term Loan or the term loan, by and among Eureka Pipeline, PennantPark Investment Corporation, or PennantPark, and the other lenders party thereto from time to time, and U.S. Bank National Association, as collateral agent (the Eureka Pipeline Revolver and the Eureka Pipeline Term Loan are collectively referred to as the Eureka Pipeline Credit Facilities).

The Eureka Pipeline Revolver provides for a revolving credit facility in an aggregate principal amount of up to $100 million (with an initial committed amount of $25 million), secured by a first lien on substantially all of the assets of Eureka Pipeline. The Eureka Pipeline Term Loan provides for a $50 million term loan, secured by a second lien on substantially all of the assets of Eureka Pipeline. The entire $50 million of the term loan must be drawn before any portion of the revolver is drawn. The revolver has a maturity date of August 16, 2016, and the term loan has a maturity date of August 16, 2018.

As of May 1, 2013, Eureka Pipeline had drawn the entire $50 million of the term loan, but was not yet eligible to draw any portion of the revolver. Both the revolver and the term loan are non-recourse to Magnum Hunter.

The terms of the Eureka Pipeline Revolver provide that the revolver may be used for (i) revolving loans, (ii) swing-line loans in an aggregate amount of up to $5 million at any one time outstanding or (iii) letters of credit in an aggregate amount of up to $5 million at any one time outstanding. The revolver provides for a commitment fee of 0.5% per annum based on the unused portion of the commitment under the revolver.

Borrowings under the revolver will, at Eureka Pipeline’s election, bear interest at:

• a base rate equal to the highest of (A) the prime lending rate announced from time to time by the Administrative Agent, (B) the then-effective Federal Funds Rate plus 0.5% per annum, or (C) the Adjusted LIBOR (as defined in the Eureka Pipeline Revolver) for a one-month interest period on such day plus 1.0% per annum, plus an applicable margin ranging from 1.25% to 2.25%; or

• the Adjusted LIBOR, plus an applicable margin ranging from 2.25% to 3.25%.

Borrowings under the term loan will bear interest at (a) prior to June 29, 2012, (i) 9.750% per annum in cash, plus (ii) 2.75% (increasing to 3.75% on and at all times when Eureka Pipeline and its subsidiaries incur indebtedness (other than the term loan) in excess of $1 million) which may be paid, at the sole option of Eureka Pipeline, in cash or in shares of restricted common stock of the Company and (b) on or after June 29, 2012, 12.50% per annum in cash (increasing to 13.50% on and at all times when Eureka Pipeline and its subsidiaries incur indebtedness (other than the term loan) in excess of $1 million).

If an event of default occurs under either the revolver or the term loan, the applicable lenders may increase the interest rate then in effect by an additional 2.0% per annum for the period that the default exists under the revolver or term loan, respectively.

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The Eureka Pipeline Credit Facilities contain negative covenants that, among other things, restrict the ability of Eureka Pipeline to, with certain exceptions: (1) incur indebtedness; (2) grant liens; (3) dispose of all or substantially all of its assets or enter into mergers, consolidations, or similar transactions; (4) change the nature of its business; (5) make investments, loans, or advances or guarantee obligations; (6) pay cash dividends or make certain other payments; (7) enter into transactions with affiliates; (8) enter into sale and leaseback transactions; (9) enter into hedging transactions; (10) amend its organizational documents or material agreements; or (11) make certain undisclosed capital expenditures.

The Eureka Pipeline Credit Facilities also require Eureka Pipeline to satisfy certain financial covenants, including maintaining:

• a consolidated total debt to capitalization ratio of not more than 60%;

• a consolidated earnings before interest, taxes, depreciation, depletion, amortization , "EBITDA," to consolidated interest expense ratio ranging from:

(i) for the term loan, not less than (A) 0.85 to 1.00 for the fiscal quarter ended December 31, 2012 (unless Eureka Pipeline has borrowed under the revolving facility before December 31, 2012, in which case, 1.00 to 1.00), (B) 1.25 to 1.00, for the fiscal quarter ended March 31, 2013, (C) 1.50 to 1.00, for the fiscal quarter ending June 30, 2013, (D) 1.75 to 1.00, for the fiscal quarter ending September 30, 2013, (E) 2.25 to 1.00, for the fiscal quarters ending December 31, 2013 and March 31, 2014, (E) 2.50 to 1.00, for the fiscal quarters ending June 30, 2014 and September 30, 2014, and (F) 2.75 to 1.0 for the fiscal quarter ending December 31, 2014 and each fiscal quarter ending thereafter, and

(ii) in the event any portion of the revolver has been drawn, for the revolver, not less than (A) 1.25 to 1.00 for the fiscal quarter ending December 31, 2012, (B) 1.50 to 1.00, for the fiscal quarter ended March 31, 2013, (C) 1.75 to 1.00, for the fiscal quarter ending June 30, 2013, (D) 2.00 to 1.00, for the fiscal quarter ending September 30, 2013, (E) 2.50 to 1.00, for the fiscal quarters ending December 31, 2013 and March 31, 2014, (E) 2.75 to 1.00, for the fiscal quarters ending June 30, 2014 and September 30, 2014, and (F) 3.00 to 1.0 for the fiscal quarter ending December 31, 2014 and each fiscal quarter ending thereafter;

• a consolidated total debt to consolidated EBITDA ratio ranging from:

(i) for the term loan, not greater than (A) 8.50 to 1.0 for the fiscal quarter ended December 31, 2012 (unless Eureka Pipeline has borrowed under the revolving facility before December 31, 2012, in which case, 6.50 to 1.00), (B) 6.00 to 1.0 for the fiscal quarters ended March 31, 2013 and June 30, 2013, (C) 5.00 to 1.0 for the fiscal quarter ending September 30, 2013, (D) 4.50 to 1.0 for the fiscal quarters ending December 31, 2013, March 31, 2014, June 30, 2014, and September 30, 2014, and (E) 4.25 to 1.0 for the fiscal quarter ending December 31, 2014 and each fiscal quarter ending thereafter, and

(ii) in the event any portion of the revolver has been drawn, for the revolver, not greater than (A) 6.25 to 1.0 for the fiscal quarter ended December 31, 2012, (B) 5.75 to 1.0 for the fiscal quarters ended March 31, 2013 and June 30, 2013, (C) 4.75 to 1.0 for the fiscal quarter ending September 30, 2013, (D) 4.50 to 1.0 for the fiscal quarters ending December 31, 2013 and March 31, 2014, and (E) 4.00 to 1.0 for the fiscal quarter ending June 30, 2014 and each fiscal quarter ending thereafter; and

• a ratio of consolidated debt under the revolver to consolidated EBITDA of (i) for the term loan, not greater than 3.5 to 1.0, and (ii) for the revolver, if any portion of the revolver has been drawn, not greater than 3.25 to 1.0 for each fiscal quarter.

The obligations of Eureka Pipeline under each of the revolver and the term loan may be accelerated upon the occurrence of an event of default (as such term is defined in the facility) under such facility. Events of default include customary events for these types of financings, including, among others, payment defaults, defaults in the performance of affirmative or negative covenants, the inaccuracy of representations or warranties, defaults under the term loan (with respect to the revolver) or the revolver (with respect to the term loan), defaults relating to judgments, material defaults under certain material contracts of Eureka Pipeline, and defaults by the Company which cause the acceleration of the Company’s debt under the MHR Senior Revolving Credit Facility.

In connection with the Eureka Pipeline Credit Facilities, (i) Eureka Pipeline and its subsidiaries have entered into customary ancillary agreements and arrangements, which provide that the obligations of Eureka Pipeline under the Eureka Pipeline Credit Facilities are secured by substantially all of the assets of Eureka Pipeline and its subsidiaries and (ii) Eureka Holdings, the sole parent of Eureka Pipeline and a majority-owned subsidiary of the Company, entered into customary ancillary agreements and arrangements, which granted the lenders under the facilities a non-recourse security interest in Eureka Holdings’ equity interest in Eureka Pipeline.

Senior Notes

On May 16, 2012, Magnum Hunter issued $450 million in aggregate principal amount of its 9.750% Senior Notes due 2020, referred to as our Senior Notes. The Senior Notes were issued pursuant to an indenture entered into on May 16, 2012 as supplemented, among the Company, the subsidiary guarantors party thereto, Wilmington Trust, National Association, as the trustee, and Citibank, N.A., as the paying agent, registrar, and authenticating agent. On December 18, 2012, Magnum Hunter issued an additional $150 million in aggregate principal amount of Senior Notes pursuant to a supplement to the indenture. The Senior Notes issued in May 2012 and the Senior Notes issued in December 2012 have identical terms and are treated as a single class of securities under the indenture. We did not register the issuances of the Senior Notes under the Securities Act in reliance on certain exemptions from the registration requirements. As of May 1, 2013, we continue to have $600 million aggregate principal amount of Senior Notes outstanding.

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The Senior Notes mature on May 15, 2020. Interest on the Senior Notes accrues at an annual rate of 9.750% (calculated using a 360-day year) and is payable semi-annually in arrears on May 15 and November 15. The MHR Senior Revolving Credit Facility prohibits the prepayment of the Senior Notes.

The Senior Notes are Magnum Hunter’s general unsecured senior obligations. Accordingly, they rank:

• equal in right of payment to all of our existing and future senior unsecured indebtedness;

• effectively subordinated to all our existing and future senior secured indebtedness incurred from time to time, such as our MHR Senior Revolving Credit Facility, to the extent of the value of our assets securing such indebtedness;

• structurally subordinated to all existing and future indebtedness and other liabilities, including trade payables, of any non-guarantor subsidiaries (such as Eureka Holdings, Eureka Pipeline, TransTex Hunter and our foreign subsidiaries), other than indebtedness and other liabilities owed to us; and

• senior in right of payment to all of our future subordinated indebtedness.

The Senior Notes are jointly and severally guaranteed by all of our existing and future direct or indirect domestic subsidiaries that guarantee obligations under our MHR Senior Revolving Credit Facility. In the future, the guarantees may be released or terminated under certain circumstances. Each guarantee ranks:

• equal in right of payment to all existing and future senior unsecured indebtedness of the guarantor;

• effectively subordinated to all of the guarantors’ existing and future senior secured indebtedness incurred from time to time (including guarantees of the MHR Senior Revolving Credit Facility), to the extent of the value of the assets securing such indebtedness;

• structurally subordinated to all existing and future indebtedness and other liabilities, including trade payables, of our non-guarantor subsidiaries (such as Eureka Holdings, Eureka Pipeline, TransTex Hunter and our foreign subsidiaries), other than indebtedness and other liabilities owed to us; and

• senior in right of payment to any future subordinated indebtedness of the guarantor.

At any time prior to May 15, 2015, we may, from time to time, redeem up to 35% of the aggregate principal amount of the Senior Notes with the net cash proceeds of certain equity offerings at the redemption prices specified in the indenture if at least 65% of the aggregate principal amount of the Senior Notes issued under the indenture (excluding notes held by us) remains outstanding immediately after such redemption and the redemption occurs within 180 days of the closing date of such equity offering. At any time prior to May 15, 2016, we may redeem the notes, in whole or in part, at a “make-whole” redemption price specified in the indenture. On and after May 15, 2016 we may redeem the notes, in whole or in part, at the redemption prices specified in the indenture.

If we experience certain change of control events, each holder of Senior Notes may require us to repurchase all or a portion of the Senior Notes for cash at a price equal to 101% of the aggregate principal amount of such notes, plus any accrued and unpaid interest to, but not including, the date of repurchase.

The indenture governing the Senior Notes contains covenants that, among other things, limit our and our restricted subsidiaries’ ability to:

• incur or guarantee additional indebtedness or issue certain preferred stock;

• pay dividends on capital stock or redeem, repurchase or retire our capital stock or subordinated indebtedness or make certain other restricted payments;

• transfer or sell assets;

• make loans and other investments;

• create or permit to exist certain liens;

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

• consolidate, merge or transfer all or substantially all of our assets;

• engage in transactions with affiliates; and

• create unrestricted subsidiaries.

These covenants are subject to certain exceptions and qualifications as described in the indenture.

The indebtedness of the Company under the indenture may (or, in certain cases, will automatically) be accelerated upon the occurrence of an Event of Default (as such term is defined in the indenture). Events of Default include customary events for a financing agreement of this type, including, without limitation, payment defaults, defaults in the performance of affirmative or negative covenants,

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bankruptcy or related events, certain cross-defaults relating to other indebtedness for borrowed money and defaults relating to judgments.

We entered into registration rights agreements pursuant to which we agreed to file an exchange offer registration statement under the Securities Act to allow the holders of the Senior Notes to exchange the Senior Notes issued in the May and December 2012 offerings for the same principal amount of a new issue of Senior Notes with substantially identical terms, except the new Senior Notes will generally be freely transferable under the Securities Act. In addition, we agreed to file, under certain circumstances, a shelf registration statement to cover re-sales of the Senior Notes.

As a result of the delay in the filing of this annual report on Form 10-K and our quarterly report on Form 10-Q for the quarter ended March 31, 2013, we failed to complete the registered exchange offer or file the shelf registration statement within the time periods specified in our registration rights agreement. Accordingly, as required by the terms of the registration rights agreement, effective May 16, 2013, we commenced payment of additional penalty interest on the Senior Notes, and will be required to continue to pay such additional interest until the exchange offer has been completed or the shelf registration statement has been filed and declared effective by the SEC.

Effect of Late SEC Filings on Liquidity and Capital Resources

We are no longer able to access the capital markets using short-form registration statements or “at-the-market” offerings as a result of this annual report not having been filed within, and our Form 10-Q for the quarter ended March 31, 2013 to be filed after, the time frames permitted by the SEC. See “Risk Factors - Our failure to timely file certain periodic reports with the SEC limits our access to the public markets to raise debt or equity capital.” Our ability to access the MHR Senior Revolving Credit Facility, and for Eureka Pipeline to access the Eureka Pipeline Revolver and the Eureka Pipeline Term Loan, could be curtailed or eliminated if (i) we fail to file such Form 10-Q by the lenders' extended deadline of July 12, 2013 or within any extended time period our lenders may in the future provide us or (ii) an uncured cross-default under such facilities results from any uncured “event of default” under the indenture relating to our Senior Notes stemming from our late SEC filings. See “Risk Factors - Our existing indenture defaults restrict our ability to utilize certain exceptions to the restrictive covenants contained therein and, under certain circumstances, may result in the acceleration of the Senior Notes issued under our indenture and the outstanding debt under our credit facilities, which would have a material adverse effect on our business, financial condition and liquidity.” These adverse impacts from our late SEC filings will be reduced, to some extent, by the net proceeds we received from the Eagle Ford Properties Sale and expected net proceeds in 2013 and 2014 from sales of non-core properties.

Eureka Holdings Equity Commitment Facility

Pursuant to the Series A Convertible Preferred Unit Purchase Agreement among Magnum Hunter, Eureka Holdings and Ridgeline, referred to as the Unit Purchase Agreement, Ridgeline committed, subject to certain conditions, to purchase up to $200 million of preferred units of Eureka Holdings. As of May 1, 2013, Eureka Holdings had sold preferred units to Ridgeline for an aggregate purchase price of $171.8 million.

Eureka Holdings’ ability to obtain additional funds from Ridgeline is subject to the satisfaction of certain conditions to Ridgeline’s obligation to purchase preferred units as set forth in the Unit Purchase Agreement. These conditions include, among others, that (i) the proceeds be used for certain approved capital expenditures, midstream growth projects and/or acquisitions (or for any other purposes agreed to by Ridgeline) and (ii) no defaults or material adverse events have occurred.

The Amended and Restated Limited Liability Company Agreement of Eureka Holdings, referred to as the EH Operating Agreement, contains certain covenants that, among other things, restrict the ability of Eureka Holdings and its subsidiaries, including Eureka Pipeline and TransTex Hunter, to, with certain exceptions:

• incur funded indebtedness, whether direct or contingent;

• issue additional equity interests;

• pay distributions to its owners, or repurchase or redeem any of its equity securities;

• make any material acquisitions, dispositions or divestitures; or

• enter into a sale, merger, consolidation or other change of control transaction.

Under the EH Operating Agreement, the holders of preferred units of Eureka Holdings are entitled to receive an annual distribution of 8%, payable quarterly. Through and including the quarter ended March 31, 2013, the board of directors of Eureka Holdings could elect to pay up to 75% of any such distribution in kind (i.e., in additional preferred units), in lieu of cash. For the quarter ending June 30, 2013 through and including the quarter ending March 31, 2014, the board of directors of Eureka Holdings may elect to pay up to 50% of any such distribution in kind. Thereafter, all distributions to Ridgeline relating to the preferred units will be paid solely in cash.

In addition to the required quarterly distributions of accrued preferred return on the preferred units, the EH Operating Agreement also (i) gives Eureka Holdings the right, at any time on or after the fifth anniversary of the closing of the initial Ridgeline investment,

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to redeem all, but not less than all, of the outstanding preferred units, and (ii) gives Ridgeline the right, at any time on or after the eighth anniversary of the closing of the initial Ridgeline investment, to require Eureka Holdings to redeem all, but not less than all, of the outstanding preferred units. If Eureka Holdings fails to meet its redemption obligations under clause (ii) above, then Ridgeline will have the right to assume control of the board of directors of Eureka Holdings and, at its option, to cause Eureka Holdings and/or its other owners to enter into a sale, merger or other disposition of Eureka Holdings or its assets (on terms acceptable to Ridgeline).

Further, pursuant to the terms of the EH Operating Agreement, the number and composition of the board of directors of Eureka Holdings may change over time based on Ridgeline’s percentage ownership interest in Eureka Holdings (after taking into account any additional purchases of preferred units) or the failure of Eureka Holdings to satisfy certain performance goals by the third anniversary of the closing of the initial Ridgeline investment (or as of any anniversary after such date). The board of directors of Eureka Holdings is currently composed of a majority of members appointed by Magnum Hunter. Subject to the rights described above, the board of directors of Eureka Holdings may in the future be composed of an equal number of directors appointed by Magnum Hunter and Ridgeline or, in certain cases, of a majority of directors appointed by Ridgeline.

The EH Operating Agreement originally contained a requirement that Ridgeline have an exclusive first right to fund up to 100% of Eureka Holdings’ funding requirements, subject to certain exceptions. On March 7, 2013, Magnum Hunter and Ridgeline entered into an amendment to the EH Operating Agreement which, among other things, provides Magnum Hunter a right to make additional capital contributions to Eureka Holdings in conjunction with or alongside additional capital contributions from Ridgeline.  Accordingly, Magnum Hunter contributed $30 million to Eureka Holdings on March 7, 2013, followed by Ridgeline contributing $20 million during April 2013.  Further, the agreement (as amended) provides that the next $70.5 million of additional capital contributions must be made 60% by Magnum Hunter and 40% by Ridgeline in order for each party to maintain their existing ownership percentage interests in Eureka Holdings.

If a change of control of Magnum Hunter occurs at any time prior to a qualified public offering (as defined in the EH Operating Agreement) of Eureka Holdings, Ridgeline will have the right under the terms of the EH Operating Agreement to purchase sufficient additional preferred units in Eureka Holdings so that it holds up to 51.0% of the equity ownership of Eureka Holdings.

The EH Operating Agreement also contains (i) preferred unit conversion rights in favor of Ridgeline, whereby it may convert its preferred units into common units of Eureka Holdings, (ii) transfer restrictions on Magnum Hunter’s ownership interests in Eureka Holdings (subject to certain exceptions), (iii) certain pre-emptive rights, rights of first refusal and co-sale rights in favor of Ridgeline and (iv) certain Securities Act registration rights in favor of Ridgeline.

Related Party Transactions

During 2012, 2011 and 2010, we rented an airplane for business use at various times from Pilatus Hunter, LLC, an entity 100% owned by Gary C. Evans, our chairman and chief executive officer. Airplane rental expenses totaled $174,000, $463,000 and $450,000 for the years ended December 31, 2012, 2011 and 2010, respectively.

In 2012, all accounting services were managed entirely by Magnum Hunter employees; however, during 2011 and 2010, we obtained accounting services and use of office space in Grapevine, Texas from GreenHunter Resources, Inc. (formerly GreenHunter Energy, Inc.), an entity of which Mr. Evans is the chairman, a major shareholder and former chief executive officer; of which Ronald D. Ormand, our chief financial officer and a director, is a former director; and of which David Krueger, our former chief accounting officer and senior vice president, is the chief financial officer. Our expenses for these matters totaled $162,000 and $212,000 for the years ended December 31, 2011 and 2010, respectively.

In October 2011, the Company purchased an office building from GreenHunter Resources, Inc. for $1.7 million. In conjunction with the purchase, the Company obtained a term loan from a financial institution in the amount of $1.4 million due on November 30, 2017, a portion of which loan is guaranteed by Mr. Evans. The building houses the accounting functions of Magnum Hunter, and the building purchase enabled the Company to terminate the previous services arrangement, as described above.

In 2011, we entered into a lease with an executive of the Company, as lessor, whereby we leased a corporate apartment in Houston, Texas from the executive, who had been transferred to our Appalachian operations, for monthly rent of $4,500, for use by Company employees. During the year ended December 31, 2012 and 2011, the Company paid rent of $22,500 and $36,000, respectively, under this lease. The lease terminated in May 2012.

During 2012 and 2011, Eagle Ford Hunter and Triad Hunter, wholly-owned subsidiaries of the Company, rented storage tanks for disposal water and equipment from GreenHunter Resources, Inc. Rental costs totaled $1.0 million and $1.3 million for the years ended December 31, 2012 and 2011, respectively. The Company believes that such services were provided to it at competitive market rates and were comparable to or more attractive than rates that could have been obtained from unaffiliated third-party suppliers of such services. Additionally, these companies regularly obtained, and we continue to obtain, services from GreenHunter Resources, Inc. for water disposal which are at competitive market rates. These disposal charges recorded in lease operating expenses totaled $2.4 million for the year ended December 31, 2012. As of December 31, 2012, we did not have any accounts payable to GreenHunter Resources, Inc. for these services.

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During 2012, Alpha Hunter Drilling, a wholly-owned subsidiary of the Company, performed drilling operations for GreenHunter Resources, Inc. Drilling services revenues totaled $1.1 million for the year ended December 31, 2012. Our net accounts receivable from GreenHunter Resources, Inc. for these services recorded in accounts receivable were $192,891 as of December 31, 2012, of which a discounted amount of $121,000 was received in February 2013.

Eagle Ford Hunter, Triad Hunter and Alpha Hunter Drilling regularly obtained, and we continue to obtain, services from GreenHunter Resources, Inc. for vacuum hauling, rig washing, waste fluid management and water management. The Company believes that such services are provided at competitive market rates and are comparable to or more attractive than rates that could be obtained from unaffiliated third-party suppliers of such services. Charges related to vacuum hauling, rig washing, waste fluid management and water management services recorded in lease operating expenses totaled $134,544 for the year ended December 31, 2012. As of December 31, 2012, we did not have any accounts payable to GreenHunter Resources, Inc. for these services.

In February 2012, the Company sold its wholly-owned subsidiary, Hunter Disposal, LLC, to GreenHunter Water, LLC, a wholly-owned subsidiary of GreenHunter Resources, Inc. The terms and conditions of the equity purchase agreement between the parties were approved by an independent special committee of the Company's board. Total consideration for the sale was approximately $9.3 million comprised of $2.2 million in cash, 1,846,722 shares of GreenHunter Resources, Inc. restricted common stock valued at $2.6 million based on a closing price of $1.79 per share, discounted for restrictions (equivalent to a price of approximately $1.57), 88,000 shares of GreenHunter Resources, Inc. 10% Series C Cumulative Preferred Stock with a fair value of $1.9 million, and a $2.2 million convertible promissory note which is convertible at the option of the Company into 880,000 shares of GreenHunter Resources, Inc. common stock based on the conversion price of $2.50 per share. The Company has recognized an embedded derivative asset resulting from the conversion option on the convertible promissory note with fair market value of $264,000 at December 31, 2012. The cash proceeds from the sale were adjusted downward to $783,000 for changes in working capital and certain fees to reflect the effective date of the sale of December 31, 2011. The Company has recorded interest income as a result of the note receivable from GreenHunter Resources, Inc. in the amount of $191,278 for the year ended December 31, 2012. As a result of this transaction, the Company has an investment in GreenHunter Resources, Inc. that is included in derivatives and other long term assets and recorded under the equity method. The loss related to this investment was $1.333 million for the year ended December 31, 2012. In connection with the sale, Triad Hunter entered into agreements with Hunter Disposal, LLC and GreenHunter Water, LLC for wastewater hauling and disposal capacity in Kentucky, Ohio and West Virginia and a five-year tank rental agreement with GreenHunter Water, LLC.

The Company acquired certain assets of TransTex Gas Services in April 2012 for $58.5 million. Mr. Evans was a 4.0% limited partner in TransTex Gas Services, which limited partnership received total consideration of 622,641 Class A Common Units of Eureka Hunter Holdings, LLC and cash of $46.0 million upon the Company’s acquisition of the assets of TransTex Gas Services. These units included units issued in accordance with the agreement of Eureka Holdings and TransTex Gas Services to provide the limited partners of TransTex Gas Services the opportunity to purchase Class A Common Units of Eureka Holdings in lieu of a portion of the cash otherwise payable for the TransTex Gas Services assets (which cash would have been distributed by TransTex Gas Services to its limited partners). Certain limited partners purchased such units, including Mr. Evans, who purchased 27,641 Class A Common Units of Eureka Holdings for $553,000 at the same per unit purchase price offered to all TransTex Gas Services limited partners.

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Contractual Commitments

Our contractual commitments consist primarily of long-term debt, accrued interest on long-term debt, operating lease obligations, asset retirement obligations, an employment agreement with a senior officer, drilling contracts, gas gathering and transportation contracts, dividends on preferred stock and commodity derivative liabilities. The following table summarizes these commitments as of December 31, 2012 (in thousands):

Contractual Obligations	Total		2013		2014 - 2015		2016 - 2017		After 2017
Long-term debt(1)	$	890,760	$	3,991	$	10,780	$	228,776	$	647,213
Interest on long-term debt(2)	497,951		72,663		145,477		131,125		148,686
Dividends on preferred stock(3)	73,489		29,175		28,889		15,425		—
Gas transportation contracts(4)	32,254		4,171		8,450		5,964		13,669
Asset retirement obligations(5)	30,680		2,358		1,803		7,295		19,224
Drilling contract commitment(6)	10,704		5,840		4,864		—		—
Commodity derivative liabilities (7)	7,477		3,501		3,976		—		—
Operating lease obligations(8)	1,361		765		537		59		—
Employment agreement with senior officer(9)	200		200		—		—		—
Total	$	1,544,876	$	122,664	$	204,776	$	388,644	$	828,792

⁽¹⁾  Our long-term debt comprises borrowings under our MHR Senior Revolving Credit Facility, the indenture governing our Senior Notes, the Eureka Pipeline Term Loan, and term equipment debt and loans related to our buildings. See "Note 10 - Long-term Debt", to the Company’s consolidated financial statements.

⁽²⁾  Interest payments have been calculated by applying the interest rate in effect as of December 31, 2012 on the debt facilities in place as of December 31, 2012. This results in a weighted average interest rate of 5.65%.

⁽³⁾  As of December 31, 2012, the Company had Series C, Series D, and Series E Preferred Stock, and Eureka Holdings had Series A Convertible Preferred Units, outstanding with liquidation values of $210.4 million, $94.4 million, $100.0 million, and $153.5 million, respectively. Dividends are calculated based on the stated yield of the preferred equity for the time remaining until redemption by the Company is possible. See "Note 12 - Shareholders' Equity" to our consolidated financial statements for further details regarding our obligations to preferred shareholders.

⁽⁴⁾  On December 14, 2011, the Company entered into a 120-month gas transportation contract. The contract became effective on August 1, 2012. Our remaining liability under the contract was approximately $24.5 million as of December 31, 2012. On June 27, 2012, Eureka Pipeline entered into 36-month gas compression contract. The contract became effective on October 1, 2012. Our remaining liability under the contract was $3.9 million as of December 31, 2012. With the Virco Acquisition, Triad Hunter assumed a 120-month gas transportation contract. Our remaining liability under the contract was $3.9 million as of December 31, 2012. See "Note 18 - Commitments and Contingencies" to our consolidated financial statements for further details regarding our gathering commitments.

⁽⁵⁾  Our asset retirement obligation represents the estimated present value of the amount we will incur to plug, abandon and remediate our producing properties at the end of their productive lives, in accordance with applicable federal, state and local laws. We determine our asset retirement obligation by calculating the present value of estimated cash flows related to the liability. The retirement obligation is recorded as a liability at its estimated present value as of the asset’s inception, with an offsetting increase to proved properties. Periodic accretion of discount of the estimated liability is recorded as an expense in the consolidated statement of operations. See "Note 9 - Asset Retirement Obligations" to our consolidated financial statements for a discussion of our asset retirement obligations.

⁽⁶⁾  On June 24, 2011, the Company entered into a 40-month drilling contract from July 1, 2011, through October 31, 2014. Our remaining maximum liability under the drilling contract, which would apply if we terminated the contract before the end of its term, was approximately $10.7 million as of December 31, 2012. This drilling contract was assigned to the purchaser of Eagle Ford Hunter in connection with the sale of that entity in April 2013.

⁽⁷⁾  Derivative obligations represent net liabilities determined in accordance with master netting arrangements for commodity derivatives that were valued as of December 31, 2012. The ultimate settlement amounts of the Company’s derivative obligations are unknown because they are subject to continuing market risk. See “Item 7A. Quantitative and Qualitative Disclosures About Market Risk” and "Note 5 - Financial Instruments and Derivatives" to our consolidated financial statements for additional information regarding the Company’s derivative obligations.

⁽⁸⁾  As of December 31, 2012, office space rentals with terms of 12 months or greater include leases that total approximately 25,000 square feet with combined monthly payments of $61,000.

⁽⁹⁾  At December 31, 2012, we had an employment agreement with a senior officer with a maximum commitment, if the employee were terminated without cause, of approximately $200,000. As of May 1, 2013, this person was no longer employed by the Company.

Off-Balance Sheet Arrangements

From time to time, we enter into off-balance sheet arrangements and transactions that can give rise to off-balance sheet obligations. As of December 31, 2012, the off-balance sheet arrangements and transactions that we have entered into include operating lease agreements. We do not believe that these arrangements are reasonably likely to have a current or future effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that is material to investors.

Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Some of the information below contains forward-looking statements. The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in oil and gas prices and other related factors. The disclosure is not meant to be a precise indicator of expected future losses, but rather an indicator of reasonable possible losses. This forward-looking information provides an indicator of how we view and manage our ongoing market risk exposures. Our market risk sensitive instruments were entered into for commodity derivative and investment purposes, not for trading purposes.

Quantitative Disclosures

Interest Rate Sensitivity

See "Note 10 - Long-Term Debt" of "Notes to Consolidated Financial Statements" included in "Item 8. Financial Statements and Supplementary Data" and "Liquidity and Capital Resources" included in "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" for information regarding debt transactions.

The following tables provide information about financial instruments to which the Company was a party as of December 31, 2012, that were sensitive to changes in interest rates. For debt obligations, the tables present maturities by expected maturity dates, the weighted average interest rates expected to be paid on the debt given current contractual terms and market conditions and the debt's estimated fair value. For fixed rate debt, the weighted average interest rates represent the contractual fixed rates that the Company was obligated to periodically pay on the debt as of December 31, 2012. For variable rate debt, the average interest rate represents the average rates being paid on the debt projected forward proportionate to the forward yield curve for LIBOR on May 1, 2013.

We have been required to pay penalty interest on our Senior Notes since May 16, 2013 as a result of our failure to complete the exchange offer for, or file a shelf registration statement with respect to, our Senior Notes, and we will be required to pay penalty interest until the exchange offer has been completed or the shelf registration statement has been declared effective.

	Year ending December 31,
	2013			2014			2015			2016			2017			After 2017			Total		Liability Fair Value
	(in millions, except percentages)
Total Debt:
Fixed rate principal maturities	$	4.0		$	4.4		$	6.4		$	2.6		$	1.1		$	647.2		$	665.8	$	613.5
Weighted average interest rate	9.79		%	9.76		%	9.72		%	9.69		%	9.68		%	9.68		%
Variable rate principal maturities	$	—		$	—		$	—		$	225.0		$	—		$	—		$	225.0	$	225.0
Weighted average interest rate	3.46		%	3.58		%	3.88		%	4.39		%	—		%	—		%

Commodity Price Risk

Given the current economic outlook, we expect commodity prices to remain volatile. Even modest decreases in commodity prices can materially affect our revenues and cash flow. In addition, if commodity prices remain suppressed for a significant amount of time, we could be required under successful efforts accounting rules to write down our oil and gas properties.

At December 31, 2012 and 2011, the fair value of our open commodity derivative contracts was a net liability of approximately $2.6 million, and a liability of $5.0 million, respectively.

Changes in commodity prices could have a significant effect on the fair value of our derivative contracts. A hypothetical 10% increase in the NYMEX floating prices would have resulted in a $28.1 million decrease in the December 31, 2012 fair value recorded on our balance sheet and a corresponding increase to the loss on commodity derivatives in our statement of operations. A hypothetical 10% decrease in the NYMEX floating prices would have a resulted in a $24.5 million increase in the December 31, 2012 fair value recorded on our balance sheet and would have increased the gain on commodity derivatives in our statement of operations by the corresponding

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amount. See "Note 3 - Summary of Significant Accounting Policies", "Note 4 - Fair Value of Financial Instruments", and "Note 5 - Financial Instruments and Derivatives" of "Notes to Consolidated Financial Statements" included in "Item 8. Financial Statements and Supplementary Data" for information regarding derivative transactions.

Embedded Derivatives

Preferred Stock Embedded Derivative

The conversion option, redemption options and other features of the Series A Preferred Units of Eureka Holdings require bifurcation and separate accounting as embedded derivatives. The fair value of this embedded feature was determined to be $43.5 million and $0 in the aggregate at December 31, 2012 and 2011, respectively.  

The preferred stock embedded derivative was valued using the “with and without” analysis in a simulation model. The key inputs used in the model were a volatility of 22.3%, credit spread of 14.64%, and an estimated enterprise value of Eureka Holdings of $483.8 million. Changes in volatility, credit spread, or enterprise value could have a significant effect on the fair value of the embedded derivative liability bifurcated from the preferred units. See "Note 3 - Summary of Significant Accounting Policies", "Note 4 - Fair Value of Financial Instruments", and "Note 5 - Financial Instruments and Derivatives" of "Notes to Consolidated Financial Statements" included in "Item 8. Financial Statements and Supplementary Data" for information regarding derivative transactions. 

Convertible Security Embedded Derivative

The Company recognized an embedded derivative asset resulting from the fair value of the bifurcated conversion feature associated with the convertible note received as partial consideration upon the sale of Hunter Disposal, LLC to GreenHunter Resources, Inc.  The convertible security embedded derivative was valued using a Black-Scholes model valuation of the conversion option. The fair value of the bifurcated conversion feature associated with the convertible note was $264,000 as of December 31, 2012. The feature was valued using a Black-Scholes option pricing model with the key inputs of a life of 4.1 years, a risk-free interest rate of 0.67%, an estimated volatility of 40%, dividends of $0, and a price of a common share of GreenHunter Resources, Inc., the underlying security, of $1.61 as of December 31, 2012. Changes to the key inputs used could have a significant effect on the fair value of the bifurcated conversion feature associated with the convertible note. See "Note 3 - Summary of Significant Accounting Policies", "Note 4 - Fair Value of Financial Instruments", and "Note 5 - Financial Instruments and Derivatives" of "Notes to Consolidated Financial Statements" included in "Item 8. Financial Statements and Supplementary Data" for information regarding derivative transactions.

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Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO FINANCIAL STATEMENTS

Reports of Independent Registered Public Accounting Firms	F-2
Consolidated Balance Sheets at December 31, 2012 and 2011	F-6
Consolidated Statements of Operations for the years ended December 31, 2012, 2011, and 2010	F-8
Consolidated Statements of Comprehensive Loss for the years ended December 31, 2012, 2011, and 2010	F-9
Consolidated Statements of Shareholders’ Equity for the years ended December 31, 2012, 2011, and 2010	F-10
Consolidated Statements of Cash Flows for the years ended December 31, 2012, 2011, and 2010	F-11
Notes to Consolidated Financial Statements	F-12

Report of Independent Registered Public Accounting Firm

Board of Directors and Shareholders

Magnum Hunter Resources Corporation

Houston, Texas

We have audited the accompanying consolidated balance sheet of Magnum Hunter Resources Corporation as of December 31, 2012, and the related consolidated statements of operations, comprehensive loss, shareholders' equity, and cash flows for year then ended. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audit.

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

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Magnum Hunter Resources Corporation at December 31, 2012, and the results of its operations and its cash flows for the year then ended, in conformity with accounting principles generally accepted in the United States of America.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Magnum Hunter Resources Corporation's internal control over financial reporting as of December 31, 2012, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) and our report dated June 14, 2013, expressed an adverse opinion thereon.

/s/ BDO USA, LLP

Dallas, Texas

June 14, 2013

F-2

Report of Independent Registered Public Accounting Firm

Board of Directors and Shareholders

Magnum Hunter Resources Corporation

Houston, Texas

We have audited Magnum Hunter Resources Corporation's internal control over financial reporting as of December 31, 2012, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Magnum Hunter Resources Corporation's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying, “Item 9A, Management's Report on Internal Control Over Financial Reporting”. Our responsibility is to express an opinion on the company's internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

As indicated in the accompanying “Item 9A, Management's Report on Internal Control over Financial Reporting”, management's assessment of and conclusion on the effectiveness of internal control over financial reporting did not include the internal controls of the subsidiaries acquired from TransTex Gas Services, LP on April 2, 2012 and Viking International Resources Co., Inc., on November 2, 2012, which are included in the consolidated balance sheet of Magnum Hunter Resources Corporation as of December 31, 2012, and the related consolidated statements of operations, comprehensive loss, shareholders' equity, and cash flows for the year then ended. The subsidiaries excluded from management's assessment of internal controls over financial reporting constitute approximately 8 percent of consolidated total assets as of December 31, 2012, and 3 percent of consolidated total revenue for the year then ended. Management did not assess the effectiveness of internal control over financial reporting of these subsidiaries because of the timing of the acquisitions. Our audit of internal control over financial reporting of Magnum Hunter Resources Corporation also did not include an evaluation of the internal control over financial reporting of these subsidiaries.

A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the company's annual or interim financial statements will not be prevented or detected on a timely basis. Material weaknesses regarding management's failure to design and maintain internal control over financial reporting have been identified and include the following as described in management's assessment:

• Effective Control Environment to Meet the Company's Growth

• Financial Reporting

• Leasehold Property Costs

• Complex Accounting Issues

• Income Taxes

These material weaknesses were considered in determining the nature, timing, and extent of audit tests applied in our audit of the 2012 consolidated financial statements, and this report does not affect our report dated June 14, 2013, on those consolidated financial statements.

F-3

In our opinion, Magnum Hunter Resources Corporation did not maintain, in all material respects, effective internal control over financial reporting as of December 31, 2012, based on the COSO criteria.

We do not express an opinion or any other form of assurance on management's statements referring to any corrective actions taken by the company after the date of management's assessment.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet of Magnum Hunter Resources Corporation as of December 31, 2012, and the related consolidated statements of operations, comprehensive loss, shareholders' equity, and cash flows for the year then ended and our report dated June 14, 2013, expressed an unqualified opinion thereon.

/s/ BDO USA, LLP

Dallas, Texas

June 14, 2013

F-4

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Stockholders

Magnum Hunter Resources Corporation

We have audited the accompanying consolidated balance sheets of Magnum Hunter Resources Corporation and subsidiaries (collectively the “Company”) as of December 31, 2011, and the related consolidated statements of operations, comprehensive income, stockholders' equity, and cash flows for each of the years ended December 31, 2011 and 2010. Our audits also included the financial statement schedule of the Company listed in Item 15(a). These financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

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

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2011, and the results of its operations and cash flows for each of the years ended December 31, 2011 and 2010, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, the related financial statement schedule, when considered in relation to the consolidated financial statements taken as a whole, present fairly in all material respects the information set forth therein.

/s/ Hein & Associates LLP

Dallas, Texas

February 29, 2012

F-5

MAGNUM HUNTER RESOURCES CORPORATION

CONSOLIDATED BALANCE SHEETS

(In thousands, except share and per share data)

	December 31,
	2012			2011
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	57,623		$	14,851
Restricted cash	1,500			—
Accounts receivable - Net of allowance for doubtful accounts of $448 and $311 as of December 31, 2012 and 2011, respectively	124,861			48,083
Derivative assets	5,146			5,732
Inventory	9,162			4,534
Investments	3,278			497
Prepaid expenses and other assets	2,249			1,224
Assets held for sale	500			2,748
Total current assets	204,319			77,669
PROPERTY, PLANT AND EQUIPMENT:
Oil and natural gas properties, successful efforts method of accounting	1,908,118			1,024,975
Accumulated depletion, depreciation, and amortization	(185,615		)	(62,010		)
Total oil and natural gas properties, net	1,722,503			962,965
Gas transportation, gathering and processing equipment, net	201,910			112,169
Total property and equipment, net	1,924,413			1,075,134
OTHER ASSETS:
Deferred financing costs, net of amortization of $8,024 and $958 as of December 31, 2012 and 2011, respectively	23,862			10,642
Derivatives and other assets	6,455			1,913
Intangible assets, net	8,981			—
Goodwill	30,602			—
Assets held for sale	—			3,402
Total Assets	$	2,198,632		$	1,168,760

The accompanying Notes to Consolidated Financial Statements are an integral part of these Statements

F-6

MAGNUM HUNTER RESOURCES CORPORATION

CONSOLIDATED BALANCE SHEETS

(In thousands, except share and per share data)

	December 31,
	2012			2011
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES:
Current portion of notes payable	$	3,991		$	4,565
Accounts payable	196,515			138,320
Accrued liabilities	11,212			3,708
Revenue payable	20,394			10,781
Derivatives and other liabilities	11,544			7,454
Liabilities associated with assets held for sale	—			2,847
Total current liabilities	243,656			167,675
Long-term debt	886,769			285,824
Asset retirement obligation	28,322			20,089
Deferred tax liability	74,258			95,299
Derivative liabilities	47,524			6,112
Other long-term liabilities	5,573			2,842
Liabilities associated with assets held for sale	—			267
Total liabilities	1,286,102			578,108
COMMITMENTS AND CONTINGENCIES (Note 18)
REDEEMABLE PREFERRED STOCK:
Series C Cumulative Perpetual Preferred Stock, cumulative dividend rate 10.25% per annum, 4,000,000 shares authorized, 4,000,000 shares issued and outstanding as of December 31, 2012 and 2011, respectively, with liquidation preference of $25.00 per share	100,000			100,000
Series A Convertible Preferred Units of Eureka Hunter Holdings, LLC, cumulative distribution rate of 8.0% per annum, 7,672,892 shares and none issued and outstanding as of December 31, 2012 and 2011, respectively, with liquidation preference of $167,403 and $0 as of December 31, 2012 and 2011, respectively	100,878			—
	200,878			100,000
SHAREHOLDERS' EQUITY:
Preferred stock, 10,000,000 shares authorized
Series D Cumulative Preferred Stock, cumulative dividend rate 8.0% per annum, 5,750,000 shares authorized, 4,208,821 and 1,437,558 shares issued and outstanding as of December 31, 2012 and December 31, 2011, respectively, with liquidation preference of $50.00 per share	210,441			71,878
Series E Cumulative Convertible Preferred Stock, cumulative dividend rate 8.0% per annum, 12,000 shares authorized, 3,775 shares issued and 3,705 shares outstanding and none issued and outstanding as of December 31, 2012 and 2011, respectively, with liquidation preference of $25,000 per share	94,371			—
Common stock, $0.01 par value; 250,000,000 shares authorized, 170,032,999 shares and 129,803,374 shares issued and 169,118,047 shares and 129,041,722 shares outstanding as of December 31, 2012 and 2011, respectively	1,700			1,298
Exchangeable common stock, par value $0.01 per share, 505,835 and 3,693,871 shares issued and outstanding as of December 31, 2012 and December 31, 2011, respectively	5			37
Additional paid in capital	715,033			569,690
Accumulated deficit	(307,484		)	(140,070		)
Accumulated other comprehensive loss	(8,889		)	(12,463		)
Treasury stock, at cost
Series E Cumulative Preferred Stock, 70 shares and none as of December 31, 2012 and 2011, respectively	(1,750		)	—
Common stock, 914,952 and 761,652 shares as of December 31, 2012 and 2011, respectively	(1,914		)	(1,310		)
Unearned common stock in KSOP at cost, none and 153,300 shares as of December 31, 2012 and 2011, respectively	—			(604		)
Total Magnum Hunter Resources Corporation shareholders' equity	701,513			488,456
Non-controlling interest	10,139			2,196
Total shareholders' equity	711,652			490,652
Total Liabilities and Shareholders’ Equity	$	2,198,632		$	1,168,760

The accompanying Notes to Consolidated Financial Statements are an integral part of these Statements

F-7

MAGNUM HUNTER RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except share and per share data)

	Year Ended December 31,
	2012			2011			2010
REVENUE:
Oil and gas sales	$	245,394		$	106,205		$	27,715
Gas transportation, gathering and processing	13,040			494			163
Oil field services	12,333			7,149			1,222
Other revenue	204			(168		)	250
Total revenue	270,971			113,680			29,350
EXPENSES:
Lease operating expenses	51,359			26,355			10,687
Severance taxes and marketing	15,046			7,475			2,381
Exploration and abandonments	117,216			2,645			942
Gas transportation, gathering and processing	8,028			373			214
Oil field services	10,037			6,759			1,272
Impairment of proved oil and gas properties	4,096			21,792			306
Depreciation, depletion, amortization and accretion	135,846			48,762			8,756
General and administrative	64,388			62,902			24,773
Total expenses	406,016			177,063			49,331
OPERATING LOSS	(135,045		)	(63,383		)	(19,981		)
OTHER INCOME (EXPENSE):
Interest income	230			27			61
Interest expense (Note 10)	(51,846		)	(11,984		)	(3,584		)
Gain (loss) on derivative contracts, net	22,239			(6,346		)	814
Other	2,046			1,601			9
Total other expense	(27,331		)	(16,702		)	(2,700		)
Loss from continuing operations before income tax	(162,376		)	(80,085		)	(22,681		)
Income tax benefit	23,016			696			—
Loss from continuing operations	(139,360		)	(79,389		)	(22,681		)
Income from discontinued operations, net of tax	230			2,977			2,350
Gain on sale of discontinued operations, net of tax	2,409			—			6,660
Net loss	(136,721		)	(76,412		)	(13,671		)
Net loss (income) attributable to non-controlling interest	4,013			(249		)	(129		)
Net loss attributable to Magnum Hunter Resources Corporation	(132,708		)	(76,661		)	(13,800		)
Dividends on preferred stock	(34,706		)	(14,007		)	(2,467		)
Net loss attributable to common shareholders	$	(167,414	)	$	(90,668	)	$	(16,267	)
Weighted average number of common shares outstanding, basic and diluted	155,743,418			113,154,270			63,921,525
Loss from continuing operations per share, basic and diluted	$	(1.09	)	$	(0.83	)	$	(0.39	)
Income from discontinued operations per share, basic and diluted	0.02			0.03			0.14
Net loss per common share, basic and diluted	$	(1.07	)	$	(0.80	)	$	(0.25	)
Amounts attributable to Magnum Hunter Resources Corporation:
Loss from continuing operations, net of tax	$	(135,347	)	$	(79,638	)	$	(22,810	)
Discontinued operations, net of tax	2,639			2,977			9,010
Net loss	$	(132,708	)	$	(76,661	)	$	(13,800	)

The accompanying Notes to Consolidated Financial Statements are an integral part of these Statements

F-8

MAGNUM HUNTER RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS

(In thousands)

	Year ended December 31,
	2012			2011			2010
Net loss	(136,721		)	(76,412		)	(13,671		)
Foreign currency translation gain (loss)	3,883			(12,477		)	—
Unrealized gain (loss) on available for sale investments	(309		)	14			—
Comprehensive loss	(133,147		)	(88,875		)	(13,671		)
Comprehensive income (loss) attributable to non-controlling interests	(4,013		)	249			129
Comprehensive loss attributable to Magnum Hunter Resources Corporation	$	(129,134	)	$	(89,124	)	$	(13,800	)

The accompanying Notes to Consolidated Financial Statements are an integral part of these Statements

F-9

MAGNUM HUNTER RESOURCES CORPORATION

CONSOLIDATED STATEMENT OF SHAREHOLDERS' EQUITY

(In thousands)

	Number of Shares of Common Stock	Number of Shares of Exchangeable Common Stock		Number of Shares of Series D Preferred Stock	Number of Shares of Series E Preferred Stock	Deposit on Triad			Series D Preferred Stock		Series E Preferred Stock		Common Stock		Exchangeable Common Stock			Additional Paid in Capital			Accumulated Deficit			Accumulated Other Comprehensive Loss			Treasury Stock			Unearned Common Shares in KSOP			Non-controlling Interest			Total Shareholders' Equity
BALANCE, January 1, 2010	50,591	—		—	—	$	(1,310	)	$	—	$	—	$	506	$	—		$	71,936		$	(33,135	)	$	—		$	—		$	—		$	1,321		$	39,318
Share based compensation	2,539	—		—	—	—			—		—		25		—			6,355			—			—			—			—			—			6,380
Stock Options surrendered by holder for cash payment	—	—		—	—	—			—		—		—		—			(116		)	—			—			—			—			—			(116		)
Issued shares of Common Stock for payment of services	56	—		—	—	—			—		—		1		—			164			—			—			—			—			—			165
Sold shares of Series C Preferred Stock for cash	—	—		—	—	—			—		—		—		—			(1,419		)	—			—			—			—			—			(1,419		)
Sold shares of Common Stock for cash	10,832	—		—	—	—			—		—		108		—			38,570			—			—			—			—			—			38,678
Issued shares of Common Stock upon exercise of warrants and options	7,590	—		—	—	—			—		—		76		—			16,156			—			—			—			—			—			16,232
Issued shares of Common Stock upon redemption of Series B Convertible Preferred Stock	1,000	—		—	—	—			—		—		10		—			3,722			—			—			—			—			—			3,732
Preferred dividends	—	—		—	—	—			—		—		—		—			—			(2,467		)	—			—			—			—			(2,467		)
761,652 shares of common stock as deposit on Triad Acquisition returned to treasury	—	—		—	—	1,310			—		—		—		—			—			—			—			(1,310		)	—			—			—
Loan of 153,300 shares to KSOP	—	—		—	—	—			—		—		—		—			—			—			—			—			(604		)	—			(604		)
Issued shares of common stock for acquisition of assets	2,255	—		—	—	—			—		—		23		—			17,071			—			—			—			—			—			17,094
Net loss	—	—		—	—	—			—		—		—		—			—			(13,800		)	—			—			—			129			(13,671		)
BALANCE, December 31, 2010	74,863	—		—	—	$	—		$	—	$	—	$	749	$	—		$	152,439		$	(49,402	)	$	—		$	(1,310	)	$	(604	)	$	1,450		$	103,322
Share based compensation	121	—		—	—	—			—		—		1		—			25,056			—			—			—			—			—			25,057
Issued shares of Series C Preferred Stock for cash	—	—		—	—	—			—		—		—		—			(689		)	—			—			—			—			—			(689		)
Sold shares of Common Stock for cash	1,714	—		—	—	—			—		—		17		—			13,875			—			—			—			—			—			13,892
Sold shares of Preferred Stock for cash	—	—		1,438	—	—			71,878		—		—		—			(6,189		)	—			—			—			—			—			65,689
Issued shares of Common Stock upon exercise of warrants and options	6,293	—		—	—	—			—		—		63		—			7,555			—			—			—			—			—			7,618
Preferred dividends	—	—		—	—	—			—		—		—		—			—			(14,007		)	—			—			—			—			(14,007		)
Issued 12,875,093 warrants for payment of dividends on common stock with fair market value of $6.7 million	—	—		—	—	—			—		—		—		—			—			—			—			—			—			—			—
Issued 378,174 warrants for payment of dividends on MHR Exchangeco Corporation's exchangeable common stock with fair market value of $197 thousand	—	—		—	—	—			—		—		—		—			—			—			—			—			—			—			—
Issued shares of Common Stock for acquisitions	45,713	—		—	—	—			—		—		456		—			342,278			—			—			—			—			—			342,734
Issued shares of Common Stock to employees for change in control payments for NGAS Resources	351	—		—	—	—			—		—		4		—			2,798			—			—			—			—			—			2,802
Issued 138,388 warrants in replacement of NGAS Resources warrants	—	—		—	—	—			—		—		—		—			190			—			—			—			—			—			190
Non-controlling interest acquired in NGAS acquisition	—	—		—	—	—			—		—		—		—			—			—			—			—			—			497			497
Issued exchangeable shares for acquisition of NuLoch Resources	—	4,276		—	—	—			—		—		—		43			31,600			—			—			—			—			—			31,643
Issued shares of Common Stock upon exchange of MHR Exchangeco Corporation's exchangeable shares	582	(582	)	—	—	—			—		—		6		(6		)	—			—			—			—			—			—			—
Issued shares of Common Stock for commitment fee	166	—		—	—	—			—		—		2		—			777			—			—			—			—			—			779
Net loss	—	—		—	—	—			—		—		—		—			—			(76,661		)	—			—			—			249			(76,412		)
Foreign currency translation	—	—		—	—	—			—		—		—		—			—			—			(12,477		)	—			—			—			(12,477		)
Unrealized gain on available for sale securities	—	—		—	—	—			—		—		—		—			—			—			14			—			—			—			14
BALANCE, December 31, 2011	129,803	3,694		1,438	—	$	—		$	71,878	$	—	$	1,298	$	37		$	569,690		$	(140,070	)	$	(12,463	)	$	(1,310	)	$	(604	)	$	2,196		$	490,652
Share based compensation	108	—		—	—	—			—		—		1		—			15,695			—			—			—			—			—			15,696
Issued shares as Employer Match on 401K	199	—		—	—	—			—		—		2		—			872			—			—			—			—			—			874
Sold shares of Preferred Stock for cash	—	—		2,771	1	—			138,563		25,000		—		—			(18,928		)	—			—			—			—			—			144,635
Sold shares of Common Stock for cash	35,000	—		—	—				—		—		350		—			147,891			—			—			—			—			—			148,241
Issued shares of Common Stock upon exercise of warrants and options	1,438	—		—	—	—			—		—		14		—			2,317			—			—			—			—			—			2,331
Preferred dividends	—	—		—	—	—			—		—		—		—			—			(34,706		)	—			—			—			—			(34,706		)
Issued shares of Common Stock for acquisition of assets	297	—		—	—	—			—		—		3		—			1,899			—			—			—			—			—			1,902
Issued shares of Preferred Stock for acquisition of assets	—	—		—	3	—			—		69,371		—		—			(4,403		)	—			—			—			—			—			64,968
Issued shares of common stock upon exchange of MHR Exchangeco Corporation's exchangeable shares	3,188	(3,188	)	—	—	—			—		—		32		(32		)	—			—			—			—			—			—			—
Purchase of outstanding non-controlling interest in a subsidiary	—	—		—	—	—			—		—		—		—			—			—			—			—			—			(497		)	(497		)
Issued common units of Eureka Hunter Holdings for asset acquisition	—	—		—	—	—			—		—		—		—			—			—			—			—			—			12,453			12,453
Common shares returned to Treasury from KSOP	—	—		—	—	—			—		—		—		—			—			—			—			(604		)	604			—			—
Purchase of treasury shares	—	—		—	—	—			—		—		—		—			—			—			—			(1,750		)	—			—			(1,750		)
Net loss	—	—		—	—	—			—		—		—		—			—			(132,708		)	—			—			—			(4,013		)	(136,721		)
Foreign currency translation	—	—		—	—	—			—		—		—		—			—			—			3,883			—			—			—			3,883
Unrealized loss on available for sale securities	—	—		—	—	—			—		—		—		—			—			—			(309		)	—			—			—			(309		)
BALANCE, December 31, 2012	170,033	506		4,209	4	$	—		$	210,441	$	94,371	$	1,700	$	5		$	715,033		$	(307,484	)	$	(8,889	)	$	(3,664	)	$	—		$	10,139		$	711,652

The accompanying Notes to Consolidated Financial Statements are an integral part of these Statements

F-10

MAGNUM HUNTER RESOURCES CORPORATION

CONSOLIDATED STATEMENT OF CASH FLOWS

(In thousands)

	Year Ended December 31,
	2012			2011			2010
Cash flows from operating activities
Net loss	$	(136,721	)	$	(76,412	)	$	(13,671	)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Depletion, depreciation, amortization and accretion	135,896			49,090			10,346
Share-based compensation	15,696			25,057			6,380
Impairment of oil and gas properties	4,096			21,782			306
Exploration and abandonments	116,686			1,118			—
Gain on sale of assets	(3,074		)	(186		)	(6,731		)
Unrealized (gain) loss on derivative contracts	(10,945		)	4,210			3,063
Unrealized loss on investments	2,200			—			—
Amortization and write off of deferred financing cost and discount on Senior Notes included in interest expense	7,399			3,636			1,201
Deferred tax benefit	(21,595		)	(696		)	—
Changes in operating assets and liabilities:
Accounts receivable, net	(73,549		)	(25,075		)	(2,949		)
Inventory	(6,198		)	(3,889		)	—
Prepaid expenses and other current assets	(538		)	(124		)	134
Accounts payable	16,390			25,883			8,866
Revenue payable	8,776			6,979			359
Accrued liabilities	3,492			2,465			(8,472		)
Net cash provided by (used in) operating activities	58,011			33,838			(1,168		)
Cash flows from investing activities
Capital expenditures and advances	(568,610		)	(291,942		)	(80,078		)
Cash paid in acquisitions, net of cash received of $34; $2,500; and $0, respectively	(444,844		)	(78,524		)	(59,500		)
Proceeds from sale of assets	4,158			8,709			21,238
Change in deposits and other long-term assets	89			42			59
Net cash used in investing activities	(1,009,207		)	(361,715		)	(118,281		)
Cash flows from financing activities
Proceeds from issuing Senior Notes	596,907			—			—
Proceeds from borrowings on debt	546,043			493,906			101,581
Proceeds from sale of Series A preferred units in Eureka Hunter Holdings	149,655			—			—
Net proceeds from sale of common stock	148,241			13,892			38,678
Net proceeds from sale of preferred shares	144,635			94,764			63,444
Proceeds from exercise of warrants and options	2,331			7,618			16,232
Change in other long-term liabilities	186			69			—
Options surrendered for cash	—			—			(116		)
Cash paid upon conversion of Series B Preferred Stock	—			—			(11,250		)
Purchase of treasury shares	(1,750		)	—			(604		)
Payment of deferred financing costs	(20,313		)	(11,577		)	(2,866		)
Preferred stock dividends paid	(26,839		)	(14,007		)	(2,492		)
Principal repayments of debt	(542,654		)	(242,472		)	(84,886		)
Net cash provided by financing activities	996,442			342,193			117,721
Effect of foreign exchange rate changes on cash	(2,474		)	(19		)	—
Net change in cash and cash equivalents	42,772			14,297			(1,728		)
Cash and cash equivalents, beginning of year	14,851			554			2,282
Cash and cash equivalents, end of year	$	57,623		$	14,851		$	554
Cash paid for interest	$	40,069		$	7,952		$	2,749
Non-cash transactions
Common stock issued for acquisitions	$	1,902		$	345,537		$	17,093
Non-cash additions to asset retirement obligation	$	8,492		$	12,628		$	2,324
Non-cash consideration received from sale of assets	$	7,120		$	—		$	—
Preferred stock issued for acquisitions	$	64,968		$	—		$	14,982
Debt assumed in acquisitions	$	—		$	71,895		$	3,412
Common stock issued for payment of services	$	—		$	779		$	165
Common stock issued in conversion of Series C Convertible Preferred Stock	$	—		$	—		$	3,732
Change in accrued capital expenditures	$	34,621		$	81,136		$	23,218
Common stock issued for 401(k) matching contribution	$	874		$	—		$	—
Eureka Hunter Holdings Series A preferred dividends paid in kind	$	1,658		$	—		$	—
Eureka Hunter Holdings Series A common units issued for an acquisition	$	12,453		$	—		$	—
Exchangeable common stock issued for acquisition of NuLoch Resources	$	—		$	31,642		$	—
Warrants issued for payment of common stock dividends	$	—		$	6,695		$	—
Warrants issued for payment of dividends on MHR Exchangeco Corporation exchangeable shares	$	—		$	197		$	—

The accompanying Notes to Consolidated Financial Statements are an integral part of these Statements

F-11

MAGNUM HUNTER RESOURCES CORPORATION

Notes to Consolidated Financial Statements

NOTE 1—ORGANIZATION AND NATURE OF OPERATIONS

Magnum Hunter Resources Corporation, a Delaware corporation, operating directly and indirectly through its subsidiaries (“Magnum Hunter” or the “Company”), is a Houston, Texas based independent exploration and production company engaged in the acquisition and development of producing properties and undeveloped acreage and the production of oil and natural gas in the United States and Canada and certain midstream and oil field service activities.

NOTE 2—LIQUIDITY

At December 31, 2012, we had (i) unrestricted and restricted cash and cash equivalents of $57.6 million and $1.5 million, respectively, of which $36.3 million was held by our subsidiary Eureka Hunter Holdings, LLC or its subsidiaries (which are unrestricted subsidiaries under our senior credit facility) and was only available for use by Eureka Hunter Holdings, LLC or its subsidiaries; and (ii) a working capital deficit of $39.3 million.

We utilize our credit agreements, as described in "Note 10 - Long-Term Debt", to fund a portion of our operating and capital needs. Under our MHR Senior Revolving Credit Facility, our total outstanding debt at December 31, 2012 was $225.0 million, with at borrowing base at December 31, 2012 of $337.5 million.Thus, our remaining available borrowing capacity under the MHR Senior Revolving Credit Facility at that date was $112.5 million. Pursuant to the terms of our MHR Senior Revolving Credit Facility, our borrowing base was redetermined on February 25, 2013, and our borrowing base was increased to $350.0 million. On April 24, 2013, the Company sold our wholly-owned subsidiary, Eagle Ford Hunter. As provided by an amendment to the MHR Senior Revolving Credit Facility, as a result of the sale, the borrowing base under the facility was adjusted down to $265.0 million. See "Note 20 - Subsequent Events" for additional information.

For the year ended December 31, 2012, we had net loss attributable to common shareholders of $167.4 million and an operating loss from continuing operations of $135.0 million, including $70.6 million related to unproved property impairments, a $43.8 million charge related to unproved leasehold abandonments, and $4.1 million impairment of proved oil and gas properties.

As of December 31, 2012, we were in compliance with all of our covenants, as amended or waived, contained in our credit agreements, as described in "Note 10 - Long-Term Debt".

We believe the combination of (i) cash on hand, (ii) cash flow generated from the expected success of prior capital development projects, (iii) borrowing capacity available under our credit agreements, (iv) liquidation of our shares of Penn Virginia stock (see "Note 20 - Subsequent Events"), and (v) proceeds from expected asset sales, provide sufficient means to conduct our operations, meet our contractual obligations, including our debt covenant requirements, as amended, and complete our budgeted capital expenditure program for the twelve months ending December 31, 2013.

Effect of Late SEC Filings on Liquidity and Capital Resources

We are no longer able to access the capital markets using short-form registration statements or “at-the-market” offerings as a result of this annual report not having been filed within, and our Form 10-Q for the quarter ended March 31, 2013 to be filed after, the time frames permitted by the SEC. See “Risk Factors - Our failure to timely file certain periodic reports with the SEC limits our access to the public markets to raise debt or equity capital.” Our ability to access the MHR Senior Revolving Credit Facility, and for Eureka Pipeline to access the Eureka Pipeline Revolver and the Eureka Pipeline Term Loan, could be curtailed or eliminated if (i) we fail to file such Form 10-Q by the lenders' extended deadline of July 12, 2013 or within any extended time period our lenders may in the future provide us or (ii) an uncured cross-default under such facilities results from any uncured “event of default” under the indenture relating to our Senior Notes stemming from our late SEC filings. See “Risk Factors - Our existing indenture defaults restrict our ability to utilize certain exceptions to the restrictive covenants contained therein and, under certain circumstances, may result in the acceleration of the Senior Notes issued under our indenture and the outstanding debt under our credit facilities, which would have a material adverse effect on our business, financial condition and liquidity.” These adverse impacts from our late SEC filings will be reduced, to some extent, by the net proceeds we received from the Eagle Ford Properties Sale and expected net proceeds in 2013 and 2014 from sales of non-core properties.

F-12

NOTE 3—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Principles of Consolidation and Presentation

The consolidated financial statements include the accounts of Magnum Hunter and our wholly-owned subsidiaries, Eagle Ford Hunter, Inc., Triad Hunter, LLC, Alpha Hunter Drilling, LLC, Hunter Real Estate, LLC, NGAS Hunter, LLC, Magnum Hunter Production, Inc., Magnum Hunter Resources GP, LLC, Magnum Hunter Resources LP, MHR Callco Corporation, MHR Exchangeco Corporation, Williston Hunter Canada, Inc., Williston Hunter, Inc., Williston Hunter ND, LLC, NGAS Gathering, LLC, Sentra Corporation, Energy Hunter Securities, Inc., Bakken Hunter, LLC, Viking International Resources Co., Inc. (“Virco”), Magnum Hunter Marketing, LLC, and Magnum Hunter Services, LLC. We have consolidated PRC Williston, LLC ("PRC Williston") and Eureka Hunter Holdings, LLC (“Eureka Hunter Holdings”) in which we own 87.5% and 61.0%, respectively, as of December 31, 2012. Eureka Hunter Holdings owns, directly or indirectly, 100% of the equity interests of Eureka Hunter Pipeline, LLC ("Eureka Hunter Pipeline"), TransTex Hunter, LLC and Eureka Hunter Land, LLC. The consolidated financial statements also reflect the interests of Magnum Hunter Production, Inc. in various managed drilling partnerships. We account for the interests in these partnerships using the proportionate consolidation method. All significant intercompany balances and transactions have been eliminated.

Our financial statements are prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP"). The preparation of our financial statements requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses. These estimates are based on information that is currently available to us and on various other assumptions that we believe to be reasonable under the circumstances. Actual results could differ from those estimates under different assumptions and conditions. Significant estimates are required for proved oil and gas reserves which may have a material impact on the carrying value of oil and gas property.

Reclassification of Prior-Year Balances

Certain prior-year balances in the consolidated financial statements have been reclassified to correspond with current-year classifications. As a result of the sale of Hunter Disposal, LLC, we reclassified the assets and liabilities of this entity to assets and liabilities held for sale and the gain on sale and all prior operating income and expense for this entity as discontinued operations.

Cash and cash equivalents

Cash and cash equivalents include cash in banks and highly liquid debt securities that have original maturities of three months or less. At December 31, 2012, the Company had cash deposits in excess of FDIC insured limits at various financial institutions.

Financial Instruments

The carrying amounts of financial instruments including cash and cash equivalents, accounts receivable, notes receivable, accounts payable and accrued liabilities, derivatives, and certain long-term debt approximate fair value as of December 31, 2012 and 2011. See "Note 4 – Fair Value of Financial Instruments".

Inventory

Inventories were comprised of $11.5 million and $4.3 million of materials and supplies as of December 31, 2012 and 2011, respectively. The Company’s materials and supplies inventory is primarily comprised of frac sand used in the completion process of hydraulic fracturing. Frac sand is acquired for use in future well completion operations or repair operations and is carried at the lower of cost or market, on a first-in, first-out cost basis. “Market,” in the context of inventory valuation, represents net realizable value, which is the amount that the Company is allowed to bill to the joint accounts under joint operating agreements to which the Company is a party. Valuation reserve allowances for materials and supplies inventories are recorded as reductions to the carrying values of the materials and supply inventories in the Company’s consolidated balance sheets and as operating expense in the accompanying consolidated statements of operations. As of December 31, 2012, the Company estimated that $3.5 million of its frac sand inventory would not be utilized within one year. Accordingly, those inventory values have been classified as derivatives and other long term assets in the accompanying consolidated balance sheet as of December 31, 2012.

Commodities inventories are carried at the lower of average cost or market, on a first-in, first-out basis. The Company’s commodities inventories consist of oil held in storage and gas pipeline fill volumes. Any valuation allowances of commodities inventories are recorded as reductions to the carrying values of the commodities inventories included in the Company’s consolidated balance sheets and as charges to lease operating expense in the consolidated statements of operations. The Company had $1.1 million and $207,000 in commodities inventory as of December 31, 2012 and December 31, 2011, respectively.

F-13

Oil and Gas Properties

Capitalized Costs

Our oil and gas properties comprised the following:

	December 31,
	2012			2011
	(in thousands)
Mineral interests in properties:
Unproved leasehold costs	$	645,164		$	424,610
Proved leasehold costs	529,538			218,654
Wells and related equipment and facilities	652,188			349,533
Uncompleted wells, equipment and facilities	71,665			27,741
Advances to operators for wells in progress	9,563			4,437
Total costs	1,908,118			1,024,975
Less accumulated depreciation, depletion, and amortization	(185,615		)	(62,010		)
Net capitalized costs	$	1,722,503		$	962,965

We follow the successful efforts method of accounting for our oil and gas producing activities. Costs to acquire mineral interests in oil and gas properties and to drill and equip new development wells and related asset retirement costs are capitalized. Costs to acquire mineral interests and drill exploratory wells are also capitalized pending determination of whether the wells have proved reserves or not. If we determine that the wells do not have proved reserves, the costs are expensed to exploration and abandonments. Geological and geophysical costs, including seismic studies and related costs of carrying and retaining unproved properties are charged to exploration expense as incurred. We capitalize interest on expenditures for significant capital asset projects that last more than six months while activities are in progress to bring the assets to their intended use. Interest of $4.4 million, all related to pipeline building projects at Eureka Hunter Pipeline, was capitalized during the year ended 2012. We did not capitalize any interest in 2011 or 2010. 

On the sale or retirement of a complete unit of a proved property, the cost and related accumulated depreciation, depletion, and amortization are eliminated from the property accounts, and the resultant gain or loss is recognized. On the retirement or sale of a partial unit of proved property, the cost is charged to accumulated depreciation, depletion, and amortization with no resulting gain or loss recognized in income. A sale of an entire field is treated as discontinued operations. In 2010, we sold our interest in our Cinco Terry property and reflected the gain on sale and current and prior operating results as discontinued operations. In 2012, we sold our interest in Hunter Disposal, LLC, and reflected the gain on sale and current and prior operating results as discontinued operations. See "Note 7 - Discontinued Operations".  

Leasehold costs attributable to proved oil and gas properties are depleted by the unit-of-production method over total proved reserves. Capitalized development costs are depleted by the unit-of-production method over producing proved reserves. Depreciation, depletion, and amortization expense for oil and gas producing property and related equipment was $123.3 million, $42.5 million, and $8.8 million for the years ended December 31, 2012, 2011, and 2010, respectively.

Unproved oil and gas leasehold costs that are individually significant are periodically assessed for impairment of value by comparing current quotes and recent acquisitions, and taking into account management's intent, and a loss is recognized at the time of impairment by providing an impairment allowance. We recorded $70.6 million in unproved property impairment during the year ended December 31, 2012, comprised of $62.2 million, $7.0 million, and $1.4 million in our Williston and Appalachian Basins and south Texas properties, respectively. There was no unproved property impairment for the years ended December 31, 2011 and 2010.

Capitalized costs related to proved oil and gas properties, including wells and related equipment and facilities, are evaluated for impairment quarterly based on an analysis of undiscounted future net cash flows. If undiscounted future net cash flows are insufficient to recover the net capitalized costs related to proved properties, then we recognize an impairment charge in income from operations equal to the difference between the net capitalized costs related to proved properties and their estimated fair values based on the present value of the related future net cash flows and other relevant market value data. Impairment of proved oil and gas properties is calculated on a field by field basis. An impairment is recorded when the estimated fair value of a field is determined to be less than the net capitalized cost of the field. We recorded $4.1 million in impairment charges for the year ended December 31, 2012, $3.9 million of which were related to the Williston Basin. We recorded $21.8 million in impairment charges to our proved properties held by Magnum Hunter Production, Inc., our wholly-owned subsidiary, for the year ended December 31, 2011, primarily due to a decline in natural gas prices. During the year ended December 31, 2010, we recorded $306,000 in impairment charges related to our Giddings Field proved property.

F-14

It is common for operators of oil and gas properties to request that joint interest owners pay for large expenditures, typically for drilling new wells, in advance of the work commencing. This right to call for cash advances is typically a provision of the joint operating agreement that working interest owners in a property adopt. We record these advance payments in Advances in our property account and reclassify amounts from this account when the actual expenditure is later billed to us by the operator.

If an unproved property is sold or the lease expires without identifying proved reserves, the cost of the property is charged to the impairment allowance. If a partial interest in an unproved property is sold, the amount received is treated as a reduction of the cost of the interest retained.

Estimates of Proved Oil and Gas Reserves

Estimates of our proved reserves included in this report are prepared in accordance with U.S. SEC guidelines for reporting corporate reserves and future net revenue. The accuracy of a reserve estimate is a function of: 

·      the quality and quantity of available data; 

·      the interpretation of that data; 

·      the accuracy of various mandated economic assumptions; and 

·      the judgment of the persons preparing the estimate.

Our proved reserve information included in this report was predominately based on evaluations reviewed by independent third party petroleum engineers. Estimates prepared by other third parties may be higher or lower than those included herein. Because these estimates depend on many assumptions, all of which may substantially differ from future actual results, reserve estimates will be different from the quantities of oil and gas that are ultimately recovered. In addition, results of drilling, testing and production after the date of an estimate may justify material revisions to the estimate. 

In accordance with SEC requirements, we based the estimated discounted future net cash flows from proved reserves on the unweighted arithmetic average of the  prior 12-month commodity prices as of the first day of each of the months constituting the period and costs on the date of the estimate.

The estimates of proved reserves materially impact DD&A expense. If the estimates of proved reserves decline, the rate at which we record depreciation and depletion expense will increase, reducing future net income. Such a decline may result from lower market prices, which may make it uneconomic to drill for and produce from higher-cost fields. 

Oil and Gas Operations

Revenue Recognition

Revenues associated with sales of crude oil, natural gas, and natural gas liquids are recognized when title passes to the customer, which is when the risk of ownership passes to the purchaser and physical delivery of goods occurs, either immediately or within a fixed delivery schedule that is reasonable and customary in the industry.

Revenues from the production of natural gas and crude oil from properties in which we have an interest with other producers are recognized based on the actual volumes sold during the period. Any differences between volumes sold and entitlement volumes, based on our net working interest, which are deemed to be non-recoverable through remaining production, are recognized as accounts receivable or accounts payable, as appropriate. Cumulative differences between volumes sold and entitlement volumes are generally not significant.

Revenues from field servicing activities are recognized at the time the services are provided and earned as provided in the various contract agreements. Gas gathering revenues are recognized at the time the natural gas is delivered at the destination point.

Accounts Receivable

We recognize revenue for our production when the quantities are delivered to or collected by the respective purchaser. Prices for such production are defined in sales contracts and are readily determinable or estimable based on available data.

Accounts receivable from joint interest owners consist of joint interest owner obligations due within 30 days of the invoice date. Accounts receivable, oil and gas sales, consist of accrued revenues due under normal trade terms, generally requiring payment within 30 to 60 days of production. We review accounts receivable periodically and reduce the carrying amount by a valuation allowance that reflects our best estimate of the amount that may not be collectible. As of December 31, 2012 and 2011, the Company had allowance for doubtful accounts of $448 thousand and $286 thousand respectively.

Accounts Payable

Our accounts payable consisted of trade payables of $196.5 million and $138.3 million as of December 31, 2012 and 2011, respectively.

F-15

Revenue Payable

Revenue payable represents amounts collected from purchasers for oil and gas sales which are either revenues due to other working or royalty interest owners or severance taxes due to the respective state or local tax authorities. Generally, we are required to remit amounts due under these liabilities within 30 days of the end of the month in which the related production occurred.

Lease Operating Expenses

Lease operating expenses, including compressor rental and repair, pumpers’ salaries, saltwater disposal, ad valorem taxes, insurance, repairs and maintenance, workovers and other operating expenses are expensed as incurred. Transportation, gathering, and processing costs are expensed as incurred and included in lease operating expenses.

Exploration and Abandonment Costs

Exploration expenses include dry hole costs, delay rentals, and geological and geophysical costs. Abandonment costs are charges to leasehold costs associated with acreage that we chose not to develop and impair such costs or allow leases to expire, which ever occurs first. The Company did not drill any dry holes in 2012, 2011, or 2010. The following table provides the Company's geological and geophysical costs and leasehold abandonments and impairment expense from continuing operations for 2012, 2011 and 2010:

	Year Ended December 31,
	2012		2011		2010
	(In thousands)
Geological and geophysical	$	2,860	$	1,537	$	942
Leasehold abandonment	43,800		1,108		—
Leasehold impairments	70,556		—		—
	$	117,216	$	2,645	$	942

During 2012, the Company's exploration and abandonment expense was primarily attributable to $70.6 million in leasehold impairments and $43.8 million in leasehold abandonment expense, which included $33.6 million and $10.2 million associated with the Company's unproved properties in the Williston Basin and Appalachian Basin, respectively. The impairment is primarily due to the large acreage position we initially acquired and results to date in the area, which led us to focus on other areas, thereby letting certain acreage expire in that region. The significant components of the Company's 2011 leasehold abandonment expense included unproved acreage abandonments of $802,000 and $306,000 in the Appalachian Basin and Eagle Ford Shale areas, respectively, and $1.5 million of exploration costs.

During the quarter ended March 31, 2013, the Company recognized an additional $4.7 million lease abandonment expense related to leases that expired on approximately 700 acres in the Williston Basin region that we planned to renew as of December 31, 2012, but failed to renew as a result of logistical difficulties.

Severance Taxes and Marketing Costs

Severance taxes are comprised of production taxes charged by most states on oil, natural gas, and natural gas liquids produced. These taxes are computed on the basis of volumes and/or value of production or sales. These taxes are usually levied at the time and place the minerals are severed from the producing reservoir. Marketing costs are those directly associated with marketing our production and are based on volumes.

Gas Gathering and Processing Costs

Gas gathering and processing costs are those costs associated with oil and gas gathering revenues of our midstream operations.

Dependence on Major Customers

The Company's share of oil and gas production is sold to various purchasers who must be prequalified under the Company's credit risk policies and procedures. The Company records allowances for doubtful accounts based on the age of accounts receivables and the financial condition of its purchasers and, depending on facts and circumstances, may require purchasers to provide collateral or otherwise secure their accounts. The loss of any one significant purchaser could have a material, adverse effect on the ability of the Company to sell its oil and gas production in a certain region. Although we are exposed to a concentration of credit risk, we believe that all of our purchasers are credit worthy. See "Note 15 - Major Customers" for more information.

Dependence on Suppliers

Our industry is cyclical, and from time to time there is a shortage of drilling rigs, fracture stimulation services, equipment, related supplies and qualified personnel. During these periods, the costs and delivery times of rigs, equipment and supplies are substantially greater. If the unavailability or high cost of drilling rigs, equipment, supplies or qualified personnel were particularly severe in the areas where we operate, we could be materially and adversely affected. We believe that there are potential alternative providers of

F-16

drilling services and that it may be necessary to establish relationships with new contractors as our activity level increases and capital program grows. However, there can be no assurance that we can establish such relationships and that those relationships will result in increased availability of drilling rigs.

Gas Gathering, Processing and Other Equipment

Our gas gathering system assets and field servicing assets are carried at cost. We capitalize interest on expenditures for significant construction projects that last more than six months while activities are in progress to bring the assets to their intended use. Interest of $4.4 million was capitalized on our Eureka Hunter Gas Gathering System during the year ended 2012, and no interest was capitalized in 2011 or 2010. Depreciation of gas gathering system assets is provided using the straight line method over an estimated useful life of fifteen years. Depreciation of field servicing assets is provided using the straight line method over various useful lives ranging from three to ten years. Gain or loss on retirement or sale or other disposition of assets is included in income in the period of disposition.

Furniture, fixtures and equipment are carried at cost. Depreciation of furniture, fixtures and equipment is provided using the straight-line method over estimated useful lives ranging from five to fifteen years. Gain or loss on retirement or sale or other disposition of assets is included in other income in the period of disposition.

	December 31,
	2012			2011
	(In thousands)
Gas gathering, processing and other equipment	$	218,656		$	121,030
Less accumulated depreciation and depletion	(16,746		)	(8,861		)
Net capitalized costs	$	201,910		$	112,169

Depreciation expense for other property and equipment was $7.9 million, $8.9 million, and $86,931, for the years ended December 31, 2012, 2011, and 2010, respectively.

TransTex Hunter sells and leases gas treating and processing equipment, much of which is leased to third party operators for treating gas at the wellhead. The leases generally have a term of three years or less. The equipment under leases in place as of December 31, 2012 had terms for future payments extending as far as December 2014. TransTex Hunter has non-cancelable leases to third parties in place as of December 31, 2012, with future minimum base rentals of $3.9 million and $1.6 million for the years ending December 31, 2013 and 2014, respectively. Equipment leasing revenue is reported in gas transportation, gathering, and processing revenue in our statement of operations.

Deferred Financing Costs

In connection with debt financings, we paid $20.3 million and $11.6 million in fees in the year ended December 31, 2012, and 2011, respectively. These fees were recorded as deferred financing costs and are being amortized over the life of the debt instrument using the straight line method for debt in the form of a line of credit and effective interest method for term loans. Amortization and write off of deferred financing costs for the years ended December 31, 2012, 2011, and 2010 was $7.1 million, $3.6 million, and $1.2 million, respectively.

Commodity and Financial Derivative Instruments

We use commodity and financial derivative instruments, typically options and swaps, to manage the risk associated with fluctuations in oil and gas prices, and we account for these instruments in accordance with ASC 815 - Derivatives and Hedging. We also have an embedded derivative liability resulting from certain conversion features, redemption options, and other features of our Series A Convertible Preferred Units of Eureka Hunter Holdings, LLC and an embedded derivative asset resulting from the bifurcated conversion feature associated with the convertible note received as partial consideration upon the sale of Hunter Disposal, LLC. See "Note 4 – Fair Value of Financial Instruments", "Note 7 – Discontinued Operations", "Note 12 — Shareholders’ Equity", and "Note 17 – Related Party Transactions", for additional information.

Derivative instruments are recorded at fair value in the balance sheet as either an asset or liability, with those contracts maturing in the next twelve months classified as current, and those maturing thereafter as long-term. We recognize changes in the derivatives' fair values in earnings, as we have not designated our oil and gas price derivative contracts as cash flow hedges. We recognize the realized and unrealized gains and losses on a net basis within the “Gain (loss) on derivative contracts” line item within the “Other Income (expense)” section of the Consolidated Statement of Operations. Additionally, we separately disclose the “Realized gain (loss)” and “Unrealized gain (loss)” within the "Notes to the Consolidated Financial Statements" in accordance with ASC 815.

F-17

Investments

Investments are comprised of common and preferred stock of companies publicly traded on the TSX Venture Exchange and the NYSE MKT (formerly NYSE Amex) with quoted prices in active markets. On February 17, 2012, the Company received 1,846,722 restricted common shares of GreenHunter Resources, Inc., with a discounted carrying value of $1.3 million at December 31, 2012, and 88,000 shares of GreenHunter Resources, Inc. 10% Series C Preferred Stock, with a discounted fair value of $1.7 million at December 31, 2012, as partial consideration for the sale by our wholly-owned subsidiary, Triad Hunter, LLC, of its equity ownership interest in Hunter Disposal, LLC to GreenHunter Resources, Inc. The GreenHunter common stock investment is accounted for under the equity method within the scope of ASC 323: Investments - Equity Method. The Company initially accounted for its investment in GreenHunter’s Series C Preferred Stock under the cost method specified in ASC 325: Investments - Other. The preferred shares were cost basis investments from February 17, 2012 through July 31, 2012, since the preferred stock was not publicly traded and did not have a readily determinable fair value, and therefore ineligible for accounting under ASC 320: Investments - Debt and Equity Securities.

Beginning July 31, 2012, the GreenHunter Series C Preferred Stock is publicly traded with a readily determinable fair value and is classified as available for sale within the scope of ASC 320. Available-for-sale assets are included in Investments on our balance sheet and represent securities and other financial investments that are neither held for trading, nor held to maturity, nor held for strategic reasons, and that have a readily available market price. As such, the gains and losses resulting from marking available-for-sale investments to market are not included in net income but are reflected in other comprehensive income until they are realized.

Below is a summary of changes in investments for the years ended December 31, 2012 and 2011:

	Available for Sale Securities			Equity Method Investments			Cost Method Investments
	(in thousands)
Fair value at January 1, 2011	$	—		$	—		$	—
Acquisition of available for sale securities	483			—			—
Change in fair value recognized in other comprehensive income	14			—			—
Fair value at December 31, 2011	497			—			—
Additional cost basis from acquisition	—			3,943			1,870
Transfers	1,770			—			(1,770		)
Decrease in carrying amount return of capital	—			—			(100		)
Equity in net loss recognized in other income (expense)	—			(1,333		)	—
Impairment in carrying value of equity method investment recognized in other income (expense)	—			(538		)	—
Change in fair value recognized in other comprehensive loss	(309		)	—			—
Fair value as of December 31, 2012	$	1,958		$	2,072		$	—

On April 24, 2013, the Company received 10.0 million shares of common stock of Penn Virginia Corporation valued at approximately $42.3 million (as of June 1, 2013) as partial consideration for the sale of our wholly-owned subsidiary, Eagle Ford Hunter. The Company plans to sell some or all of these shares opportunistically depending upon market conditions. See "Note 20 - Subsequent Events" for additional information.

Goodwill and Other Intangible Assets

During 2012, the Company recorded goodwill associated with the acquisition of the assets of TransTex Gas Services, LP, which represents the fair value of the acquired entity over the net amounts assigned to assets acquired and liabilities assumed. In accordance with GAAP, goodwill is not amortized to earnings, but is assessed annually in April for impairment, or whenever events or circumstances indicate that impairment of the carrying value of goodwill is likely. The Company has established April 1 as the annual testing date. If the carrying value of goodwill is determined to be impaired, it is reduced to its implied fair value with a corresponding charge to pretax earnings in the period in which it is determined to be impaired. Financial Accounting Standards Board ("FASB") Accounting Standards Update No. 2011-08, Intangibles - Goodwill and Other (Topic 350) permits an entity to first assess qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount as a basis for determining whether it is necessary to perform the two-step goodwill impairment test. The Company performed an interim evaluation of any triggering events, and none were determined to exist.

Intangible assets consist primarily of the fair value of the acquired gas treating agreements and customer relationships in the TransTex Gas Services, LP assets acquisition.  The intangible assets were valued at fair value using a discounted cash flow model with a discount rate of 13%.  Such assets will be amortized over the weighted average term of 8.5 years.  The customer relationships are being amortized with a 12.5 year life. Amortizable intangible assets are required to be evaluated at least annually for impairment. If

F-18

the carrying value of an individual amortizable intangible asset exceeds its fair value as determined by its discounted cash flows, such individual amortizable intangible asset is written down by the amount of the excess. Other intangible assets are evaluated for impairment when events or changes in circumstances indicate the carrying value may not be recoverable. At December 31, 2012, our other intangible assets were not impaired.

Assets Held for Sale

The Company agreed to exchange a drilling rig owned by Alpha Hunter Drilling, a subsidiary of Triad Hunter, LLC, as partial consideration toward the purchase of a new drilling rig. The trade in value of the rig is $500,000 and has been reclassified to assets held for sale as of December 31, 2012, and the remaining book value of the rig of $156,000 was written off as an expense.

As a result of the sale of Hunter Disposal, LLC, we reclassified the assets and liabilities of this entity to "Assets and Liabilities Held for Sale" and the gain on sale and all prior operating income and expense for this entity as discontinued operations.

Asset Retirement Obligation

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

Our liability is determined using significant assumptions, including current estimates of plugging and abandonment costs, annual inflation of these costs, the productive lives of wells and our risk-adjusted interest rate. Changes in any of these assumptions can result in significant revisions to the estimated asset retirement obligation. Our liability for current and long term asset retirement obligations were approximately $2.4 million and $28.3 million, respectively, at December 31, 2012, and $495,000 and $20.1 million , respectively, at December 31, 2011. The liability for current asset retirement obligations is reported in other current liabilities. See "Note 9—Asset Retirement Obligations" to our consolidated financial statements for more information.

Share-Based Compensation

The Company estimates the fair value of share-based payment awards made to employees and directors, including stock options, restricted stock and matching contributions of stock to employees under our employee stock ownership plan, on the date of grant using an option-pricing model. The value of the portion of the award that is ultimately expected to vest is recognized as an expense ratably over the requisite service periods. Awards that vest only upon achievement of performance criteria are recorded only when achievement of the performance criteria is considered probable. We estimate the fair value of each share-based award using the Black-Scholes option pricing model or a lattice model. These models are highly complex and dependent on key estimates by management. The estimates with the greatest degree of subjective judgment are the estimated lives of the stock-based awards, the estimated volatility of our stock price, and the assessment of whether the achievement of performance criteria is probable.

Income Taxes

Income taxes are accounted for in accordance with FASB ASC 740, under which deferred income taxes are recognized for the future tax effects of temporary differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities using the enacted statutory tax rates in effect at year-end. The effect on deferred taxes for a change in tax rates is recognized in earnings in the period that includes the enactment date. A valuation allowance for deferred tax assets is recorded when it is more likely than not that the benefit from the deferred tax asset will not be realized.

Uncertain Income Tax Positions

Under accounting standards for uncertainty in income taxes (ASC 740-10), a company recognizes a tax benefit in the financial statements for an uncertain tax position only if management's assessment is that the position is “more likely than not” (i.e., a likelihood greater than 50 percent) to be allowed by the tax jurisdiction based solely on the technical merits of the position. The term “tax position” in the accounting standards for income taxes refers to a position in a previously filed tax return or a position expected to be taken in a future tax return that is reflected in measuring current or deferred income tax assets and liabilities for interim or annual periods. We had no uncertain tax positions at December 31, 2012 or 2011.

Loss per Common Share

Basic net income or loss per common share is computed by dividing the net income or loss attributable to common shareholders by the weighted average number of shares of common stock outstanding during the period. Diluted net income or loss per common share is calculated in the same manner, but also considers the impact to net income and common shares for the potential dilution from stock options, stock warrants and any outstanding convertible securities.

We have issued potentially dilutive instruments in the form of our restricted common stock granted and not yet issued, common stock warrants, common stock options granted to our employees and directors, and our Series E Cumulative Convertible Preferred

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Stock. We did not include any of these instruments in our calculation of diluted loss per share during the period because to include them would be anti-dilutive due to our loss from continuing operations during the periods.

The following table summarizes the types of potentially dilutive securities outstanding as of December 31, 2012, 2011 and 2010:

	December 31,
	2012	2011	2010
	(in thousands)
Series E Preferred Stock	11,103	—	—
Warrants	13,376	13,526	963
Restricted shares granted, not yet issued	—	38	118
Common stock options	14,710	12,566	12,781
Total	39,189	26,130	13,862

Recently Issued Accounting Pronouncements

None.

Regulated Activities

Energy Hunter Securities, Inc. is a wholly-owned subsidiary and is a registered broker-dealer and member of the Financial Industry Regulatory Authority. Among other regulatory requirements, it is subject to the net capital provisions of Rule 15c3-1 under the Securities Exchange Act of 1934, as amended. Because it does not hold customer funds or securities or owe money or securities to customers, Energy Hunter Securities, Inc. is required to maintain minimum net capital equal to the greater of $5,000 or 6.67% of its aggregate indebtedness. At December 31, 2012 and 2011, Energy Hunter Securities, Inc. had net capital of $61,074 and $49,000, respectively, and aggregate indebtedness of $38,926 and $132,000, respectively.

Sentra Corporation owns and operates distribution systems for retail sales of natural gas in south central Kentucky. Sentra Corporation’s gas distribution billing rates are regulated by Kentucky’s Public Service Commission based on recovery of purchased gas costs. We account for its operations based on the provisions of ASC 980-605, Regulated Operations–Revenue Recognition, which requires covered entities to record regulatory assets and liabilities resulting from actions of regulators. For the years ended December 31, 2012, 2011, and 2010, we had gas transmission, compression and processing revenue, reported in other revenue, which included gas utility sales from Sentra Corporation’s regulated operations aggregating $511,000, $61,000, and $0, respectively.

Other Comprehensive Income (Loss)

The functional currency of our operations in Canada, the only country in addition to the United States in which we operate, is the Canadian dollar. For purposes of consolidation, we translate the assets and liabilities of our Canadian subsidiary into U.S. dollars at current exchange rates while revenues and expenses are translated at the average rates in effect for the period. The related translation gains and losses are included in accumulated other comprehensive income within shareholders’ equity on our consolidated balance sheets. During the year ended December 31, 2012, 2011, and 2010 we recognized a translation gain of $3.9 million and a loss of $12.5 million, and zero, respectively. As the Company considers undistributed earnings in Canada to be indefinitely reinvested in Canada, there is no tax effect of the translation gain.

NOTE 4 - FAIR VALUE OF FINANCIAL INSTRUMENTS

Accounting standards define fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The standards also establish a framework for measuring fair value and a valuation hierarchy based upon the transparency of inputs used in the valuation of an asset or liability.  Classification within the hierarchy is based upon the lowest level of input that is significant to the fair value measurement.  The valuation hierarchy contains three levels:

● Level 1 — Quoted prices (unadjusted) for identical assets or liabilities in active markets;

● Level 2 — Quoted prices for similar assets or liabilities in active markets; quoted prices for identical or similar assets or liabilities in markets that are not active; and model-derived valuations whose inputs or significant value drivers are observable;

● Level 3 — Significant inputs to the valuation model are unobservable.

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We used the following fair value measurements for certain of our assets and liabilities during the years ended December 31, 2012 and 2011: 

Level 1 Classification:

Available for Sale Securities

At December 31, 2012, the Company held common and preferred stock of companies publicly traded on the TSX Venture Exchange and the NYSE MKT (formerly NYSE Amex) with quoted prices in active markets. Accordingly, the fair market value measurements of these securities have been classified as Level 1.

Level 2 Classification:

Derivative Instruments

At December 31, 2012 and December 31, 2011, the Company had commodity derivative financial instruments in place.  The Company does not designate its derivative instruments as hedges and therefore does not apply hedge accounting.  Changes in fair value of derivative instruments subsequent to the initial measurement are recorded as other income (expense).  The estimated fair values of the Company’s derivative instruments have been determined at discrete points in time based on relevant market information which resulted in the Company classifying such derivatives as Level 2.  Although the Company’s derivative instruments are valued using public indices, the instruments themselves are traded with unrelated counterparties and are not openly traded on an exchange.  See "Note 5—Financial Instruments and Derivatives", for additional information. 

As of December 31, 2012 and December 31, 2011, the Company’s derivative contracts were with financial institutions, all of which were either senior lenders to the Company or affiliates of such senior lenders, and some of which had investment grade credit ratings. All of such counterparties are believed to have minimal credit risk.  Although the Company is exposed to credit risk to the extent of nonperformance by the counterparties to the derivative contracts discussed above, the Company does not anticipate such nonperformance and monitors the credit worthiness of its counterparties on an ongoing basis.

Level 3 Classification: 

Preferred Stock Embedded Derivative 

At December 31, 2012, the Company had preferred stock derivative liabilities resulting from certain conversion features, redemption options, and other features of our Series A Convertible Preferred Units of Eureka Hunter Holdings, LLC. See "Note 13 — Redeemable Preferred Stock", for more information. 

The preferred stock embedded derivative was valued using the “with and without” analysis in a simulation model. The key inputs used in the model were a volatility of 22.3%, credit spread of 14.64%, and an estimated enterprise value of Eureka Hunter Holdings of $483.8 million. 

Convertible Security Embedded Derivative

The Company recognized an embedded derivative asset resulting from the fair value of the bifurcated conversion feature associated with the convertible note received as partial consideration upon the sale of Hunter Disposal, LLC (See "Note 7 - Discontinued Operations") to GreenHunter Resources.  The convertible security embedded derivative was valued using a Black-Scholes model valuation of the conversion option.

The key inputs used in the Black-Scholes option pricing model were as follows:

	December 31, 2012
Life	4.1		years
Risk-free interest rate	0.67		%
Estimated volatility	40		%
Dividend	—
GreenHunter Resources Stock price at end of period	$	1.61

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The following table presents the changes in the fair value of the derivative assets and liabilities measured at fair value using significant unobservable inputs for the year ended December 31, 2012:

	Embedded Derivatives
	Preferred  Stock			Convertible Security
	(in thousands)
Fair value at December 31, 2011	$	—		$	—
Issued or acquired embedded derivative asset (liability)	(52,240		)	405
Change in fair value recognized in other income (expense)	8,692			(141		)
Fair value as of December 31, 2012	$	(43,548	)	$	264

The following tables present financial assets and liabilities which are adjusted to fair value on a recurring basis at December 31, 2012 and 2011:

	Fair Value Measurements on a Recurring Basis
	December 31, 2012
	(in thousands)
	Level 1		Level 2		Level 3
Available for sale securities	$	1,958	$	—	$	—
Derivative assets	—		4,882		264
Total assets at fair value	$	1,958	$	4,882	$	264
Derivative liabilities	$	—	$	7,477	$	43,548
Total liabilities at fair value	$	—	$	7,477	$	43,548

	Fair Value Measurements on a Recurring Basis
	December 31, 2011
	(in thousands)
	Level 1		Level 2		Level 3
Available for sale securities	$	497	$	—	$	—
Derivative assets	—		6,924		—
Total assets at fair value	$	497	$	6,924	$	—
Derivative liabilities	$	—	$	11,912	$	—
Total liabilities at fair value	$	—	$	11,912	$	—

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The Company uses available market data and valuation methodologies to estimate the fair value of debt.  The carrying amounts and fair values of long-term debt are as follows:

	Fair Value	December 31, 2012				December 31, 2011
	Hierarchy Level	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Senior Notes (1)	2	$	597,212	$	613,500	$	—	$	—
MHR Senior Revolving Credit Facility (2)	1	225,000		225,000		142,000		142,000
Eureka Hunter Pipeline, LLC second lien term loan (3)	3	50,000		58,550		31,000		34,407
Magnum Hunter second lien term loan (2)	1	—		—		100,000		100,000
Equipment note payable (3) (4)	3	9,785		8,687		6,158		5,350

^1.  The fair value of our Senior Notes is based on quoted market prices. 

^2.  The carrying value of each of the MHR Senior Revolving Credit Facility and Magnum Hunter's second lien term loan approximates fair value as it is subject to short-term floating interest rates that approximate the rates available to us at these dates. 

^3.  The fair value of (a) Eureka Hunter Pipeline’s second lien term loan and (b) equipment note payable, is the estimated cost to acquire the debt, including a credit spread for the difference between the issue rate and the period end market rate.  The credit spread is Eureka Hunter Pipeline’s default or repayment risk.  The credit spread (premium or discount) is determined by comparing fixed-rate notes and credit facility to new issuances (secured and unsecured) and secondary trades of similar size and credit statistics for both public and private debt. 

^4.  The Company has various inconsequential equipment notes outstanding at December 31, 2012 and 2011 which carrying values approximate fair values and have been excluded from the table above.

Fair Value on a Non-Recurring Basis

The Company follows the provisions of ASC 820-10 for nonfinancial assets and liabilities measured at fair value on a non-recurring basis. As it relates to Magnum Hunter, ASC 820-10 applies to certain nonfinancial assets and liabilities as may be acquired in a business combination and thereby measured at fair value; measurements of oil and natural gas property impairments; and the initial recognition of asset retirement obligations, for which fair value is used. These asset retirement obligation ("ARO") estimates are derived from historical costs as well as management's expectation of future cost environments. As there is no corroborating market activity to support the assumptions used, Magnum Hunter has designated these measurements as Level 3.

A reconciliation of the beginning and ending balances of Magnum Hunter's asset retirement obligation is presented in "Note 9 - Asset Retirement Obligation".

New fair value measurements of proved oil and natural gas properties during the year ended December 31, 2011 and 2012 consist of:

Fair Value Measurements on a Non-recurring Basis
	(Level 1)		(Level 2)		(Level 3)
	(In thousands)
Proved properties impaired (1)	$	—	$	—	$	2,710
Acquisitions (2)	—		—		602,661
Total during 2011	$	—	$	—	$	605,371
Proved properties impaired (1)	$	—	$	—	$	58,082
Acquisitions (2)	—		—		532,150
Total during 2012	$	—	$	—	$	590,232

⁽¹⁾ The Company recorded impairment charges of $4.1 million and $21.8 million during the years ended December 31, 2012 and 2011, respectively, as a result of writing down the carrying value of certain properties to fair value. In order to determine fair value, Magnum Hunter compares net capitalized costs of proved oil and natural gas properties to estimated undiscounted future net cash flows using management's expectations of economically recoverable reserves. If the net capitalized cost exceeds the undiscounted future net cash flows, Magnum Hunter impairs the net cost basis down to the discounted future net cash flows, which is management's

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estimate of fair value. Significant inputs used to determine the fair value include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital rate. The underlying commodity prices embedded in the Company's estimated cash flows are the product of a process that begins with NYMEX forward curve pricing, adjusted for estimated location and quality differentials, as well as other factors that Magnum Hunter's management believes will impact realizable prices. The inputs used by management for the fair value measurements utilized in this review include significant unobservable inputs, and therefore, the fair value measurements employed are classified as Level 3 for these types of assets.

⁽²⁾Magnum Hunter records the fair value of assets and liabilities acquired in business combinations. During the year ended December 31, 2011, Magnum Hunter acquired oil and natural gas properties with a fair value of $602.7 million. During the year ended December 31, 2012, Magnum Hunter acquired oil and natural gas properties with a fair value of $532.2 million. Properties acquired are recorded at fair value, which correlates to the discounted future net cash flow. Significant inputs used to determine the fair value of proved properties include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital rate. The underlying commodity prices embedded in the Company's estimated cash flows are the product of a process that begins with NYMEX forward curve pricing, adjusted for estimated location and quality differentials, as well as other factors that Magnum Hunter's management believes will impact realizable prices. For acquired unproved properties, the market-based weighted average cost of capital rate is subjected to additional project specific risking factors. The inputs used by management for the fair value measurements of these acquired oil and natural gas properties include significant unobservable inputs, and therefore, the fair value measurements employed are classified as Level 3 for these types of assets.

NOTE 5 - FINANCIAL INSTRUMENTS AND DERIVATIVES

We periodically enter into certain commodity derivative instruments such as futures contracts, swaps, collars, and basis swap contracts , which are effective in mitigating commodity price risk associated with a portion of our future monthly natural gas and crude oil production and related cash flows. We have not designated any of our commodity derivatives as hedges under ASC 815. When actual commodity prices exceed the fixed price provided by these contracts, we pay this excess to the counterparty, and when actual commodity prices are below the contractually provided fixed prices, we receive the difference from the counterparty.

In a commodities swap agreement, the Company trades the fluctuating market prices of oil or natural gas at specific delivery points over a specified period, for fixed prices. As a producer of oil and natural gas, the Company holds these commodity derivatives to protect the operating revenues and cash flows related to a portion of our future natural gas and crude oil sales from the risk of significant declines in commodity prices, which helps insure our ability to fund our capital budget.  If the price of a commodity rises above what we have agreed to receive in the swap agreement, the amount that we agree to pay the counterparty would theoretically be offset by the increased amount we received for our production.

The Company also enters into three-way collars with third parties. These instruments typically establish two floors and one ceiling. Upon settlement, if the index price is below the lowest floor, the Company receives the difference between the two floors. If the index price is between the two floors, the Company receives the difference between the higher of the two floors and the index price. If the index price is between the higher floor and the ceiling, the Company does not receive or pay any amounts. If the index price is above the ceiling, the Company pays the excess over the ceiling price. The advantage to the Company of the three-way collar is that the proceeds from the second floor allow us to lower the total cost of the collar.

Our failure to service any of our debt or to comply with any of our debt covenants (including failures stemming from our late SEC filings) could result in a default under the related debt agreement, and under any commodity derivative contract under which such debt default is a cross-default, which could result in the early termination of the commodity derivative contract (and an early termination payment obligation) and/or otherwise materially adversely affect our business, financial condition and results of operations.

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The table below is a summary of our commodity derivatives as of December 31, 2012:

			Weighted Avg
Natural Gas	Period	MMBTU/day	Price per MMBTU
Collars	Jan 2013 - Dec 2013	12,500	$4.50 - $5.96(1)
Swaps	Jan 2013 - Dec 2013	15,500	$3.52
Ceilings sold (call)	Jan 2014 - Dec 2014	16,000	$5.91
			Weighted Avg
Crude Oil	Period	Bbls/day	Price per Bbl
Collars	Jan 2013 - Dec 2013	2,763	$81.38 - $97.61
Three-way collar (2)	Jan 2014 - Dec 2014	663	$65.00 - $85.00 - $91.25
Three-way collar (2)	Jan 2015 - Dec 2015	259	$70.00 - $85.00 - $91.25
Three-way collar (2)	Jan 2013 - Dec 2013	2,000	$60.63 - $80.00 - $100.00
Three-way collar (2)	Jan 2014 - Dec 2014	4,000	$64.94 - $85.00 - $102.50
Three-way collar (3)	Jan 2013 - Dec 2013	763	$65.00 - $91.25 - $101.25
Swaps	Jan 2013 - Dec 2013	1,000	$91.46
Floors sold (put)	Jan 2013 - Dec 2013	1,438	$65.00
(1)  Weighted averages prices for sold put and sold call, respectively.
(2)  These three-way collars are a combination of three options: a sold put, a purchased put, and a sold call.
(3)  This three-way collar is a combination of three options: a sold put, a purchased call, and a sold call.

Currently, Bank of Montreal, KeyBank National Association, Credit Suisse Energy, LLC, UBS AG London Branch, Deutsche Bank AG London Branch, Citibank, N.A., J. Aron & Company, an affiliate of Goldman Sachs, are the only counterparties to our commodity derivatives positions.  We are exposed to credit losses in the event of nonperformance by the counterparties on our commodity derivatives positions.  However, we do not anticipate nonperformance by the counterparties over the term of the commodity derivatives positions.  All counterparties or their affiliates are participants in our senior revolving credit facility, and the collateral for the outstanding borrowings under our senior revolving credit facility is used as collateral for our commodity derivatives with those counterparties.

At December 31, 2012, the Company has preferred stock derivative liabilities resulting from certain conversion features, redemption options, and other features of our Series A Convertible Preferred Units of Eureka Hunter Holdings, LLC. See "Note 4 – Fair Value of Financial Instruments" and "Note 12 — Shareholders’ Equity", for more information. 

At December 31, 2012, the Company also has a convertible security embedded derivative asset primarily due to the conversion feature of the promissory note receivable from GreenHunter Resources, Inc. received as partial consideration for the sale of Hunter Disposal, LLC. See "Note 4 – Fair value of Financial Instruments", "Note 7 – Discontinued Operations" and "Note 17 – Related Party Transactions", for additional information.

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The following table summarizes the fair value of our derivative contracts as of the dates indicated:

	Derivatives not designated as hedging instruments
	Gross Derivative Assets				Gross Derivative Liabilities
	December 31,				December 31,
	2012		2011		2012			2011
Commodity	(In thousands)
Derivative assets - current	$	4,882	$	5,732	$	—		$	—
Derivatives and other long term assets	—		1,192		—			—
Derivative and other current liabilities	—		—		(3,501		)	(5,800		)
Derivative liabilities - long term	—		—		(3,976		)	(6,112		)
Total commodity	$	4,882	$	6,924	$	(7,477	)	$	(11,912	)
Financial
Derivative assets - current	$	264	$	—	$	—		$	—
Derivative liabilities - long term	—		—		(43,548		)	—
Total financial	$	264	$	—	$	(43,548	)	$	—

The following table summarizes the net gain (loss) on all derivative contracts included in other income (expense) on the consolidated statements of operations for the years ended December 31, 2012, 2011 and 2010:

	For the Year Ended December 31,
	2012		2011			2010
	(in thousands)
Realized gain (loss)	$	11,294	$	(2,136	)	$	3,877
Unrealized gain (loss)	10,945		(4,210		)	(3,063		)
Net gain (loss) on derivative contracts	$	22,239	$	(6,346	)	$	814

NOTE 6 – ACQUISITIONS

The Company has recognized $4.7 million, $8.9 million, and $2.2 million of transaction expenses related to acquisitions in its general and administrative expenses for the years ended December 31, 2012, 2011, and 2010, respectively. Substantially all of our acquisitions contained a significant amount of unproved acreage, as is consistent with the Company's business strategy.

Wetzel County, West Virginia Asset Acquisition

On April 7, 2011, the Company purchased oil and gas properties and related assets from a third party, located in Wetzel County, West Virginia. The assets purchased included oil and gas leases and mineral interests and existing wells with proven reserves. The primary purpose of the acquisition was to acquire leasehold acreage and wells complementary to our existing acreage and expand our position in the Marcellus Shale in West Virginia. We acquired the assets for a total purchase price of $20.0 million, payable in cash and subject to customary purchase price adjustments. Subject to the indemnification obligations set forth in the purchase agreement, we assumed certain customary liabilities in connection with the acquisition.

NGAS Acquisition

On April 13, 2011, the Company completed the acquisition of all of the outstanding common shares of NGAS Resources, Inc. (“NGAS”) for total consideration of approximately $124.5 million consisting of $15.3 million in cash, $53.1 million in debt assumed, 6,986,104 shares of our common stock valued at approximately $55.8 million based on the closing stock price of $7.99 on April 13, 2011, and $1.2 million in warrant liability, of which $1.0 million was paid out in cash upon exercise of the cash option (included in $53.1 million in cash above) and 138,388 warrants are outstanding that are exercisable for common stock of the Company. The Company has liquidated NGAS into a wholly-owned subsidiary of the Company, NGAS Hunter, LLC, and changed the name of its subsidiary NGAS Production Co. to Magnum Hunter Production, Inc. and the name of another subsidiary, NGAS Securities, Inc. to Energy Hunter Securities, Inc. The primary purpose of the acquisition was to acquire leasehold acreage and wells complementary to our existing acreage and expand our position in the Marcellus Shale in West Virginia and establish our position in Southern Appalachia.

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The following table summarizes the purchase price and the fair values of the net assets from NGAS acquired (in thousands, except share per share information):

Fair value of total purchase price:
6,635,478 shares of common stock issued on April 13, 2011 at $7.99 per share	$	53,017
Senior credit facility paid off at closing	33,282
NGAS 6% convertible notes paid off in cash at closing	13,683
Contract payment in cash	12,929
Other long-term debt assumed	6,160
350,626 shares of common stock issued for change in control payments at $7.99 per share	2,802
Tax on change of control payments paid in cash	1,363
Common stock warrants settled in cash	1,044
Common stock warrants issued in conversion of NGAS warrants	190
Total	$	124,470
Amounts recognized for assets acquired and liabilities assumed:
Working capital deficit	$	(11,028	)
Oil and gas properties	135,121
Equipment and other fixed assets	9,055
Asset retirement obligation	(8,678		)
Total	$	124,470
Working capital deficit assumed:
Cash	$	1,908
Accounts receivable	3,662
Prepaid Expenses	416
Inventory	278
Accounts payable	(9,009		)
Revenue payable	(1,547		)
Payroll tax payable	(206		)
Advances	(3,751		)
Deferred compensation	(379		)
Accrued Liabilities	(2,400		)
Total working capital deficit assumed	$	(11,028	)

NuLoch Acquisition

On May 3, 2011, the Company completed the acquisition of all of the outstanding common shares of NuLoch Resources, Inc., (“NuLoch”) for total consideration of approximately $430.5 million consisting of 38,131,846 shares of our common stock and 4,275,998 exchangeable shares of MHR Exchangeco Corporation, an indirect wholly-owned Canadian subsidiary of the Company, which are exchangeable for shares of Company common stock, with a combined value of approximately $313.8 million based on the closing stock price of $7.40 on May 3, 2011, $18.8 million in debt assumed, and deferred tax liability of approximately $97.9 million. The Company has changed the name of NuLoch to Williston Hunter Canada, Inc. and its subsidiary NuLoch America Corporation to Williston Hunter, Inc. The primary purpose of the acquisition was to establish the Company's position in the Bakken, Three Forks, and Sanish formations in North Dakota and Saskatchewan, Canada.

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The following table summarizes the purchase price and the estimates of the fair values of the net assets of NuLoch acquired (in thousands except shares and per share amounts):

Fair value of total purchase price:
38,131,846 shares of common stock issued on May 3, 2011 at $7.40 per share	$	282,175
4,275,998 exchangeable shares at $7.40 per share	31,643
Debt assumed	18,770
Net deferred tax liability	97,912
Total	$	430,500
Amounts recognized for assets acquired and liabilities assumed:
Working capital deficit	$	(20,711	)
Oil and gas properties	447,540
Equipment and other fixed assets	5,167
Asset retirement obligation	(1,496		)
Total	$	430,500
Working capital deficit assumed:
Cash	$	640
Accounts receivable	5,951
Prepaid expenses	359
Accounts payable	(27,661		)
Total working deficit assumed	$	(20,711	)

Utica Shale Assets Acquisition

On February 17, 2012, the Company closed on the acquisition of leasehold mineral interests located predominately in Noble County, Ohio for a total purchase price of $24.8 million in cash. 

Eagle Operating Assets Acquisition

On March 30, 2012, the Company, through its wholly-owned subsidiary, Williston Hunter ND, LLC, a Delaware limited liability company (“Williston Hunter”), closed on the purchase of operating working interest in certain oil and gas leases and wells located in several counties in North Dakota from Eagle Operating, Inc. (“Eagle Operating”), an unrelated third party, effective April 1, 2011.  Total consideration was $52.9 million consisting of $51.0 million in cash and 296,859 shares of Magnum Hunter restricted common stock valued at $1.9 million based on a price of $6.41 per share. The purpose of the acquisition was to expand the Company’s position in the Williston Basin. The Company already owned a non-operated ownership interest in the properties acquired.

The acquisition was accounted for using the acquisition method of accounting, which requires the net assets acquired to be recorded at their fair values. The following table summarizes the purchase price and the estimates of fair values of the net assets acquired (in thousands, except shares and per share information):

Fair value of total purchase price:
296,859 shares of common stock issued on March 30, 2012 at $6.41 per share	$	1,902
Cash	50,974
Total	$	52,876
Amounts recognized for assets acquired and liabilities assumed:
Oil and gas properties	$	54,832
Asset retirement obligation	(1,956		)
Total	$	52,876

TransTex Gas Services, LP Assets Acquisition

On April 2, 2012, the Company, through its majority owned subsidiary, Eureka Hunter Holdings, LLC, and its wholly-owned subsidiary, Eureka Hunter Acquisition Sub, LLC, closed on their purchase of certain assets of TransTex Gas Services, LP (“TransTex”), a related third party, under an asset purchase agreement dated March 21, 2012, which resulted in the recognition of approximately

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$30.6 million in goodwill and $10.5 million of intangible assets.  See "Note 8 - Goodwill and Intangible Assets" for additional information. The Company expects all of the goodwill, which is associated with the Company’s midstream operating segment, to be deductible for tax purposes.  The purpose of the acquisition was to complement the Company’s existing midstream assets.  The total purchase price paid for the acquired assets was $58.5 million, comprised of $46.0 million in cash and 622,641 Eureka Hunter Holdings Class A Common Units representing membership interests in Eureka Hunter Holdings, with a value of $12.5 million based on an estimated enterprise value of $400.0 million at that time.  The value, totaling $12.5 million as of the acquisition date, of the common units transferred as partial consideration for the acquisition was determined utilizing a discounted future cash flow analysis. 

The following table summarizes the purchase price and the estimates of fair values of the net assets acquired from TransTex (in thousands):

Fair value of total purchase price:
Cash	$	46,047
Eureka Hunter Holdings Class A Common Units	12,453
Total	$	58,500
Amounts recognized for assets acquired and liabilities assumed:
Working capital	$	525
Equipment and other fixed assets	15,575
Other assets	1,306
Goodwill (Note 8)	30,602
Intangible assets (Note 8)	10,492
Total	$	58,500

Gary C. Evans, our Chairman and CEO, previously held a small limited partnership interest in TransTex, and participated in the purchase of certain Eureka Hunter Holdings Class A Common Units offered to all limited partners of TransTex in connection with the acquisition. See "Note 17 - Related Party Transactions" below.

Baytex Energy USA Assets Acquisition

On May 22, 2012, the Company, through its wholly-owned subsidiary, Bakken Hunter, LLC, closed on the acquisition of certain Williston Basin assets of Baytex Energy USA, Ltd. (“Baytex Energy USA”), an affiliate of Baytex Energy Corporation, an unrelated third party, for a total purchase price of $312.0 million.  The purpose of the acquisition was to significantly increase the Company’s ownership interest in existing mineral leases in a key shale play where the Company has increased its drilling activities. To a lesser extent, proved reserves were added attributable to the acquired properties. The acquired assets include all of Baytex Energy USA’s non-operated working interest in oil and gas properties and wells located in Divide and Burke Counties, North Dakota, within an area subject to an operating agreement among Samson Resources Company, as operator, Baytex Energy Corporation, and Williston Hunter, Inc., a wholly-owned subsidiary of Magnum Hunter. 

The following table summarizes the purchase price and the preliminary estimates of fair values of the net assets acquired (in thousands):

Fair value of total purchase price:
Cash	$	312,018
Total	$	312,018
Amounts recognized for assets acquired and liabilities assumed:
Oil and gas properties	$	312,294
Asset retirement obligation	(276		)
Total	$	312,018

Acquisition of Viking International Resources Co., Inc.

On November 2, 2012, Triad Hunter, LLC, a wholly-owned subsidiary of the Company, closed on the acquisition of all outstanding capital stock of Viking International Resources Co., Inc. (“Virco”) effective January 1, 2012.  The total fair market value of consideration paid was approximately $100.8 million, made up of approximately $37.3 million paid in cash and 2,774,850 depositary shares representing 2,774.85 shares of 8.0% Series E Cumulative Convertible Preferred Stock of the Company with market value of approximately $65.2 million and stated liquidation preference of approximately $69.4 million. See "Note 12 – Shareholders’ Equity" for additional information on the Series E Preferred Stock. The primary purpose of the acquisition was to acquire leasehold

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acreage and wells complementary to our existing acreage position of this region and expand our ownership interest in the Marcellus Shale and Utica Shale plays in West Virginia and Ohio.

The following table summarizes the purchase price and the preliminary estimates of fair values of the net assets acquired (in thousands):

Fair value of total purchase price:
Cash	$	37,349
2,774,850 depositary shares evidencing Series E Preferred Stock issued on November 2, 2012, valued at $23.50 per share	65,209
Escrow settlement	(1,750		)
Total	$	100,808
Amounts recognized for assets acquired and liabilities assumed:
Oil and gas properties	$	110,224
Current assets	1,676
Equipment and other fixed assets	970
Accounts payable and accrued expenses	(3,928		)
Other long-term liabilities	(2,362		)
Asset retirement obligation	(5,772		)
Total	$	100,808

Samson Resources Assets Acquisition

On December 20, 2012, Bakken Hunter, LLC, a wholly-owned subsidiary of the Company, closed on the acquisition of certain existing wells and Williston Basin lease acres located in Divide County, North Dakota from Samson Resources Company. The purchase price for the assets was $30 million in cash, subject to customary adjustments. The effective date of the transaction was August 1, 2012.

With the closing of this transaction, the Company owns varied working ownership interests in these properties up to approximately 100%. The acquisition established the Company as an operator in certain of this Bakken acreage, covering four Townships and Ranges in northern Divide County, North Dakota, previously operated by Samson Resources Company.

The following summarizes the revenue and operating income (loss) from the acquisitions included in our consolidated statements of operations for the years ended December 31, 2012 and 2011:

	For the year ended December 31,
	2012					2011
	Revenues		Operating Income (loss)			Revenues		Operating Income (loss)
	(in thousands)					(in thousands)
NGAS acquisition	$	19,611	$	18,453		$	16,581	$	(28,698	)
NuLoch acquisition	64,045		(66,862		)	18,524		901
Eagle Operating assets	5,500		(3,019		)
TransTex assets	7,014		(393		)
Baytex Energy USA assets	18,430		(6,649		)
VIRCO acquisition	1,094		450

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The following unaudited summary, prepared on a pro forma basis, presents the results of operations for the years ended December 31, 2012, and 2011, as if the above acquisitions along with transactions necessary to finance the acquisitions, had occurred as of the beginning of 2011. The pro forma information includes the effects of adjustments for interest expense, depreciation and depletion expense, and dividend expense. The pro forma results are not necessarily indicative of what actually would have occurred if the acquisition had been completed as of the beginning of each period presented, nor are they necessarily indicative of future consolidated results.

	Pro Forma
	For the Year Ended December 31,
	2012			2011
	(in thousands, unaudited)
Total revenue	$	290,328		$	160,746
Operating loss	(135,014		)	(56,441		)
Net loss	(151,946		)	(105,412		)
Net loss attributable to Magnum Hunter Resources Corporation	(147,933		)	(105,661		)
Net loss attributable to common shareholders	$	(189,906	)	$	(136,889	)
Loss per common share, basic and diluted	(1.21		)	(0.92		)

NOTE 7 – DISCONTINUED OPERATIONS

On February 17, 2012, the Company, through its wholly-owned subsidiary, Triad Hunter, LLC, sold 100% of its equity ownership interest in Hunter Disposal, LLC, to a wholly-owned subsidiary of GreenHunter Resources, Inc., for total consideration of $9.3 million, comprised of cash of $2.2 million, 1,846,722 restricted common shares of GreenHunter Resources, Inc., valued at $2.6 million based on a closing price of $1.79 per share, discounted for restrictions, 88,000 shares of GreenHunter Resources, Inc. 10% Series C Preferred Stock, with a fair value of $1.9 million, and a promissory note of $2.2 million which is convertible, at the option of the Company, into 880,000 shares of GreenHunter Resources, Inc. common stock based on the conversion price of $2.50 per share. The Company recognized an embedded derivative asset resulting from the conversion option on the convertible promissory note with an initial fair value of $405,000. See "Note 4 - Fair Value of Financial Instruments" for additional information. The cash proceeds from the sale were adjusted downward to $783,000 for changes in working capital and certain fees to reflect the effective date of the sale of December 31, 2011. Triad Hunter recognized a gain on the sale of discontinued operations of $3.7 million, $2.4 million net of tax of $1.3 million. GreenHunter Resources, Inc. is a related party as described in "Note 17 - Related Party Transactions". The operating results of Hunter Disposal, LLC, which has historically been included as part of the Oilfield Services operating segment, have been reclassified as discontinued operations in the consolidated statements of operations for the years ended December 31, 2012 and 2011, as detailed in the table below:

	(1)Year Ended December 31,			Year Ended December 31,
	2012			2011
	(in thousands)
Revenues	$	2,400		$	13,047
Operating expenses	(2,047		)	(10,049		)
Income tax expense and other	(123		)	(21		)
Gain on sale of discontinued operations (net of tax of $1.3 million)	2,409			—
Income from discontinued operations	$	2,639		$	2,977

⁽¹⁾Represents operations from January 1, 2012 through February 17, 2012, the date of sale.

NOTE 8 — GOODWILL AND INTANGIBLE ASSETS

Goodwill

Goodwill represents the excess of the purchase price of an entity over the estimated fair value of the assets acquired and the liabilities assumed. The Company assesses the carrying amount of goodwill by testing the goodwill for impairment annually or whenever interim impairment indicators arise.  Goodwill of $30.6 million was recorded related to our midstream segment during 2012 as a result of our acquisition of the assets of TransTex Gas Services, LP, discussed in "Note 6 -  Acquisitions". The Company assessed goodwill for the period April 2012 to December 31, 2012, and determined that no impairment existed at December 31, 2012.

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Intangible Assets

Intangible assets consist primarily of the fair value of the acquired gas treating agreements and customer relationships in the TransTex Gas Services, LP assets acquisition completed in 2012.  The intangible assets were valued at fair value using a discounted cash flow model with a discount rate of 13%.  Such assets are being amortized over the weighted average term of 8.54 years. 

The following table summarizes our changes in intangible assets during the year ended December 31, 2012:

	Amortization		December 31,
	Period		2012
			(in thousands)
Intangible assets, at beginning of the period			$	—
Additions through acquisition:
Customer relationships	12.5	years	5,434
Trademark	11.0	years	859
Existing contracts	2.9	years	4,199
Total intangible assets			10,492
Accumulated amortization:
Customer relationships			(326		)
Trademark			(58		)
Existing contracts			(1,127		)
Intangible assets, net of accumulated amortization			$	8,981

The following table summarizes the aggregate amortization of intangible assets over the next five years:

	(in thousands)
2013	$	1,964
2014	$	1,810
2015	$	837
2016	$	513
2017	$	513
Thereafter	$	3,345

NOTE 9 - ASSET RETIREMENT OBLIGATIONS

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

Our liability is determined using significant assumptions, including current estimates of plugging and abandonment costs, annual inflation of these costs, the productive lives of wells and our risk-adjusted interest rate. Changes in any of these assumptions can result in significant revisions to the estimated asset retirement obligation. Revisions to the asset retirement obligation are recorded with an corresponding change to producing properties, resulting in prospective changes to depreciation, depletion and amortization expense and accretion of discount. Because of the subjectivity of assumptions and the relatively long lives of most of our wells, the costs to ultimately retire our wells may vary significantly from prior estimates. Our liability for asset retirement obligations was approximately$30.7 million and $20.6 million at December 31, 2012 and 2011, respectively.

Our midstream operating assets generally consist of underground pipelines and related components along rights-of-way and above ground storage tanks and related facilities. Our right-of-way agreements typically do not require the dismantling, removal and reclamation of the right-of-way upon permanent cessation of pipeline service. Additionally, management is unable to predict when, or if, our pipelines, storage tanks and related facilities would become completely obsolete and require decommissioning. Accordingly, we have recorded no liability or corresponding asset as an asset retirement obligation as both the amounts and timing of such future costs are indeterminable.

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The following table summarizes the Company’s asset retirement obligation transactions during the years ended December 31:

	2012			2011
	(in thousands)
Asset retirement obligation, beginning of period	$	20,584		$	4,455
Assumed in acquisition	8,027			10,174
Accretion expense	1,671			882
Liabilities incurred	373			688
Revisions in estimated liabilities	76			1,766
Foreign currency adjustment	16			—
Liabilities settled	(80		)	(14		)
Correction of prior year error	—			2,660
Associated with property sales	13			(27		)
Asset retirement obligation, end of period	30,680			20,584
Less: current portion included in other current liabilities	2,358			495
Asset retirement obligation, end of period	$	28,322		$	20,089

NOTE 10 – LONG-TERM DEBT

Notes payable at December 31, 2012 and 2011 consisted of the following:

	(in thousands)
	2012			2011
Senior Notes Payable due May 15, 2020, interest rate of 9.75%, net of unamortized discount of $2.8 million	$	597,212		$	—
Various equipment and real estate notes payable with maturity dates February 2015 - November 2017, interest rates of 4.25% - 5.70%	18,548			17,389
Eureka Hunter Pipeline, LLC second lien term loan due August 16, 2018, interest rate of 12.5%	50,000			31,000
Second lien term loan due October 13, 2016, interest rate of 8% (1)	—			100,000
Senior revolving credit facility due April 13, 2016, interest rate of 3.56% at December 31, 2012	225,000			142,000
	$	890,760		$	290,389
Less: current portion	(3,991		)	(4,565		)
Total long-term debt	$	886,769		$	285,824

⁽¹⁾The Company’s second lien term loan was paid in full in May 2012 in connection with the issuance of the Company’s Senior Notes.

The following table presents the approximate annual maturities of debt, gross of unamortized discount:

	(in thousands)
2013	$	3,991
2014	4,368
2015	6,412
2016	227,628
2017	1,149
Thereafter	650,000
	$	893,548

Senior Notes Payable

On May 16, 2012, the Company completed the issuance of $450.0 million aggregate principal amount of its 9.75% Senior Notes which mature on May 15, 2020 for total proceeds of $431.2 million net of issuing costs of $12.8 million, resulting in a discount of $6.0 million.  The Senior Notes are unsecured and are guaranteed, jointly and severally, on a senior unsecured basis by certain of the Company’s domestic subsidiaries. The indenture governing the Senior Notes permits a guarantor of the Senior Notes to be released from its guarantee under certain circumstances, including in connection with a sale or other disposition of all or substantially all of

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the assets of the guarantor, a sale of other disposition of the capital stock of the guarantor to a third party, or upon the liquidation or dissolution of the guarantor.

Interest on the Senior Notes is paid semi-annually in arrears on May 15 and November 15 of each year, with the first interest payment made on November 15, 2012.

The Company used the net proceeds of this offering, together with other sources of liquidity, (i) to finance a portion of the $312.0 million acquisition of oil properties in the Williston Basin from Baytex Energy USA, Ltd., which closed on May 22, 2012, (ii) to pay off all amounts outstanding under the Company’s second lien term loan, (iii) to repay outstanding debt under the Company’s senior revolving credit facility, (iv) to increase the Company’s 2012 upstream capital budget from $150.0 million to $325.0 million (92% of capital budget focused on Williston Basin and Eagle Ford Shale) and (v) for general corporate purposes.

On December 13, 2012, the Company completed the issuance of an additional $150.0 million aggregate principal amount of its 9.75% Senior Notes for total proceeds of $149.9 million net of issuing costs of $3.1 million, resulting in a premium of $3.0 million.  The Company used the net proceeds of this offering to pay down the outstanding debt under the Company’s senior revolving credit facility and for general corporate purposes.

The Senior Notes were issued pursuant to an indenture entered into on May 16, 2012 as supplemented, among the Company, the subsidiary guarantors party thereto, Wilmington Trust, National Association, as the trustee, and Citibank, N.A., as the paying agent, registrar and authenticating agent.  The terms of the Senior Notes are governed by the indenture, which contains affirmative and restrictive covenants that, among other things, limit the Company’s and the guarantors’ ability to incur or guarantee additional indebtedness or issue certain preferred stock; pay dividends on capital stock or redeem, repurchase or retire capital stock or subordinated indebtedness or make certain other restricted payments; transfer or sell assets; make loans and other investments; create or permit to exist certain liens; enter into agreements that restrict dividends or other payments from restricted subsidiaries to the Company; consolidate, merge or transfer all or substantially all of their assets; engage in transactions with affiliates; and create unrestricted subsidiaries.

The indenture also contains customary events of default.  Upon the occurrence of events of default arising from certain events of bankruptcy or insolvency, the Senior Notes shall become due and payable immediately without any declaration or other act of the trustee or the holders of the Senior Notes.  Upon the occurrence of certain other events of default, the trustee or the holders of at least 25% in aggregate principal amount of the then outstanding Senior Notes may declare all outstanding Senior Notes to be due and payable immediately.

The Senior Notes are redeemable by the Company at any time on or after May 15, 2016, at the redemption price of 104.875%, after May 15, 2017, at the redemption price of 102.438%, and after May 15, 2018, at the redemption price of 100.00%. The Senior Notes are redeemable by the Company prior to May 15, 2016 at the redemption price equal to 100.00% of the principle amount of the notes redeemed, plus a “make-whole” premium of the greater of:

(1)1.0% of the principal amount of the note; and

(2)The excess of:

(a) The present value at such redemption date of (i) the redemption price of the note at May 15, 2016 plus (ii) all required interest payments due on the note through May 15, 2016 (excluding accrued but unpaid interest to the redemption date), computed using a discount rate equal to the treasury rate as of such redemption date plus 50 basis points discounted to such redemption date on a semi-annual basis, over

(b) The principal amount of the note.

The Company is also entitled to redeem up to 35% of the aggregate principal amount of the Senior Notes before May 15, 2015 with net proceeds that the Company raises in certain equity offerings at a redemption price of 109.750%, so long as at least 65% of the aggregate principal amount of the Senior Notes issued under the indenture (excluding Senior Notes held by the Company) remains outstanding immediately after such redemption and the redemption occurs within 180 days of the closing date of such equity offering.  If the Company experiences certain change of control events, each holder of Senior Notes may require the Company to repurchase all or a portion of the Senior Notes for cash at a price equal to 101% of the aggregate principal amount of such Senior Notes, plus any accrued and unpaid interest up to, but not including the date of repurchase.

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Eureka Hunter Pipeline Credit Facilities

On August 16, 2011, Eureka Hunter Pipeline, LLC (“Eureka Hunter Pipeline ”), a majority-owned subsidiary of the Company, entered into (i) a First Lien Credit Agreement (the “First Lien Agreement”) by and among Eureka Hunter Pipeline, the lenders party thereto and SunTrust Bank, as administrative agent, and (ii) a Second Lien Term Loan Agreement (the “Second Lien Agreement”), by and among Eureka Hunter Pipeline, the lenders party thereto and U.S. Bank National Association, as collateral agent (the First Lien Agreement and the Second Lien Agreement being collectively referred to as the “Eureka Credit Agreements”).

The First Lien Agreement provides for a revolving credit facility (the “Revolver”) in an aggregate principal amount of up to $100 million (with an initial committed amount of $25 million), secured by a first lien on substantially all of the assets of Eureka Hunter Pipeline. The Second Lien Agreement provides for a $50 million term loan facility (the “Term Loan”), secured by a second lien on substantially all of the assets of Eureka Hunter Pipeline. The entire $50 million Term Loan had previously been drawn.  As of May 1, 2013, the revolving credit facility is not available due to the Company's failure to meet certain debt covenants included in the agreement. The Revolver has a maturity date of August 16, 2016, and the Term Loan has a maturity date of August 16, 2018. Both the Revolver and the Term Loan are non-recourse to Magnum Hunter Resources Corporation. See "Effect of Late SEC Filings on Liquidity and Capital Resources."

The terms of the First Lien Agreement provide that the Revolver may be used for (i) revolving loans, (ii) swingline loans in an aggregate amount of up to $5 million at any one time outstanding, or (iii) letters of credit in an aggregate amount of up to $5 million at any one time outstanding. The Revolver provides for a commitment fee of 0.5% per annum based on the unused portion of the commitment under the Revolver.

Borrowings under the Revolver will, at Eureka Hunter Pipeline’s election, bear interest at:

• a base rate equal to the highest of (i) the prime lending rate announced from time to time by the Administrative Agent, (ii) the then-effective Federal Funds Rate plus 0.5% per annum, or (iii) the Adjusted LIBOR (as defined in the First Lien Agreement) for a one-month interest period on such day plus 1.0% per annum, plus an applicable margin ranging from 1.25% to 2.25%; or

• the Adjusted LIBOR, plus an applicable margin ranging from 2.25% to 3.5%.

Borrowings under the Term Loan will bear interest at (a) prior to June 29, 2012, (i) 9.750% per annum in cash, plus (ii) 2.75% (increasing to 3.75% on and at all times when Eureka Hunter Pipeline and its subsidiaries incur indebtedness (other than the Term Loan) in excess of $1 million) which additional 2.75% (or 3.75%) interest amount may be paid, at the sole option of Eureka Hunter Pipeline, in cash or in shares of restricted common stock of the Company and (b) on or after June 29, 2012, 12.50% per annum in cash (increasing to 13.50% on and at all times when Eureka Hunter Pipeline and its subsidiaries incur indebtedness (other than the Term Loan) in excess of $1 million).

If an event of default occurs under either the Revolver or the Term Loan, the lenders may increase the interest rate then in effect by an additional 2.0% per annum for the period that the default exists under the Revolver or the Term Loan.

The Eureka Credit Agreements contain negative covenants that, among other things, restrict the ability of Eureka Hunter Pipeline to, with certain exceptions: (1) incur indebtedness; (2) grant liens; (3) dispose of all or substantially all of its assets or enter into mergers, consolidations, or similar transactions; (4) change the nature of its business; (5) make investments, loans, or advances or guarantee obligations; (6) pay cash dividends or make certain other payments; (7) enter into transactions with affiliates; (8) enter into sale and leaseback transactions; (9) enter into hedging transactions; (10) amend its organizational documents or material agreements; or (11) make certain undisclosed capital expenditures.

The Eureka Credit Agreements also require Eureka Hunter Pipeline to satisfy certain financial covenants, including maintaining:

• a consolidated total debt to capitalization ratio of not more than 60%;

• a consolidated EBITDA to consolidated interest expense ratio ranging from:

(i) for the Term Loan, not less than (A) 0.85 to 1.00 for the fiscal quarter ended December 31, 2012 (unless Eureka Hunter Pipeline has borrowed under the Revolver before December 31, 2012, in which case, 1.00 to 1.00), (B) 1.25 to 1.00, for the fiscal quarter ended March 31, 2013, (C) 1.50 to 1.00, for the fiscal quarter ending June 30, 2013, (D) 1.75 to 1.00, for the fiscal quarter ending September 30, 2013, (E) 2.25 to 1.00, for the fiscal quarters ending December 31, 2013 and March 31, 2014, (E) 2.50 to 1.00, for the fiscal quarters ending June 30, 2014 and September 30, 2014, and (F) 2.75 to 1.0 for the fiscal quarter ending December 31, 2014 and each fiscal quarter ending thereafter, and

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(ii) in the event any portion of the Revolver has been drawn, for the Revolver, not less (A) 1.25 to 1.00 for the fiscal quarter ending December 31, 2012, (B) 1.50 to 1.00, for the fiscal quarter ended March 31, 2013, (C) 1.75 to 1.00, for the fiscal quarter ending June 30, 2013, (D) 2.00 to 1.00, for the fiscal quarter ending September 30, 2013, (E) 2.50 to 1.00, for the fiscal quarters ending December 31, 2013 and March 31, 2014, (E) 2.75 to 1.00, for the fiscal quarters ending June 30, 2014 and September 30, 2014, and (F) 3.00 to 1.0 for the fiscal quarter ending December 31, 2014 and each fiscal quarter ending thereafter;

• a consolidated total debt to consolidated EBITDA ratio ranging from:

(i) for the Term Loan, not greater than (A) 8.50 to 1.0 for the fiscal quarter ended December 31, 2012 (unless Eureka Hunter Pipeline has borrowed under the Revolver before December 31, 2012, in which case, 6.50 to 1.00), (B) 6.00 to 1.0 for the fiscal quarters ended March 31, 2013 and June 30, 2013, (C) 5.00 to 1.0 for the fiscal quarter ending September 30, 2013, (D) 4.50 to 1.0 for the fiscal quarters ending December 31, 2013, March 31, 2014, June 30, 2014, and September 30, 2014, and (E) 4.25 to 1.0 for the fiscal quarter ending December 31, 2014 and each fiscal quarter ending thereafter, and

(ii) in the event any portion of the Revolver has been drawn, for the Revolver, not greater than (A) 6.25 to 1.0 for the fiscal quarter ended December 31, 2012, (B) 5.75 to 1.0 for the fiscal quarters ended March 31, 2013 and June 30, 2013, (C) 4.75 to 1.0 for the fiscal quarter ending September 30, 2013, (D) 4.50 to 1.0 for the fiscal quarters ending December 31, 2013 and March 31, 2014, and (E) 4.00 to 1.0 for the fiscal quarter ending June 30, 2014 and each fiscal quarter ending thereafter; and

• a ratio of consolidated debt under the Revolver to consolidated EBITDA of (i) for the Term Loan, not greater than 3.5 to 1.0, and (ii) for the Revolver, if any portion of the Revolver has been drawn, not greater than 3.25 to 1.0 for each fiscal quarter.

The obligations of Eureka Hunter Pipeline under each of the Revolver and the Term Loan may be accelerated upon the occurrence of an Event of Default (as such term is defined in such Eureka Credit Agreement) under such Eureka Credit Agreement. Events of Default include customary events for these types of financings, including, among others, payment defaults, defaults in the performance of affirmative or negative covenants, the inaccuracy of representations or warranties, defaults under the Term Loan (with respect to the Revolver) or the Revolver (with respect to the Term Loan), defaults relating to judgments, material defaults under certain material contracts of Eureka Hunter Pipeline, and defaults by the Company which cause the acceleration of the Company’s debt under its existing MHR Senior Revolving Credit Facility.

Under the Eureka Credit Agreements, (i) Eureka Hunter Pipeline and its subsidiaries have entered into customary ancillary agreements and arrangements, which provide that the obligations under the Eureka Credit Agreement are secured by substantially all of the assets of Eureka Hunter Pipeline and such subsidiaries, consisting primarily of pipelines, pipeline rights-of-way, and gas treating and processing equipment and certain other equipment, and (ii) Eureka Hunter Holdings, the sole parent of Eureka Hunter Pipeline and a majority owned subsidiary of the Company, entered into customary ancillary agreements and arrangements, which granted the lenders under the Eureka Credit Agreements a non-recourse security interest in Eureka Hunter Holdings' equity interests in Eureka Hunter Pipeline.

Availability under the Revolver is subject to satisfaction of certain financial covenants that are tested on a quarterly basis. 

On April 2, 2012, Eureka Hunter Holdings closed on the acquisition of certain assets of TransTex.  The working capital and EBITDA associated with the acquired assets are included in the covenant determinations under Eureka Hunter Pipeline’s credit facilities going forward based on amendments to such credit facilities.

At December 31, 2012, we were in compliance with all of our covenants, as amended or waived, contained in the Eureka Hunter Pipeline credit facilities. See "Effect of Late SEC Filings on Liquidity and Capital Resources."

Eureka Hunter Pipeline had loans outstanding under this second lien facility of $50.0 million and $31.0 million as of December 31, 2012 and 2011, respectively.

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The Amended and Restated Limited Liability Company Agreement of Eureka Hunter Holdings, referred to as the EH Operating Agreement, contains certain covenants that, among other things, restrict the ability of Eureka Hunter Holdings and its subsidiaries, including Eureka Hunter Pipeline and TransTex Hunter, LLC, to, with certain exceptions:

• incur funded indebtedness, whether direct or contingent;

• issue additional equity interests;

• pay distributions to its owners, or repurchase or redeem any of its equity securities;

• make any material acquisitions, dispositions or divestitures; or

• enter into a sale, merger, consolidation or other change of control transaction.

Magnum Hunter Second Lien Term Loan Credit Agreement

On September 28, 2011, the Company entered into a Second Lien Term Loan Credit Agreement (the “Second Lien Credit Agreement”) by and among the Company, Capital One, N.A., as Administrative Agent, BMO Harris Financing, Inc., as Syndication Agent, Citibank, N.A., as Documentation Agent, BMO Capital Markets Corp. and Capital One, N.A., as Joint Lead Arrangers and Bookrunners, and the lenders party thereto.

The Second Lien Credit Agreement provided for a term loan credit facility (the “Term Loan Facility”) maturing on October 13, 2016, in an aggregate principal amount of $100 million, which was fully drawn on the closing date.

On May 16, 2012, the Company retired the Term Loan Facility using proceeds from the issuance of Senior Notes. In connection with this retirement, the Company wrote off $2.8 million in unamortized deferred financing costs during 2012.

The Company had loans outstanding under the Term Loan Facility of $100.0 million as of December 31, 2011, and the facility was paid off and terminated in May 2012.

MHR Senior Revolving Credit Facility

On April 13, 2011, the Company entered into a Second Amended and Restated Credit Agreement, referred to, as amended, as the MHR Senior Revolving Credit Facility, by and among the Company, Bank of Montreal, as administrative agent, and the lenders party thereto.

The MHR Senior Revolving Credit Facility provides for an asset‑based, senior secured revolving credit facility maturing on April 13, 2016. The MHR Senior Revolving Credit Facility is governed by a semi-annual borrowing base redetermination derived from the Company’s proved crude oil and natural gas reserves, and based on such redeterminations, the borrowing base may be decreased or may be increased up to a maximum commitment level of $750 million.

As of December 31, 2012, the aggregate borrowing base under this facility was $337.5 million, comprised of a conforming borrowing base of $306.25 million and a non-conforming borrowing base of $31.25 million. Borrowings under the non-conforming borrowing base could not be made unless availability under the conforming borrowing base was fully borrowed. There were no borrowings under the non-conforming borrowing base outstanding at December 31, 2012. On February 25, 2013, pursuant to an amendment to this facility, the non-conforming borrowing base was eliminated, and the conforming borrowing base was increased to $350.0 million. On April 23, 2013, pursuant to a subsequent amendment, the borrowing base was decreased from $350 million to $265 million, effective upon the closing of the Company's sale of 100% of the capital stock of Eagle Ford Hunter, Inc. to Penn Virginia Oil & Gas Corporation. See "Note – 20 Subsequent Events".

The facility may be used for loans and, subject to a $10 million sublimit, letters of credit. The facility provides for a commitment fee of 0.50% based on the unused portion of the borrowing base under the facility.

Borrowings under the facility will, at the Company’s election, bear interest at either: (i) an alternate base rate, or "ABR", equal to the higher of (A) the Prime Rate, (B) the Federal Funds Effective Rate plus 0.5% per annum and (C) the LIBOR for a one month interest period on such day plus 1.00%; or (ii) the adjusted LIBOR, which is the rate stated on Reuters BBA Libor Rates LIBOR01 market for one, two, three, six or twelve months, as adjusted for statutory reserve requirements for Eurocurrency liabilities, plus, in each of the cases described in clauses (i) and (ii) above, an applicable margin ranging from 1.25% to 2.75% for ABR loans and from 2.25% to 3.75% for adjusted LIBO Rate loans.

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Upon any payment default, the interest rate then in effect shall be increased on such overdue amount by an additional 2% per annum for the period that the default exists plus the rate applicable to ABR loans.

The MHR Senior Revolving Credit Facility contains negative covenants that, among other things, restrict the ability of the Company to, with certain exceptions: (1) incur indebtedness; (2) grant liens; (3) make certain restricted payments; (4) change the nature of its business; (5) dispose of its assets; (6) enter into mergers, consolidations or similar transactions; (7) make investments, loans or advances; (8) pay cash dividends, unless certain conditions are met, and subject to a “basket” of $45 million per year available for payment of dividends on preferred stock; and (9) enter into transactions with affiliates. The facility also requires the Company to satisfy certain financial covenants, including maintaining (as defined) (1) a ratio of consolidated current assets to consolidated current liabilities of not less than 1.0 to 1.0; (2) a ratio of EBITDAX to interest expense of not less than 2.5 to 1.0; and (3) a total debt to EBITDAX ratio of not more than (a) 4.75 to 1.0 for the fiscal quarter ended December 31, 2012, (b) 4.50 to 1.0 for the fiscal quarter ended March 31, 2013, (c) 4.25 to 1.0 for the fiscal quarter ending June 30, 2013, and (d) 4.00 to 1.0 for the fiscal quarter ending September 30, 2013 and for each fiscal quarter ending thereafter, unless, in the case of this clause (iv) only, a “material asset sale” shall have occurred during any such fiscal quarter in which case the ratio of total debt to EBITDAX shall not exceed 4.0 to 1.0 for such fiscal quarter. A “material asset sale” is any asset sale resulting in the receipt of net cash proceeds in excess of $15 million, other than asset sales made in the ordinary course of the Company’s and its restricted subsidiaries’ partnership drilling programs. The Company is also limited to certain maximum notional amounts in respect of commodity hedging agreements pursuant to the terms of the facility.

The obligations of the Company under the facility may be accelerated upon the occurrence of an event of default (as such term is defined in the facility). Events of default include customary events for a financing agreement of this type, including, without limitation, payment defaults, defaults in the performance of affirmative or negative covenants, the inaccuracy of representations or warranties, bankruptcy or related defaults, defaults relating to judgments and the occurrence of a change in control of the Company.

Our ability to access the MHR Senior Revolving Credit Facility, and for Eureka Hunter Pipeline to access the Eureka Credit Agreements, could be curtailed or eliminated if (i) we fail to file our Form 10-Q for the quarter ended March 31, 2013 by the lenders' extended deadline of July 12, 2013 or within any extended time period our lenders may in the future provide us or (ii) an uncured cross-default under such facilities results from any uncured “event of default” under the indenture relating to our Senior Notes stemming from our late SEC filings. See “Risk Factors - Our existing indenture defaults restrict our ability to utilize certain exceptions to the restrictive covenants contained therein and, under certain circumstances, may result in the acceleration of the Senior Notes issued under our indenture and the outstanding debt under our credit facilities, which would have a material adverse effect on our business, financial condition and liquidity.”

Subject to certain permitted liens, the Company’s obligations under the MHR Senior Revolving Credit Facility have been secured by the grant of a first priority lien on no less than 80% of the value of the proved oil and gas properties of the Company and its restricted subsidiaries.

In connection with the facility, the Company and its restricted subsidiaries also entered into certain customary ancillary agreements and arrangements, which, among other things, provide that the indebtedness, obligations and liabilities of the Company arising under or in connection with the facility are unconditionally guaranteed by such subsidiaries.

The Company had loans outstanding under this senior credit facility of $225.0 million and $142.0 million as of December 31, 2012 and 2011, respectively.

Interest Expense

Interest expense includes amortization and write off of deferred financing costs and discount on the Senior Notes in the combined amount of $7.4 million for the year ended December 31, 2012 and amortization and write off of deferred financing costs of $3.6 million, and $1.2 million, for the years ended December 31, 2011, and 2010, respectively. We capitalize interest on expenditures for significant capital asset projects that last more than six months while activities are in progress to bring the assets to their intended use. Interest of $4.4 million was capitalized during the year ended 2012. We did not capitalize interest in 2011 or 2010.

Effect of Late SEC Filings on Liquidity and Capital Resources

We are no longer able to access the capital markets using short-form registration statements or “at-the-market” offerings as a result of this annual report not having been filed within, and our Form 10-Q for the quarter ended March 31, 2013 to be filed after, the time frames permitted by the SEC. See “Risk Factors - Our failure to timely file certain periodic reports with the SEC limits our access to the public markets to raise debt or equity capital.” Our ability to access the MHR Senior Revolving Credit Facility, and for Eureka Hunter Pipeline to access the Eureka Credit Agreements, could be curtailed or eliminated if (i) we fail to file such Form 10-Q by the

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lenders' extended deadline of July 12, 2013 or within any extended time period our lenders may in the future provide us or (ii) an uncured cross-default under such facilities results from any uncured “event of default” under the indenture relating to our Senior Notes stemming from our late SEC filings. See “Risk Factors - Our existing indenture defaults restrict our ability to utilize certain exceptions to the restrictive covenants contained therein and, under certain circumstances, may result in the acceleration of the Senior Notes issued under our indenture and the outstanding debt under our credit facilities, which would have a material adverse effect on our business, financial condition and liquidity.” These adverse impacts from our late SEC filings will be reduced, to some extent, by the net proceeds we received from the Eagle Ford Properties Sale and expected net proceeds in 2013 and 2014 from sales of non-core properties.

NOTE 11 – SHARE-BASED COMPENSATION

Employees, directors and other persons who contribute to the success of Magnum Hunter are eligible for grants of common stock, common stock options, and stock appreciation rights under our amended and restated Stock Incentive Plan. At December 31, 2012, 20,000,000 shares of our common stock are authorized to be issued under the plan, and 3,683,657 shares have been issued as of December 31, 2012. On January 17, 2013, upon shareholder approval, the Magnum Hunter Resources Corporation Amended and Restated Stock Incentive Plan was amended to increase the aggregate number of shares of the Company’s common stock that may be issued under the plan from 20,000,000 to 27,500,000.

We recognized share-based compensation expense of $15.7 million, $25.1 million, and $6.4 million for the years ended December 31, 2012, 2011, and 2010 respectively.

A summary of stock option and stock appreciation rights activity for the years ended December 31, 2012, 2011, and 2010 is presented below:

	2012				2011				2010
			Weighted-Average Exercise Price				Weighted-Average Exercise Price				Weighted-Average Exercise Price
	Shares				Shares				Shares
Outstanding at beginning of period	12,566,199		$	5.64	12,779,282		$	2.65	7,117,000		$	0.93
Granted	4,978,750		$	6.00	5,601,792		$	7.74	5,892,332		$	4.70
Exercised	(1,304,050	)	$	1.54	(5,479,250	)	$	0.92	(52,500	)	$	2.05
Forfeited or expired	(1,393,905	)	$	7.14	(335,625	)	$	3.40	(177,550	)	$	1.36
Outstanding at end of period	14,846,994		$	6.01	12,566,199		$	5.64	12,779,282		$	2.65
Exercisable at end of the year	8,683,622		$	5.97	6,915,471		$	4.97	7,563,750		$	1.29

A summary of the Company’s non-vested options and stock appreciation rights as of December 31, 2012, 2011, and 2010 is presented below:

Non-vested Options	2012		2011		2010
Non-vested at beginning of period	5,650,782		5,215,532		2,340,250
Granted	4,978,750		5,601,792		5,892,332
Vested	(3,405,434	)	(4,832,417	)	(2,964,500	)
Forfeited	(1,060,726	)	(334,125	)	(52,550	)
Non-vested at end of period	6,163,372		5,650,782		5,215,532

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Total unrecognized compensation cost related to the non-vested options was $12.6 million, $9.2 million, and $10.4 million as of December 31, 2012, 2011, and 2010, respectively. The cost at December 31, 2012 is expected to be recognized over a weighted-average period of 1.64 years. At December 31, 2012, the aggregate intrinsic value for the outstanding options was $3.9 million; and the weighted average remaining contract life was 6.6.

The assumptions used in the fair value method calculations for the years ended December 31, 2012, 2011, and 2010 are disclosed in the following table:

		Year Ended December 31,
		2012	2011	2010
Weighted average fair value per option granted during the period (1)		$3.72	$4.28	$2.65
Assumptions (2) :
Weighted average stock price volatility (3)		82.64%	64.29%	79.32%
Weighted average risk free rate of return		0.77%	2.04%	1.78%
Weighted average estimated forfeiture rate (4)		—%	—%	—%
Weighted average expected term		4.51 years	6.36 years	4.24 years
(1)	Calculated using the Black-Scholes fair value based method for service and performance based grants and the Lattice Model for market based grants.
(2)	The Company has not paid cash dividends on our common stock.
(3)	The volatility assumption was estimated based upon a blended calculation of historical volatility and implied volatility over the life of the awards.
(4)	For the years 2012, 2011 and 2010, the Company estimated forfeitures to be zero based on the majority of options being granted to executive officers who are less likely to forfeit shares.

During 2012, the Company granted 69,791 fully vested shares of common stock to the Company’s board members as payment of board and committee meeting fees and chairperson retainers.

A summary of the Company’s non-vested common shares granted under the Stock Incentive Plan as of December 31, 2012, 2011, and 2010 is presented below:

	2012				2011				2010
			Weighted-Average Exercise Price				Weighted-Average Exercise Price				Weighted-Average Exercise Price
Non-vested Shares	Shares				Shares				Shares
Non-vested at beginning of year	155,049		$	4.43	300,074		$	4.43	2,310,000		$	0.44
Granted	69,791		$	4.29	40,305		$	5.45	253,930		$	5.45
Vested	(159,815	)	$	4.46	(185,330	)	$	0.47	(2,263,856	)	$	0.47
Non-vested at end of year	65,025		$	6.09	155,049		$	4.43	300,074		$	4.43

Total unrecognized compensation cost related to the above non-vested shares amounted to $0.4 million, $0.8 million, and $1.2 million as of December 31, 2012, 2011, and 2010, respectively. The unrecognized compensation cost at December 31, 2012 is expected to be recognized over a weighted-average period of 0.9 years.

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NOTE 12 - SHAREHOLDERS’ EQUITY

Common Stock

During the years ended December 31, 2012, 2011, and 2010, the Company issued 84,052, 121,143, and 2,539,317 shares, respectively, of the Company’s common stock in connection with share-based compensation which had fully vested to certain senior management and officers of the Company.

During the years ended December 31, 2012, 2011, and 2010, the Company issued 1,438,275, 6,293,107, and 7,589,154 shares of the Company’s common stock upon the exercise of warrants and options for total proceeds of approximately $2.3 million, $7.6 million, and $16.2 million, respectively.

During the year ended December 31, 2010, the Company issued 10,832,076 shares of common stock in open market transactions at an average price of $3.57 per share pursuant to an “At the Market” sales agreement (ATM) we had with our sales agent for total proceeds of approximately $38.7 million. Sales of shares of our common stock by our sales agent have been 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 an exchange or sales made through a market maker other than on an exchange. Our sales agent has made all sales using commercially reasonable efforts consistent with its normal sales and trading practices on mutually agreed upon terms between our sales agent and us.

On December 31, 2010, the Company issued 2,255,046 shares of common stock valued at approximately $17.1 million based on the closing stock price of $7.58 as consideration in the first closing of the PostRock assets acquisition.

During the years ended December 31, 2012 and 2011, the Company issued 3,188,036 and 582,127 shares of the Company’s common stock, respectively, upon exchange of exchangeable shares issued by MHR Exchangeco Corporation in connection with the Company’s acquisition of NuLoch Resources, Inc. in May 2011.

During the year ended December 31, 2011, the Company issued 1,713,598 shares of common stock in open market transactions at an average price of $8.27 per share pursuant to an ATM sales agreement as described above, for total new proceeds of approximately $13.9 million.

On January 14, 2011, the Company issued 946,314 shares of common stock valued at approximately $7.5 million based on a closing stock price of $7.97 as consideration in the second closing of the PostRock assets acquisition.

On April 13, 2011, the Company issued 6,635,478 shares of common stock valued at approximately $53.0 million based on a closing stock price of $7.99 as consideration in the closing of the acquisition of NGAS. In connection with the NGAS acquisition, the Company issued 350,626 shares of common stock valued at approximately $2.8 million to NGAS employees as change in control payments.

On May 3, 2011, the Company issued 38,131,846 shares of common stock valued at approximately $282.2 million based on a closing stock price of $7.40 as consideration in the closing of the acquisition of NuLoch.

On March 30, 2012, the Company issued 296,859 restricted shares of the Company’s common stock valued at approximately $1.9 million based on a price of $6.41 per share as partial consideration for the acquisition of the assets of Eagle Operating. 

On May 16, 2012, the Company issued 35,000,000 shares of the Company’s common stock in an underwritten public offering at a price of $4.50 per share for total proceeds of $157.5 million.  The net proceeds of the offering, after deducting underwriting discounts and commissions and offering expenses, were approximately $148.2 million.

On August 20, 2012, the Company issued an aggregate of 199,055 shares of the Company’s common stock as "safe harbor" and discretionary matching contributions to the Magnum Hunter Resources Corporation 401(k) Employee Stock Ownership Plan (the "KSOP" or the "Plan"). The Plan was established effective October 1, 2010 as a defined contribution plan. At the discretion of the Board of Directors, the Company may elect to contribute discretionary contributions to the Plan either as profit sharing contributions or as employee stock ownership plan contributions. It is the intent of the Company to review and make discretionary contributions to the Plan in the future, however, the Company has no further obligation to make future contributions to the Plan as of December 31, 2012, except for statutorily required "safe harbor" matching contributions.

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Unearned Common Stock in Magnum Hunter Resources Corporation 401(k) Employee Stock Ownership Plan

On August 13, 2012, the Company rescinded the loan of 153,300 Magnum Hunter common shares to the Company's KSOP and the common shares were returned to the Company and held in treasury at cost of $3.94 per share. The loan was rescinded to correct a mutual mistake by the parties in connection with the Company’s original acquisition of the shares through open market purchases. The Company has agreed that 153,300 shares of the Company’s common stock will either be (i) offered for sale to the participants in the Plan at a price not to exceed the lesser of $3.94 per share (the basis of these treasury shares) or the fair market value of the shares on the date of the sale, or (ii) contributed to the Plan as one or more discretionary matching contributions.  Such sale or contribution shall be made at such time or times as determined by the trustee of the Plan, except to the extent that the Company elects prior to that time to contribute all or a part of such shares as a discretionary matching contribution.

Exchangeable Common Stock

On May 3, 2011, in connection with the acquisition of NuLoch, the Company issued 4,275,998 exchangeable shares of MHR Exchangeco Corporation, which are exchangeable for shares of the Company at a one for one ratio. The shares of MHR Exchangeco Corporation were valued at approximately $31.6 million. Each exchangeable share is exchangeable for one share of our common stock at any time after issuance at the option of the holder and will be redeemable at the option of the Company, through Exchangeco, after one year or upon the earlier of certain specified events. During the year ended December 31, 2012 and 2011, 3,188,036 and 582,127, respectively, of the exchangeable shares have been exchanged for common shares of the Company. As of December 31, 2012, 505,835 exchangeable shares were outstanding.

Common Stock Warrants

During 2006, the Company issued 871,500 warrants to purchase an equal number of shares of the Company’s common stock at an exercise price of $3.00 per share in conjunction with private placement sales of common stock.  The warrants had a term of five years from the date of issuance.  The Company also issued 326,812 warrants to purchase an equal number of shares of the Company’s common stock at an exercise price of $3.00 per share along with a cash payment for commission fees.

In association with common stock sales on November 5, 2009, the Company issued 457,982 common stock warrants. Each warrant issued to a purchaser had a term of 3 years and (i) was exercisable for one share of the Company's common stock at any time after the shares of common stock underlying the warrant are registered with the SEC for resale pursuant to an effective registration statement, which was June 12, 2010, (ii) had a cash exercise price of $2.50 per share of the Company's common stock, and (iii) upon notice to the holder of the warrant, was redeemable by the Company for $0.01 per share of the Company's common stock underlying the warrant if (a) the registration statement as filed with the SEC is effective and (b) the average trading price of the Company's common stock as traded and quoted on the NYSE Amex equals or exceeds $3.75 per share for at least 20 days in any period of 30 consecutive days.

On November 16, 2009, the Company issued 1,280,744 common stock warrants. The warrants, which represent the right to acquire an aggregate of up to 1,280,744 common shares, were exercisable at any time on or after May 17, 2010 and had a term of 3 years, at an exercise price of $2.50 per share, which was 145% of the closing price of the Company's common shares on the NYSE Amex on November 11, 2009. These warrants were exercised during the years 2010, 2011, 2012.

On April 13, 2011, at the time of the NGAS acquisition, NGAS had 4,609,038 warrants outstanding which were converted, based on the exchange ratio of 0.0846, to 389,924 warrants exercisable for Magnum Hunter common stock. The warrants had a cash-out option, which remained available to the holder for 30 days from the date of the acquisition, based on fair market value of the warrants at April 13, 2011. The Company paid cash of $1.0 million upon exercise of the cash-out option on the warrants exercisable for 251,536 shares of the Company’s common stock. At December 31, 2012, common stock warrants exercisable for 138,388 shares of the Company’s common stock were outstanding. The warrants consist of 97,780 warrants with an exercise price of $15.13 which expire February 13, 2014 and 40,608 warrants with an exercise price of $19.04 which expire November 17, 2014.

On August 13, 2011, the Company declared a dividend to be paid in the form of one common stock warrant for every ten shares held by holders of record of our common stock and exchangeable shares of MHR Exchangeco Corporation on August 31, 2011. The Company issued 12,875,093 common stock warrants to common stock holders and 378,174 warrants to holders of MHR Exchangeco Corporation exchangeable shares. Each warrant entitles the holder to purchase one share of the Company’s common stock for an initial exercise price of $10.50 and expires on October 14, 2013. The fair market value of the warrants was $6.9 million. The warrants were accounted for in additional paid-in capital rather than as a reduction of retained earnings because the Company has an accumulated deficit position.

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During the year ended December 31, 2010, 251,500 of our $3.00 common stock warrants, 1,562,504 of our $2.50 common stock warrants, and 5,722,650 of our $2.00 common stock warrants were exercised for total combined proceeds of approximately $16.1 million, and 78,000 of our $2.00 common stock warrants expired.

During the year ended December 31, 2011, 771,812 of our $3.00 common stock warrants and 42,045 of our $2.50 common stock warrants were exercised for total combined proceeds of approximately $2.4 million, and 15,000 of our $3.00 common stock warrants expired.

During the year ended December 31, 2012, 48 of our $10.50 common stock warrants and 134,177 of our $2.50 common stock warrants were exercised for total combined proceeds of approximately $328,000, and 15,330 of our $10.50 common stock warrants were canceled upon the rescission of the 153,300 Magnum Hunter common shares loaned to the Company's KSOP.

 A summary of warrant activity for the years ended December 31, 2012, 2011, and 2010 is presented below:

	2012				2011				2010
			Weighted -				Weighted -				Weighted -
			Average				Average				Average
	Shares		Exercise Price		Shares		Exercise Price		Shares		Exercise Price
Outstanding at beginning of year	13,525,832		$	10.48	963,034		$	2.91	8,577,688		$	2.15
Granted	—		$	—	13,391,655		$	10.56	—		$	—
Exercised, forfeited, or expired	(149,555	)	$	3.32	(828,857	)	$	2.97	(7,614,654	)	$	2.14
Outstanding at end of year	13,376,277		$	10.56	13,525,832		$	10.48	963,034		$	2.91
Exercisable at end of year	13,376,277		$	10.56	13,525,832		$	10.48	963,034		$	2.91

At December 31, 2012, the warrants had no aggregate fair value; and the weighted average remaining contract life was 0.8 years.

Series D Preferred Stock

During the year ended December 31, 2011, the Company sold 1,437,558 shares of our 8.0% Series D Cumulative Preferred Stock, par value $0.01 per share and liquidation preference of $50.00 per share, of which 400,000 were sold in an underwritten offering and 1,037,558 were sold under the ATM sales agreement, for net proceeds of $65.7 million. The Series D Preferred Stock cannot be converted into common stock of the Company but may be redeemed by the Company, at the Company’s option, on or after March 14, 2014 for par value or $50.00 per share or in certain circumstances prior to such date as a result of a change in control of the Company. Dividends accrue and are payable monthly on the Series D Preferred Stock at a fixed rate of 8.0% per annum of the $50.00 per share liquidation preference.

During the year ended December 31, 2012, the Company issued an aggregate of 2,771,263 shares of our 8.0% Series D Cumulative Preferred Stock with a liquidation preference of $50.00 per share for cumulative net proceeds of approximately $122.5 million, which included various offering expenses of approximately $3.1 million. The 2,771,263 shares of our 8.0% Series D Cumulative Preferred Stock issued during the year ended December 31, 2012 included (i) 1,721,263 shares issued under an ATM sales agreement for net proceeds of approximately $77.9 million, which included approximately $1.5 million of offering and underwriting fees and (ii) 1,050,000 shares issued pursuant to an underwritten public offering on September 7, 2012 at a price of $44.00 per share for net proceeds of approximately $44.6 million, which included approximately $1.6 million of underwriting discounts, commissions and offering expenses. 

Series E Preferred Stock

Each share of Series E Preferred Stock, par value $0.01 per share, has a stated liquidation preference of $25,000 and a dividend rate of 8.0% per annum (based on stated liquidation preference), is convertible at the option of the holder into a number of shares of the Company’s common stock equal to the stated liquidation preference (plus accrued and unpaid dividends) divided by a conversion price of $8.50 per share (subject to anti-dilution adjustments in the case of stock dividends, stock splits and combinations of shares), and is redeemable by the Company under certain circumstances.  The Series E Preferred Stock is junior to the Company’s 10.25% Series C Cumulative Perpetual Preferred Stock and 8.0% Series D Cumulative Preferred Stock in respect of dividends and distributions upon liquidation.  Each Depositary Share is a 1/1000th interest in a share of Series E Preferred Stock.  Accordingly, the Depositary Shares have a stated liquidation preference of $25.00 per share and a dividend rate of 8.0% per annum (based on stated liquidation preference), are similarly convertible at the option of the holder into a number of shares of the Company’s common stock equal to

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the stated liquidation preference (plus accrued and unpaid dividends) divided by a conversion price of $8.50 per share (subject to corresponding anti-dilution adjustments), and are redeemable by the Company under certain circumstances.

In November 2012, the Company issued 2,704,850 Depositary Shares, each representing a 1/1,000th interest in a share of the Company’s 8% Series E Cumulative Convertible Preferred Stock, liquidation preference $25,000 per share, to the shareholders of Virco as partial consideration for the Company’s purchase of 100% of the outstanding stock of Virco. The Company also issued 70,000 Depositary Shares into an escrow account which were returned and held in treasury at cost of $1.8 million upon an indemnification settlement in favor of the Company.

In December 2012, the Company sold in a public offering an aggregate of 1,000,000 Depositary Shares, each representing a 1/1,000th  interest in a share of the Company’s 8% Series E Cumulative Convertible Preferred Stock, liquidation preference $25,000 per share.  The Depositary Shares were sold to the public at a price of $23.50 per Depositary Share, and the net proceeds to the Company were $22.4425 per Depositary Share after deducting underwriting commissions, but before deducting expenses related to the offering. 

Non-controlling Interests

During the year ended December 31, 2012, the Company purchased outstanding non-controlling interest in a subsidiary which the Company did not previously own.  The Company acquired the non-controlling interest valued at $497,000 based on fair value at the date of acquisition.

In connection with a Williston Basin acquisition in 2008, the Company entered into equity participation agreements with certain of its lenders pursuant to which the Company agreed to pay to the lenders an aggregate of 12.5% of all distributions paid to the owners of PRC Williston, which equity participation agreements, for accounting purposes, are treated as non-controlling interests in PRC Williston, and consequently, PRC Williston is treated as a majority owned subsidiary of the Company and is consolidated by the Company. The equity participation agreements had a fair value of $3.4 million upon issuance and were accounted for as a non-controlling interest in PRC Williston.

On April 2, 2012, Eureka Hunter Holdings, a majority owned subsidiary, issued 622,641 Class A Common Units representing membership interests in Eureka Hunter Holdings, with a value of $12.5 million, as partial consideration for the assets acquired from TransTex.  The value of the units transferred as partial consideration for the acquisition was determined utilizing a discounted future cash flow analysis. The carrying value of the Eureka Hunter Holdings Class A Common Units held by third parties is classified as non-controlling interest.

A summary of non-controlling interests in the Company for the years ended December 31, 2012, 2011, and 2010 is presented below:

	2012			2011		2010
	(in thousands)
Non-controlling interest at beginning of period	$	2,196		$	1,450	$	1,321
Non-controlling interests acquired through acquisition of NGAS	—			497		—
Purchase of outstanding non-controlling interests	(497		)	—		—
Issuance of shares of Eureka Hunter Holdings, LLC Common Units	12,453			—		—
Income (loss) attributable to non-controlling interest	(4,013		)	249		129
Non-controlling interest at end of period	$	10,139		$	2,196	$	1,450

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Preferred Dividends Paid

A summary of dividends paid by the Company for the years ended December 31, 2012, 2011, and 2010 is presented below:

	2012			2011			2010
	(in thousands)
Dividend on Eureka Hunter Holdings, LLC Series A Preferred Units	$	(8,090	)	$	—		$	—
Dividend on Series B Preferred Stock	—			—			(131		)
Dividend on Series C Preferred Stock	(10,248		)	(10,248		)	(2,336		)
Dividend on Series D Preferred Stock	(11,699		)	(3,759		)	—
Dividend on Series E Preferred Stock	(894		)	—			—
Total dividends on Preferred Stock	$	(30,931	)	$	(14,007	)	$	(2,467	)

Accretion of the difference between the carrying value and the redemption value of the Eureka Hunter Holdings, Series A Preferred Units of $3.8 million for the year ended December 31, 2012, and none for the years ended December 31, 2011, and 2010, was included in dividends on preferred stock.

NOTE 13 - REDEEMABLE PREFERRED STOCK

Series C Preferred Stock

On December 13, 2009, the Company sold 214,950 shares of our 10.25% Series C Cumulative Perpetual Preferred Stock, par value $0.01 per share and liquidation preference $25.00 per share (the “Series C Preferred Stock”), for net proceeds of $5.1 million. The Series C Preferred Stock cannot be converted into common stock of the Company, but may be redeemed by the Company, at the Company’s option, on or after December 14, 2011 for par value or $25.00 per share.  In the event of a change of control of the Company, the Series C Preferred Stock will be redeemable by the holders at $25.00 per share, except in certain circumstances when the acquirer is considered a qualifying public company. Dividends accrue and are payable monthly on the Series C Preferred Stock at a fixed rate of 10.25% per annum of the $25.00 per share liquidation preference.

During the year ended December 31, 2010, the Company sold 2,594,506 shares of the Series C Preferred Stock under our ATM sales agreement for net proceeds of $63.4 million.

During the year ended December 31, 2011, the Company sold 1,190,544 shares of our 10.25% Series C Cumulative Perpetual Preferred Stock under our ATM sales agreement for net proceeds of $29.1 million. The sales during the year ended December 31, 2011 have fully subscribed the authorized 4,000,000 shares of Series C Preferred Stock. The Series C Preferred Stock is recorded as temporary equity because a forced redemption, upon certain circumstances as a result of a change in control of the Company, is outside the Company’s control.

Eureka Hunter Holdings, LLC Series A Preferred Units

On March 21, 2012, Eureka Hunter Holdings entered into a Series A Convertible Preferred Unit Purchase Agreement (the “Unit Purchase Agreement”) with Magnum Hunter and Ridgeline Midstream Holdings, LLC (“Ridgeline”), an affiliate of ArcLight Capital Partners, LLC. Pursuant to this Unit Purchase Agreement, Ridgeline committed, subject to certain conditions, to purchase up to $200 million of Series A Convertible Preferred Units representing membership interests of Eureka Hunter Holdings (the “Series A Preferred Units”).

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During the year ended December 31, 2012, Eureka Hunter Holdings issued 7,590,000 Series A Preferred Units to Ridgeline for net proceeds of $148.6 million, net of transaction costs.  The Series A Preferred Units outstanding at December 31, 2012 represented 36.5% of the ownership of Eureka Hunter Holdings on a basis as converted to Class A Common Units of Eureka Hunter Holdings and represent non-controlling interests in the form of redeemable preferred stock of a subsidiary in consolidation of the Company.  Eureka Hunter Holdings pays cumulative distributions quarterly on the Series A Preferred Units at a fixed rate of 8% per annum of the initial liquidation preference.  The distribution rate is increased to 10% if any distribution is not paid when due.  The board of directors of Eureka Hunter Holdings may elect to pay up to 75% of the distributions owed for the period from March 21, 2012 through March 31, 2013 in the form of “paid-in-kind” units and may elect to pay up to 50% of the distributions owed for the period from April 1, 2013 through March 31, 2014 in such units.  The Series A Preferred Units can be converted into Class A Common Units of Eureka Hunter Holdings upon demand by Ridgeline at any time or by Eureka Hunter Holdings upon the consummation of a qualified initial public offering, provided that Eureka Hunter Holdings converts no less than 50% of the Series A Preferred Units into Class A Common Units at that time.  The conversion rate is 1:1, which may be adjusted from time to time based upon certain anti-dilution and other provisions.  Eureka Hunter Holdings can redeem all outstanding Series A Preferred Units at their liquidation preference, which involves a specified IRR hurdle, any time after March 21, 2017.  Holders of the Series A Preferred Units can force redemption of all outstanding Series A Preferred Units any time after March 21, 2020, at a redemption rate equal to the higher of the as-converted value and a specified internal investment rate of return calculation.  The Series A Preferred Units are recorded as temporary equity because a forced redemption by the holders of the preferred units is outside the control of Eureka Hunter Holdings.

We have evaluated the Series A Preferred Units and determined that they should be considered a “debt host” and not an “equity host”. This evaluation is necessary to determine if any embedded features require bifurcation and, therefore, would be required to be accounted for separately as a derivative liability. Our analysis followed the “whole instrument approach,” which compares an individual feature against the entire preferred instrument that includes that feature. Our analysis was based on a consideration of the economic characteristics and risks of the preferred unit and, more specifically, evaluated all of the stated and implied substantive terms and features of such unit, including (1) whether the preferred unit included redemption features; (2) how and when any redemption features could be exercised; (3) whether the holders of preferred units were entitled to dividends; (4) the voting rights of the preferred unit; and (5) the existence and nature of any conversion rights. As a result of our determination that the preferred unit is a “debt host,” we determined that the embedded conversion option, redemption options and other features of the preferred units do require bifurcation and separate accounting as embedded derivatives. The fair value of the embedded features were determined to be $22.1 million, $15.4 million, $7.9 million, and $6.3 million at the issuance dates of March 21, 2012, April 2, 2012, June 20, 2012, and October 19, 2012, respectively, which were bifurcated from the issuance values of the Series A Preferred Units and presented in long term liabilities. The fair value of this embedded feature was determined to be $43.5 million and $0 in the aggregate at December 31, 2012 and 2011, respectively. See "Note 4 - Fair Value of Financial Instruments" for additional information.

During the year ended December 31, 2012, the Company paid cash distributions of $3.4 million and accrued distributions of $3.0 million not yet paid, to the holder of our Series A Preferred Units. During such year, distributions in the amount of $1.7 million were paid-in-kind to the holder of the Series A Preferred Units and the Company issued 82,892 Series A Preferred Units as payment. At December 31, 2012, 7,672,892 shares of Series A Preferred Units were outstanding.

NOTE 14 - INCOME TAXES

The total provision for income taxes applicable to continuing operations consists of the following:

	Year Ended December 31,
	2012				2011			2010
	(in thousands)
Current income tax expense (benefit)
Various states	$	—			$	—		$	—
Total current tax expense (benefit)	$	—			$	—		$	—
Deferred income tax expense (benefit)
U.S. federal	(14,272		)	)	(513		)	—
Various states	(517		)		(60		)	—
Canada and various provinces	(8,227		)		(123		)	—
Total deferred tax expense (benefit)	$	(23,016	)		$	(696	)	$	—
Total income tax expense (benefit)	$	(23,016	)		$	(696	)	$	—

At December 31, 2012, the Company has available for U.S. federal income tax reporting purposes, net operating loss carry forwards ("NOL's") of approximately $473 million, (tax effected $178 million) which expire in varying amounts during the tax years 2018 through 2032. The Company has two (2) separate U.S. corporate filing entities. In addition, the Company files in various State taxing

F-46

jurisdictions. The Company also has an NOL relating to the Canadian operations of approximately $58 million (tax effected $15 million ), which expire in varying amounts between years 2015 through 2032. The U.S. NOL above includes $20 million of deductions for excess stock-based compensation. The Company will recognize the NOL tax assets associated with excess stock-based compensation tax deductions only when all other components of the NOL tax assets have been fully utilized and a cash tax benefit is realized. Upon realization, the excess stock-based compensation deduction will reduce taxes payable and will be credited directly to equity.

Internal Revenue Code ("IRC") Section 382 imposes limitations on a corporation's ability to utilize its NOL carryforwards in the tax years following an "ownership change". For this purpose, an ownership change results from stock transactions that increase the ownership of certain existing and new stockholders in the corporation by more than 50 percentage points during the previous three-year testing period. Approximately $44 million ($16 million tax effected) of our NOL relates to corporate acquisitions and the utilization of that portion of the NOL is limited on an annual basis under section 382.

Canada Revenue Agency also provides limitations on the utilization of NOL's from acquired companies. Under applicable statutes, the Company believes approximately $15 million (tax effected $3.7 million) will be subject to limitations and will on a more likely than not basis never be utilized. The company maintains a full valuation allowance against the $15 million it believes will be limited under the statute.

At December 31, 2012, the Company was not under examination by any federal or state taxing juristiction, nor had the Company been contacted by any examining agency.

The Company has approximately $2.6 million (tax effected $1.0 million) of depletion carryover which has no expiration.

The Company has no unremitted earnings in Canada.

The Company has recorded a valuation allowance of $188 million (tax effected $69 million) against the net deferred tax assets of the Company at December 31, 2012. The Company is uncertain on a more likely than not basis that the NOL and other deferred tax assets will be utilized in the future. Management evaluated all available positive and negative evidence in making this assessment. The assessment included objectively verifiable information such as historical operating results, future projections of operating results, future reversals of existing taxable temporary differences and anticipated capital expenditures. Management placed a significant amount of weight on the historical results. The Company closed on the sale of Eagle Ford Shale properties in April 2013. While the Company anticipates the recognition of both book and taxable income from the transaction, given future projections of operating results for 2013 and the Company's capital expenditure budget for 2013, management believes it is not more likely than not that the Company will realize the benefit of NOL's in 2013. Further, because the transaction was a fundamental transaction of core assets for the Company, occurring subsequent to the year-end beyond the Company's original filing deadline for this annual report, management believes the availability of such evidence arising from the transaction is outside of the scope of evidence that should be considered in its assessment of the need for a valuation allowance at December 31, 2012.

The following is a reconciliation of the reported amount of income tax expense (benefit) attributable to continuing operations for the years ended December 31, 2012, 2011, and 2010 to the amount of income tax expense that would result from applying domestic federal statutory tax rates to pretax income:

	Year Ended December 31,
	2012			2011			2010
	(in thousands)
Income tax expense (benefit) at statutory U.S. rate	$	(56,831	)	$	(26,301	)	$	(5,520	)
State income taxes	(3,708		)	(4,641		)	0
Effect of permanent differences	(555		)	419			386
Foreign statutory tax rate differences	3,324			315			—
Tax effect of non-controlled	797			—			—
Other	7			—			—
Change in valuation allowance	33,950			29,512			5,134
Total continuing operations	(23,016		)	(696		)	0
Discontinued operations	1,421			—			—
Total tax expense (benefit)	$	(21,595	)	$	(696	)	$	0

F-47

Income (loss) before income taxes was as follows:

	Year Ended December 31,
	2012			2011			2010
	(in thousands)
Domestic	$	(129,136	)	$	(77,623	)	$	(22,681	)
Foreign	(33,240		)	(2,462		)	—
Income (loss) from continuing operations	(162,376		)	(80,085		)	(22,681		)
Income (loss) from discontinued operations	4,060			2,977			9,010
Loss before income tax	$	(158,316	)	$	(77,108	)	$	(13,671	)

Deferred Tax Assets and Liabilities

The tax effects of temporary differences that gave rise to the Company's deferred tax assets and liabilities are presented below:

	Year Ended December 31,
	2012			2011			2010
	(in thousands)
Deferred tax assets:
Net operating loss carry forwards	$	193,310		$	62,923		$	21,520
Share-based compensation	7,950			10,247			3,091
Depletion carryforwards	997			972			972
Tax credits	53			26,340			—
Other	532			7,475			1,691
Deferred tax liabilities:
Property and equipment	(206,650		)	(111,015		)	(3,685		)
Valuation allowances
Tax credits	(53		)	(26,340		)	—
Depletion carryforwards	(997		)	(972		)	—
Net operating losses	(69,400		)	(51,523		)	(23,589		)
Other				$	(13,406	)
Net deferred tax	$	(74,258	)	$	(95,299	)	$	—

Net deferred tax assets (liabilities) are allocated between current and non-current as follows:

	Year Ended December 31,
	2012			2011
	(in thousands)
Current deferred tax asset (liability)	$	—		$	—
Non-current deferred tax asset (liability)	(74,258		)	(95,299		)
Net deferred tax asset (liability) after valuation allowance	$	(74,258	)	$	(95,299	)

As of December 31, 2012 we provided for a liability of $3.9 million for unrecognized tax benefits related to various federal tax matters, which were netted against the Company's net operating loss. Settlement of the uncertain tax position is expected to occur in the next 12 months and will have no effect on income tax expense (benefit) given the Company's valuation allowance position. We have elected to classify interest and penalties related to uncertain income tax positions in income tax expense. As of December 31, 2012, we have accrued no amounts for potential payment of interest and penalties.

F-48

Following is a reconciliation of the total amounts of unrecognized tax benefits during the years ended December 31, 2012, 2011 and 2010:

	Year Ended December 31,
	2012	2011	2010
	(in thousands)
Unrecognized tax benefits at January 1	—	—	—
Change in unrecognized tax benefits taken during a prior period	—	—	—
Change in unrecognized tax benefits taken during the current period (netted against the US net operating loss)	3,879	—	—
Decreases in unrecognized tax benefits from settlements with taxing authorities	—	—	—
Reductions to unrecognized tax benefits from lapse of statutes of limitations	—	—	—
Unrecognized tax benefits at December 31	3,879	—	—

NOTE 15 – MAJOR CUSTOMERS

The Company's share of oil and gas production is sold to various purchasers who must be prequalified under the Company's credit risk policies and procedures. The following purchasers individually accounted for ten percent or more of the Company's consolidated continuing oil and gas revenues in at least one of the three years ended December 31, 2012. The loss of any one significant purchaser could have a material, adverse effect on the ability of the Company to sell its oil and gas production. Although we are exposed to a concentration of credit risk, we believe that all of our purchasers are credit worthy.

The table below provides the percentages of the Company's consolidated oil, NGL and gas revenues represented by our major purchasers during the periods presented:

	Year Ended December 31,
	2012		2011		2010
Shell	19	%	11	%	—	%
Trafigura	16	%	9	%	—	%
Gulfmark Energy, Inc.	15	%	9	%	—	%
DPI	6	%	10	%	—	%
Plains Marketing, LP	5	%	16	%	33	%
Clearfield Energy	3	%	8	%	23	%
Ergon Oil	2	%	7	%	19	%

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NOTE 16 – OTHER INFORMATION

Quarterly Data (Unaudited)

The following tables set forth unaudited summary financial results on a quarterly basis for the most recent two years. The results for the quarter ended June 30, 2012, have been restated on Form 10-Q/A.

	(in thousands)
	Quarter Ended
	March 31,			June 30,			September 30,			December 31,			Year Ended
	2012
	(in thousands)
Total revenue	$	57,196		$	60,300		$	69,770		$	83,705		$	270,971
Loss from operations (1)	$	(11,549	)	$	(16,005	)	$	(9,739	)	$	(97,752	)	$	(135,045	)
Income from discontinued operations, net of tax	$	230		—			—			—			$	230
Gain on sale of discontinued operations, net of tax	$	2,409		—			—			—			$	2,409
Net loss attributable to Magnum Hunter Resources Corporation	$	(12,458	)	$	(14,503	)	$	(32,463	)	$	(73,284	)	$	(132,708	)
Net loss attributable to common shareholders	$	(17,052	)	$	(22,708	)	$	(42,283	)	$	(85,371	)	$	(167,414	)
Basic and diluted loss per common share	$	(0.13	)	$	(0.15	)	$	(0.25	)	$	(0.54	)	$	(1.07	)
	2011
Total revenue	$	14,537		$	29,532		$	28,055		$	41,556		$	113,680
Loss from operations	$	(2,795	)	$	(15,208	)	$	(14,004	)	$	(31,376	)	$	(63,383	)
Income from discontinued operations, net of tax	$	260		$	1,220		$	682		$	815		$	2,977
Net loss attributable to Magnum Hunter Resources Corporation	$	(6,690	)	$	(15,040	)	$	2,000		$	(56,931	)	$	(76,661	)
Net loss attributable to common shareholders	$	(9,298	)	$	(18,497	)	$	(1,952	)	$	(60,921	)	$	(90,668	)
Basic and diluted loss per common share	$	(0.12	)	$	(0.16	)	$	(0.02	)	$	(0.50	)	$	(0.80	)

See "Oil and Gas Properties -Capitalized Costs" and "Exploration and Abandonment Costs," in "Note 3 - Summary of Significant Accounting Policies" for a discussion of proved and unproved property impairments.

^1.  The quarter-ended December 31, 2012, loss from operations was primarily driven by exploration and abandonment expense. Management reviews leasehold acreage on a quarterly basis. During the quarter-ended December 31, 2012 management determined a significant portion of the non-core Williston Basin acreage would not be utilized as the Company planned to focus on assets that will provide a higher rate of return in 2013.

F-50

Segment Reporting

The following tables set forth operating activities by segment for the years ended December 31, 2012, 2011, and 2010.

	For the Year Ended December 31, 2012 (in thousands)
	U.S. Upstream			Canadian Upstream			Midstream			Oil Field Services			Corporate Unallocated			Intersegment Eliminations			Total
Oil and gas sales	$	205,838		$	39,556		$	—		$	—		$	—		$	—		$	245,394
Gas transportation, gathering and processing	—			—			15,469			—			—			(2,429		)	13,040
Oil field services	—			—			—			13,552			—			(1,219		)	12,333
Gain (loss) on sale of assets and other revenue	363			(35		)	473			(600		)	—			3			204
Total revenue	206,201			39,521			15,942			12,952			—			(3,645		)	270,971
Lease operating expenses	49,786			5,163			—			—			—			(3,590		)	51,359
Severance taxes and marketing	12,675			2,371			—			—			—			—			15,046
Exploration and abandonments	80,375			36,841			—			—			—			—			117,216
Gas transportation, gathering and processing	—			—			7,908			—			—			120			8,028
Oil field services	—			—			—			10,420			—			(383		)	10,037
Impairment of proved oil and gas properties	3,839			257			—			—			—			—			4,096
Depreciation, depletion, and accretion	100,987			27,461			5,963			967			—			468			135,846
General and administrative	30,680			2,043			3,798			418			27,137			312			64,388
Total expenses	278,342			74,136			17,669			11,805			27,137			(3,073		)	406,016
Operating income (loss)	(72,141		)	(34,615		)	(1,727		)	1,147			(27,137		)	(572		)	(135,045		)
Interest income	200			3,096			—			—			3,483			(6,549		)	230
Interest expense	(13,282		)	(1,724		)	(758		)	(327		)	(41,022		)	5,267			(51,846		)
Gain on derivative contracts	129			—			8,692			—			13,418			—			22,239
Other	2,745			2			(546		)	(155		)	—			—			2,046
Total other income (expense)	(10,208		)	1,374			7,388			(482		)	(24,121		)	(1,282		)	(27,331		)
Income (loss) from continuing operations before income tax	(82,349		)	(33,241		)	5,661			665			(51,258		)	(1,854		)	(162,376		)
Income tax benefit	14,797			8,219			—			—			—			—			23,016
Loss from continuing operations	(67,552		)	(25,022		)	5,661			665			(51,258		)	(1,854		)	(139,360		)
Income from discontinued operations	—			—			—			230			—			—			230
Gain on sale of discontinued operations	2,409			—			—			—			—			—			2,409
Net income (loss)	(65,143		)	(25,022		)	5,661			895			(51,258		)	(1,854		)	(136,721		)
Loss (income) attributable to non-controlling interest	4,173			—			(160		)	—			—			—			4,013
Net income (loss) attributable to Magnum Hunter Resources Corporation	$	(60,970	)	$	(25,022	)	$	5,501		$	895		$	(51,258	)	$	(1,854	)	$	(132,708	)
Dividends on preferred stock	—			—			(11,864		)	—			(22,842		)	—			(34,706		)
Net income (loss) attributable to common shareholders	$	(60,970	)	$	(25,022	)	$	(6,363	)	$	895		$	(74,100	)	$	(1,854	)	$	(167,414	)
Total segment assets	$	1,602,022		$	392,918		$	245,207		$	23,810		$	93,612		$	(158,937	)	$	2,198,632
Segment capital expenditures	$	417,431		$	84,536		$	57,010		$	8,828		$	805		$	—		$	568,610

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	For the Year Ended December 31, 2011 (in thousands)
	U.S. Upstream			Canadian Upstream			Midstream			Oil Field Services			Corporate Unallocated			Intersegment Eliminations			Total
Oil and gas sales	$	95,474		$	10,731		$	—		$	—		$	—		$	—		$	106,205
Gas transportation, gathering and processing	—			—			1,978			—			—			(1,484		)	494
Oil field services	—			—			—			9,417			—			(2,268		)	7,149
Gain (loss) on sale of assets and other revenue	(726		)	36			513			9			—			—			(168		)
Total revenue	94,748			10,767			2,491			9,426			—			(3,752		)	113,680
Lease operating expenses	26,738			1,813			—			—			—			(2,196		)	26,355
Severance taxes and marketing	6,887			588			—			—			—			—			7,475
Exploration and abandonments	2,605			40			—			—			—			—			2,645
Gas transportation, gathering and processing	—			—			373			—			—			—			373
Oil field services	—			—			—			8,315			—			(1,556		)	6,759
Impairment of proved oil and gas properties	21,792			—			—			—			—			—			21,792
Depreciation, depletion, and accretion	40,374			6,055			1,789			544			—			—			48,762
General and administrative	8,883			1,914			850			461			50,794			—			62,902
Total expenses	107,279			10,410			3,012			9,320			50,794			(3,752		)	177,063
Operating income (loss)	(12,531		)	357			(521		)	106			(50,794		)	—			(63,383		)
Interest income	15			2,062			—			—			4			(2,054		)	27
Interest expense	(2,315		)	13			(1,674		)	(183		)	(9,879		)	2,054			(11,984		)
Loss on derivative contracts	—			—			—			—			(6,346		)	—			(6,346		)
Other	1,606			(5		)	—			—			—			—			1,601
Total other income (expense)	(694		)	2,070			(1,674		)	(183		)	(16,221		)	—			(16,702		)
Income (loss) from continuing operations before income tax	(13,225		)	2,427			(2,195		)	(77		)	(67,015		)	—			(80,085		)
Income tax benefit	571			125			—			—			—			—			696
Loss from continuing operations	(12,654		)	2,552			(2,195		)	(77		)	(67,015		)	—			(79,389		)
Income from discontinued operations	—			—			—			2,977			—			—			2,977
Net income (loss)	(12,654		)	2,552			(2,195		)	2,900			(67,015		)	—			(76,412		)
Net income attributable to non-controlling interest	(249		)	—			—			—			—			—			(249		)
Net income (loss) attributable to Magnum Hunter Resources Corporation	(12,903		)	2,552			(2,195		)	2,900			(67,015		)	—			(76,661		)
Dividends on preferred stock	—			—			—			—			(14,007		)	—			(14,007		)
Net income (loss) attributable to common shareholders	$	(12,903	)	$	2,552		$	(2,195	)	$	2,900		$	(81,022	)	$	—		$	(90,668	)
Total segment assets	$	797,674		$	349,410		$	83,847		$	17,045		$	47,839		$	(127,055	)	$	1,168,760
Segment capital expenditures	$	202,818		$	18,493		$	54,748		$	6,494		$	9,389		$	—		$	291,942

F-52

	For the Year Ended December 31, 2010 (in thousands)
	U.S. Upstream			Canadian Upstream		Midstream		Oil Field Services			Corporate Unallocated			Intersegment Eliminations			Total
Oil and gas sales	$	27,715		$	—	$	—	$	—		$	—		$	—		$	27,715
Gas transportation, gathering and processing	—			—		334		—			—			(171		)	163
Oil field services	—			—		—		3,388			—			(2,166		)	1,222
Gain (loss) on sale of assets and other revenue	168			—		80		2			—			—			250
Total revenue	27,883			—		414		3,390			—			(2,337		)	29,350
Lease operating expenses	10,877			—		—		—			—			(190		)	10,687
Severance taxes and marketing	2,381			—		—		—			—			—			2,381
Exploration and abandonments	942			—		—		—			—			—			942
Gas transportation, gathering and processing	—			—		214		—			—			—			214
Oil field services	—			—		—		3,419			—			(2,147		)	1,272
Impairment of proved oil and gas properties	306			—		—		—			—			—			306
Depreciation, depletion, and accretion	8,347			—		45		364			—			—			8,756
General and administrative	1,724			—		71		143			22,835			—			24,773
Total expenses	24,577			—		330		3,926			22,835			(2,337		)	49,331
Operating income (loss)	3,306			—		84		(536		)	(22,835		)	—			(19,981		)
Interest income	20			—		—		—			41			—			61
Interest expense	(23		)	—		—		(149		)	(3,412		)	—			(3,584		)
Gain (loss) on derivative contracts	(6		)	—		—		—			820			—			814
Other	9			—		—		—			—			—			9
Total other expense	—			—		—		(149		)	(2,551		)	—			(2,700		)
Income (loss) from continuing operations	3,306			—		84		(685		)	(25,386		)	—			(22,681		)
Income from discontinued operations	1,797			—		—		553			—			—			2,350
Gain on sale of discontinued operations	6,660			—		—		—			—			—			6,660
Net income (loss)	11,763			—		84		(132		)	(25,386		)	—			(13,671		)
Net (income) loss attributable to non-controlling interest	(129		)	—		—		—			—			—			(129		)
Net income (loss) attributable to Magnum Hunter Resources Corporation	11,634			—		84		(132		)	(25,386		)	—			(13,800		)
Dividends on preferred stock	—			—		—		—			(2,467		)	—			(2,467		)
Net income (loss) attributable to common shareholders	11,634			—		84		(132		)	(27,853		)	—			(16,267		)
Total segment assets	$	189,072		$	—	$	33,060	$	7,253		$	19,582		$	—		$	248,967
Segment capital expenditures	$	60,042		$	—	$	18,274	$	1,762		$	—		$	—		$	80,078

F-53

The US and Canadian Upstream, Midstream, and Oil Field Services functions best define the operating segments of the Company that are reported separately. The factors used to identify these reportable segments are based on the nature of the operations that are undertaken by each segment. The Upstream segment is organized and operates to explore for and produce crude oil, natural gas, and natural gas liquids. The Company has significant operations in the United States and Canada in the Upstream segment. The Midstream segment operates a network of pipelines that gathers natural gas and provides certain natural gas treating and other services. The Oil Field Services segment is organized and operates to sell services to third-party exploration and production companies. These are broadly understood as segments across the petroleum industry.

These functions have been defined as the operating segments of the Company because they are the segments (1) that engage in business activities from which revenues are earned and expenses are incurred; (2) whose operating results are regularly reviewed by the Company's chief executive officer to make decisions about resources to be allocated to the segment and assess its performance; and (3) for which discrete financial information is available.

The US Upstream segment comprises the following subsidiaries: Eagle Ford Hunter, Inc, Triad Hunter, LLC, Bakken Hunter, LLC, Williston Hunter, Inc., Williston Hunter ND, LLC, PRC Williston, LLC, Magnum Hunter Production, Inc. and the interests of Magnum Hunter Production, Inc. in various managed drilling partnerships, Sentra Corporation, Energy Hunter Securities, Inc., and Hunter Real Estate, LLC. The Magnum Hunter Resources Corporation parent company's oil and gas production activity is included in the US Upstream segment, and the activity that is related to the enterprise-wide operations, such as interest expense, general and administrative expense, gain (loss) on derivatives, dividends on preferred stock, and interest expense are classified as corporate unallocated activity. The Canadian Upstream segment comprises Williston Hunter Canada, Inc. The Midstream segment comprises Eureka Hunter Holdings, LLC and its subsidiaries, Eureka Hunter Pipeline, LLC and TransTex Hunter, LLC, as well as Magnum Hunter Marketing, LLC. The Oil Field Services segment comprises Alpha Hunter Drilling, LLC. The income from discontinued operations related to Hunter Disposal, LLC, which was sold in February 2012, is classified in Oil Field Services.

Supplemental Oil and Gas Disclosures (Unaudited)

The following table sets forth the costs incurred in oil and gas property acquisition, exploration, and development activities (in thousands):

	For the Year Ended December 31,
	2012		2011		2010
Purchase of non-producing leases	$	414,037	$	397,947	$	46,683
Purchase of producing properties	159,290		226,634		53,116
Exploration costs	165,789		112,606		43,466
Development costs	262,486		101,151		13,641
Asset retirement obligation	407		5,390		2,171
	$	1,002,009	$	843,728	$	159,077

F-54

Oil and Gas Reserve Information

Proved oil and gas reserve quantities are based on estimates prepared by Magnum Hunter’s third party reservoir engineering firms Cawley, Gillespie, & Associates, Inc. in 2012, and Cawley, Gillespie, & Associates, Inc. and AJM Deloitte in 2011. There are numerous uncertainties inherent in estimating quantities of proved reserves and projecting future rates of production and timing of development expenditures. The following reserve data only represent estimates and should not be construed as being exact.

Total Proved Reserves	Crude Oil  and Liquids	Natural Gas
	(mbbl)	(mmcf)
Balance December 31, 2009	4,609	9,364
Revisions of previous estimates	(112)	541
Purchases of reserves in place	3,328	22,250
Extensions, discoveries, and other additions	890	13,822
Sales of reserves in place	(1,507)	(5,298)
Production	(384)	(1,227)
Balance December 31, 2010	6,824	39,452
Revisions of previous estimates	6,937	40,494
Purchases of reserves in place	6,345	43,757
Extensions, discoveries, and other additions	2,687	22,399
Sales of reserves in place	(215)	(11)
Production	(869)	(6,854)
Balance December 31, 2011	21,709	139,237
Extensions, discoveries and other additions	3,415	544
Revisions of previous estimates	12,568	25,644
Purchases of reserves in place	10,613	12,082
Sales of reserves in place	(10)	(63)
Production	(2,343)	(14,824)
Balance December 31, 2012	45,952	162,620
Developed reserves, included above:
December 31, 2010	3,720	18,888
December 31, 2011	9,179	90,198
December 31, 2012	22,617	125,526

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Reserves

The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves and the changes in standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves were prepared in accordance with provisions of ASC 932, Extractive Activities - Oil and Gas. Future cash inflows at December 31, 2012, 2011, and 2010 were computed by applying the unweighted, arithmetic average of the closing price on the first day of each month for the 12-month period prior to December 31, 2012, 2011, and 2010 to estimated future production. Future production and development costs are computed by estimating the expenditures to be incurred in developing and producing the proved oil and natural gas reserves at year-end, based on year-end costs and assuming continuation of existing economic conditions.

Future income tax expenses are calculated by applying appropriate year-end tax rates to future pretax net cash flows relating to proved oil and natural gas reserves, less the tax basis of properties involved. Future income tax expenses give effect to permanent differences, tax credits and loss carry forwards relating to the proved oil and natural gas reserves. Future net cash flows are discounted at a rate of 10% annually to derive the standardized measure of discounted future net cash flows. This calculation procedure does not necessarily result in an estimate of the fair market value of our oil and natural gas properties.

F-55

The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves are as follows:

	Years Ended December 31,
	2012			2011			2010
	(in thousands)
Future cash inflows	$	4,248,384		$	2,409,249		$	709,788
Future production costs	(1,520,260		)	(765,048		)	(253,544		)
Future development costs	(603,809		)	(330,007		)	(77,216		)
Future income tax expense	(230,500		)	(253,721		)	(88,233		)
Future net cash flows	1,893,815			1,060,473			290,795
10% annual discount for estimated timing of cash flows	(1,046,162		)	(586,077		)	(162,836		)
Standardized measure of discounted future net cash flows	$	847,653		$	474,396		$	127,959

Future cash flows as shown above were reported without consideration for the effects of commodity derivative transactions outstanding at each period end.

Changes in Standardized Measure of Discounted Future Net Cash Flows

The changes in the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves are as follows:

	Years Ended December 31,
	2012			2011			2010
	(in thousands)
Balance, beginning of period	$	474,396		$	127,959		$	47,388
Net changes in prices and production costs	13,647			49,498			17,133
Changes in estimated future development costs	(391,318		)	(167,399		)	(50,950		)
Sales and transfers of oil and gas produced during the period	(179,384		)	(71,724		)	(19,054		)
Net changes due to extensions, discoveries, and improved recovery	60,468			110,316			51,022
Net changes due to revisions of previous quantity estimates (1)	290,500			235,163			(355		)
Previously estimated development costs incurred during the period	245,168			24,740			25,020
Accretion of discount	85,377			27,029			2,740
Purchase of minerals in place	217,791			234,336			112,406
Sale of minerals in place	(354		)	(3,726		)	(23,837		)
Changes in timing and other (2)	22,436			824			(1,863		)
Net change in income taxes	8,926			(92,620		)	(31,691		)
Standardized measure of discounted future net cash flows	$	847,653		$	474,396		$	127,959

1. The Company's net changes due to revisions of previous quantity estimates primarily reflect upward revisions to recoverable quantities of oil and gas minerals assuming existing prices and technology. For the year ended December 31, 2012, the Company made upward revisions of 12,568 mbbls of oil and natural gas liquids and 25,644 mmcf of natural gas. For the year ended December 31, 2011, the Company made upward revisions of 6,937 mbbls of oil and natural gas liquids and 40,494 mmcf of natural gas.

2. The Company's changes in timing and other primarily represent changes in the Company's estimates of when proved reserve quantities will be realized. The reserves as of December 31, 2012, reflect accelerated recovery of minerals due to purchases of minerals in place and capital expenditures incurred to develop properties.

F-56

The commodity prices inclusive of adjustments for quality and location used in determining future net revenues related to the standardized measure calculation are as follows:

	2012		2011		2010
Oil (per bbl)	$	88.37	$	96.19	$	79.43
Natural gas liquids (per bbl)	$	53.94	$	44.25	$	—
Gas (per mcf)	$	3.08	$	4.11	$	4.37

NOTE 17 – RELATED PARTY TRANSACTIONS

During 2012, 2011, and 2010, we rented an airplane for business use at various times from Pilatus Hunter, LLC, an entity 100% owned by Gary C. Evans, our Chairman and CEO. Airplane rental expenses totaled $174,000, $463,000, and $450,000, for the years ended December 31, 2012, 2011, and 2010, respectively.

During 2011 and 2010, we obtained accounting services and use of office space from GreenHunter Resources, Inc., an entity for which Mr. Evans is the Chairman, a major shareholder and former CEO; for which Ronald Ormand, our Chief Financial Officer and a director, is a former director; and for which David Krueger, our former Chief Accounting Officer and Senior Vice President, is the Chief Financial Officer. Professional services expenses totaled $162,000 and $212,000 for the years ended December 31, 2011 and 2010, respectively. In 2012, all accounting services were managed entirely by Magnum Hunter employees.

On October 13, 2011, the Company purchased an office building for $1.7 million from GreenHunter Resources, Inc. In conjunction with the purchase, the Company entered into a term note with a financial institution for $1.4 million due on November 30, 2017. The building houses the accounting functions of Magnum Hunter, and the building purchase enabled the Company to terminate the previous services arrangement described above.

We entered into a lease for a corporate apartment from an executive of the Company who was transferred for monthly rent of $4,500 for use by Company employees. During the years ended December 31, 2012 and 2011, the Company paid rent of $22,500 and $36,000, respectively, pertaining to the lease. The lease terminated in May 2012.

During 2012 and 2011, Eagle Ford Hunter and Triad Hunter, wholly-owned subsidiaries of the Company, rented storage tanks for disposal water and equipment from GreenHunter Resources, Inc. Rental costs totaled $1.0 million and $1.3 million for the years ended December 31, 2012 and 2011, respectively. The Company believes that such rentals are provided at competitive market rates and are comparable to or more attractive than rates that could be obtained from unaffiliated third party suppliers of such services. Additionally, these companies regularly obtained, and we continue to obtain, services from GreenHunter Resources, Inc. for water disposal. Disposal charges recorded in lease operating expenses totaled $2.4 million for the year ended December 31, 2012. We had no related party disposal charges in 2011 or 2010. As of December 31, 2012 and 2011, we had net accounts payable to GreenHunter of $0 and $70,000, respectively.

On February 17, 2012, the Company sold its wholly-owned subsidiary, Hunter Disposal, LLC, to GreenHunter Water, LLC, a wholly-owned subsidiary of GreenHunter Resources, Inc. The terms and conditions of the equity purchase agreement between the parties were approved by an independent special committee of the Board of the Company. Total consideration for the sale was approximately $9.3 million comprised of $2.2 million in cash, 1,846,722 shares of GreenHunter Resources, Inc. restricted common stock valued at $2.6 million based on a closing price of $1.79 per share, discounted for restrictions, 88,000 shares of GreenHunter Resources, Inc. 10% Series C Cumulative Preferred Stock with a fair value of $1.9 million, and a $2.2 million convertible promissory note which is convertible at the option of the Company into 880,000 shares of GreenHunter Resources, Inc. common stock based on the conversion price of $2.50 per share. The Company recognized a gain of on the sale of $2.4 million, in gain on sale of discontinued operations, net of tax. The Company has recognized an embedded derivative asset resulting from the conversion option on the convertible promissory note with fair market value of $264,000 at December 31, 2012. See "Note 4 - Fair Value of Financial Instruments" for additional information. The cash proceeds from the sale were adjusted downward to $783,000 for changes in working capital and certain fees to reflect the effective date of the sale of December 31, 2011. The Company has recorded interest income as a result of the note receivable from GreenHunter Resources, Inc., in the amount of $191,278 for the year ended December 31, 2012. As a result of this transaction, the Company has an investment in GreenHunter Resources, Inc. that is included in derivatives and other long term assets and recorded under the equity method. The loss related to this investment was $1.3 million for the year ended December 31, 2012. In connection with the sale, Triad Hunter entered into agreements with Hunter Disposal, LLC and GreenHunter Water, LLC for wastewater hauling and disposal capacity in Kentucky, Ohio, and West Virginia and a five-year tank rental agreement with GreenHunter Water, LLC.

Mr. Evans, our Chairman and Chief Executive Officer, was a 4.0% limited partner in TransTex Gas Services, LP, which limited partnership received total consideration of 622,641 Class A Common Units of Eureka Hunter Holdings and cash of $46.0 million upon the Company’s acquisition of certain of its assets.  This includes units issued in accordance with the agreement of Eureka Hunter

F-57

Holdings and TransTex to provide the limited partners of TransTex the opportunity to purchase additional Class A Common Units of Eureka Hunter Holdings in lieu of a portion of the cash distribution they would otherwise receive.  Certain limited partners purchased such units, including Mr. Evans, who purchased 27,641 Class A Common Units of Eureka Hunter Holdings for $553,000 at the same per unit purchase price offered to all TransTex investors.

NOTE 18 – COMMITMENTS AND CONTINGENCIES

Legal Proceedings

On April 23, 2013, Anthony Rosian, individually and on behalf of all other persons similarly situated, filed a class action complaint in the United States District Court, Southern District of New York, against the Company and certain of its officers, two of whom also serve as directors.  On April 24, 2013, Horace Carvalho, individually and on behalf of all other persons similarly situated, filed a similar class action complaint in the United States District Court, Southern District of Texas, against the Company and certain of its officers, two of whom also serve as directors.  Several substantially similar putative class actions have been filed in the Southern District of New York and in the Southern District of Texas. All such cases are collectively referred to as the Securities Cases. The complaints in the Securities Cases allege that the Company made certain false or misleading statements in its filings with the SEC, including statements related to the Company's internal and financial controls, the calculation of non-cash share-based compensation expense, the late filing of the Company's 2012 Form 10-K,  the dismissal of Magnum Hunter's previous independent registered accounting firm, and other matters identified in the Company's April 16, 2013 Form 8-K, as amended.  The complaints demand that the defendants pay unspecified damages to the class action plaintiffs, including damages allegedly caused by the decline in the Company's stock price between February 22, 2013 and April 22, 2013.  The Company and the individual defendants intend to vigorously defend the Securities Cases.  It is possible that additional putative class action suits could be filed over these events.

In addition, on May 10, 2013, Steven Handshu filed a shareholder derivative suit in the 151st Judicial District Court of Harris County, Texas on behalf of the Company against the Company's directors and senior officers. On June 6, 2013, Zachariah Hanft filed another shareholder derivative suit in the Southern District of New York on behalf of the Company against the Company's directors and senior officers. These suits are collectively referred to as the Derivative Cases.  The Derivative Cases assert that the individual defendants unjustly enriched themselves and breached their fiduciary duties to the Company by publishing allegedly false and misleading statements to the Company's investors regarding the Company's business and financial position and results, and allegedly failing to maintain adequate internal controls.   The complaints demand that the defendants pay unspecified damages to the Company, including damages allegedly sustained by the Company as a result of the alleged breaches of fiduciary duties by the defendants, as well as disgorgement of profits and benefits obtained by the defendants, and reasonable attorneys', accountants' and experts' fees and costs to the plaintiff.  The Derivative Cases are in their preliminary stages.  It is possible that additional shareholder derivative suits could be filed over these events.

The Company also received a letter from the SEC in April 2013 stating that the SEC's Division of Enforcement was conducting an inquiry regarding the Company's internal controls, change in outside auditors and public statements to investors and asking the Company to preserve documents relating to these matters.  The Company has been complying with this request.   

Any potential liability from these claims cannot currently be estimated, and no provision has been accrued for them in our financial statements.

Payable on Sale of Partnership

On September 26, 2008, the Company sold its 5.33% limited partner interest in Hall-Houston Exploration II, L.P. pursuant to a Partnership Interest Purchase Agreement dated September 26, 2008, as amended on September 29, 2008. The interest was purchased by a non-affiliated partnership for a cash consideration of $8.0 million and the purchaser’s assumption of the first $1.4 million of capital calls subsequent to September 26, 2008.  The Company agreed to reimburse the purchaser for up to $754,255 of capital calls in excess of the first $1.4 million. The Company’s net gain on the sale of the asset is subject to future upward adjustment to the extent that some or all of the $754,255 is not called.  The liability as of December 31, 2012 and 2011 was $640,695.  

Operational Contingencies

The exploration, development and production of oil and gas assets, the operations of oil and natural gas gathering systems, and the performance of oil field services are subject to various federal, state, local and foreign laws and regulations designed to protect the environment. Compliance with these regulations is part of our day-to-day operating procedures. Infrequently, accidental discharge of such materials as oil, natural gas or drilling fluids can occur and such accidents can require material expenditures to correct. We maintain various levels and types of insurance which we believe to be appropriate to limit our financial exposure. We are unaware of any material capital expenditures required for environmental control during this fiscal year.

F-58

Leases and Drilling Contract

As of December 31, 2012, office space rentals with terms of 12 months or greater include office spaces in Houston, Texas, that total approximately 16,900 square feet at a monthly cost of $25,000, Triad Hunter lease commitments with monthly payments of approximately $13,000, and Williston Hunter subsidiaries office spaces in Calgary, Alberta and Denver, Colorado that have combined monthly payments of $32,000.

On June 24, 2011, the Company entered into a 40-month drilling contract, for a term from July 1, 2011 through October 31, 2014. Our remaining maximum liability under the drilling contract, which would apply if we terminated the contract before the end of its term, was approximately $10.7 million as of December 31, 2012.

Future minimum lease commitments under noncancellable operating leases including operating leases and drilling contracts at December 31, 2012, are follows (in thousands):

2013	$	6,605
2014	$	5,232
2015	$	169
2016	$	58
2017	$	1
Thereafter	$	—

Drilling Rig Purchase

On November 15, 2012, the Company entered into an agreement to purchase a drilling rig. The remaining commitment under this agreement was $4.7 million as of December 31, 2012 of which $1.1 million remains due in equal installments over twelve months beginning in June 2013.

Employment Agreements

At December 31, 2012, we had an employment agreement with a senior officer with a maximum commitment, if the employee were terminated without cause, of approximately $200,000. As of May 1, 2013, this person was no longer employed by the Company.

Gas Gathering and Processing Agreements

On December 14, 2011, the Company entered into a 120 -month gas transportation contract. The contract became effective on August 1, 2012. Our remaining liability under the contract was approximately $24.5 million as of December 31, 2012. On June 27, 2012, Eureka Hunter Pipeline entered into 36-month gas compression contract. The contract became effective on October 1, 2012. Our remaining liability under the contract was $3.9 million as of December 31, 2012. With the Virco Acquisition, Triad Hunter assumed a 120-month gas transportation contract. Our remaining liability under the contract was $3.9 million as of December 31, 2012.

Future minimum gathering, processing, and transportation commitments at December 31, 2012, are as follows (in thousands):

2013	$	4,171
2014	$	4,225
2015	$	4,225
2016	$	3,017
2017	$	2,947
Thereafter	$	13,669

Derivative Obligations

Derivative obligations represent net liabilities determined in accordance with master netting arrangements for commodity derivatives that were valued as of December 31, 2012. The ultimate settlement amounts of the Company’s derivative obligations are unknown because they are subject to continuing market risk.

Eureka Hunter Holdings Operating Agreement

F-59

Pursuant to the terms of the Eureka Hunter Holdings operating agreement, the number and composition of the board of directors of Eureka Hunter Holdings may change over time based on Ridgeline’s percentage ownership interest in Eureka Hunter Holdings (after taking into account any additional purchases of preferred units) or the failure of Eureka Hunter Holdings to satisfy certain performance goals by the third anniversary of the closing of the initial Ridgeline investment (or as of any anniversary after such date) or under certain other circumstances. The board of directors of Eureka Hunter Holdings is currently composed of a majority of members appointed by Magnum Hunter. Subject to the rights described above, the board of directors of Eureka Hunter Holdings may in the future be composed of an equal number of directors appointed by Magnum Hunter and Ridgeline or, in certain cases, of a majority of directors appointed by Ridgeline.

If a change of control of Magnum Hunter occurs at any time prior to a qualified public offering (as defined in the Eureka Hunter Holdings operating agreement) of Eureka Hunter Holdings, Ridgeline will have the right under the terms of the operating agreement to purchase sufficient additional preferred units in Eureka Hunter Holdings so that it holds up to 51.0% of the equity ownership of Eureka Hunter Holdings.

F-60

NOTE 19 – CONDENSED CONSOLIDATING GUARANTOR FINANCIAL STATEMENTS

Debt Securities Under Universal Shelf Registration Statement

Certain of the Company’s wholly-owned subsidiaries, Eagle Ford Hunter, Inc., Triad Hunter, LLC, NGAS Hunter, LLC, Magnum Hunter Production, Inc., Williston Hunter, Inc., Williston Hunter ND, LLC, and Bakken Hunter, LLC (collectively, “Guarantor Subsidiaries”), have fully and unconditionally guaranteed the obligations of the Company under any debt securities that it may issue under a universal shelf registration statement on Form S-3, on a joint and several basis.

Condensed consolidating financial information for Magnum Hunter Resources Corporation, the Guarantor Subsidiaries and the other subsidiaries of the Company (the “Non Guarantor Subsidiaries”) as of December 31, 2012 and 2011 and for the years ended December 31, 2012, 2011, and 2010, was as follows:

Magnum Hunter Resources Corporation and Subsidiaries

Condensed Consolidating Balance Sheets

(in thousands)

	As of December 31, 2012
	Magnum Hunter Resources Corporation		Guarantor Subsidiaries		Non Guarantor Subsidiaries		Eliminations			Magnum Hunter Resources Corporation Consolidated
ASSETS
Current assets	$	63,167	$	97,434	$	74,927	$	(31,209	)	$	204,319
Intercompany accounts receivable	803,834		—		—		(803,834		)	—
Property and equipment (using successful efforts accounting)	9,596		1,363,651		551,166		—			1,924,413
Investment in subsidiaries	763,856		101,342		102,354		(967,552		)	—
Other assets	20,849		5,341		43,710		—			69,900
Total Assets	$	1,661,302	$	1,567,768	$	772,157	$	(1,802,595	)	$	2,198,632
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities	$	28,503	$	155,993	$	89,537	$	(30,377	)	$	243,656
Intercompany accounts payable	—		796,008		7,826		(803,834		)	—
Long-term liabilities	831,286		83,508		127,652		—			1,042,446
Redeemable preferred stock	100,000		—		100,878		—			200,878
Shareholders' equity	701,513		532,259		446,264		(968,384		)	711,652
Total Liabilities and Shareholders' Equity	$	1,661,302	$	1,567,768	$	772,157	$	(1,802,595	)	$	2,198,632

F-61

Magnum Hunter Resources Corporation and Subsidiaries

Condensed Consolidating Balance Sheets

(in thousands)

	As of December 31, 2011
	Magnum Hunter Resources Corporation		Guarantor Subsidiaries		Non Guarantor Subsidiaries		Eliminations			Magnum Hunter Resources Corporation Consolidated
ASSETS
Current assets	$	25,401	$	36,772	$	14,929	$	567		$	77,669
Intercompany accounts receivable	667,557		—		—		(667,557		)	—
Property and equipment (using successful efforts accounting)	13,287		723,489		338,358		—			1,075,134
Investment in subsidiaries (1)	147,491		64,784		126,655		(338,930		)	—
Other assets	9,151		440		6,366		—			15,957
Total Assets	$	862,887	$	825,485	$	486,308	$	(1,005,920	)	$	1,168,760
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities	$	21,112	$	110,938	$	35,045	$	580		$	167,675
Intercompany accounts payable	—		307,398		360,159		(667,557		)	—
Long-term liabilities	253,319		93,659		63,455		—			410,433
Redeemable preferred stock	100,000		—		—		—			100,000
Shareholders' equity (1)	488,456		313,490		27,649		(338,943		)	490,652
Total Liabilities and Shareholders' Equity	$	862,887	$	825,485	$	486,308	$	(1,005,920	)	$	1,168,760

⁽¹⁾ In the third quarter of 2012, the Company revised its condensed consolidating balance sheet for the year ended December 31, 2011, to correct the presentation of Guarantor and Non-Guarantor shareholders' equity and the corresponding impact to investment in subsidiaries in the Magnum Hunter Resources Corporation column. The impact of this revision to the Guarantor Subsidiaries and Magnum Hunter Resources Corporation is an increase of equity and investment in subsidiaries of approximately $45.3 million and $32.2 million, respectively, for the year ended December 31, 2011. Management concluded the revision was not material to the related financial statements.

F-62

Magnum Hunter Resources Corporation and Subsidiaries

Condensed Consolidating Statements of Operations

(in thousands)

	For the Year Ended December 31, 2012
	Magnum Hunter Resources Corporation			Guarantor Subsidiaries			Non Guarantor Subsidiaries			Eliminations			Magnum Hunter Resources Corporation Consolidated
Revenues	$	565		$	196,418		$	77,633		$	(3,645	)	$	270,971
Expenses	53,883			244,161			137,093			(1,790		)	433,347
Loss from continuing operations before equity in net income of subsidiaries	(53,318		)	(47,743		)	(59,460		)	(1,855		)	(162,376		)
Equity in net income of subsidiaries	(91,254		)	458			(23,362		)	114,158			—
Loss from continuing operations before income tax	(144,572		)	(47,285		)	(82,822		)	112,303			(162,376		)
Income tax benefit	—			14,796			8,220			—			23,016
Loss from continuing operations	(144,572		)	(32,489		)	(74,602		)	112,303			(139,360		)
Income from discontinued operations, net of tax	—			—			230			—			230
Gain on sale of discontinued operations, net of tax	—			2,409			—			—			2,409
Net income (loss)	(144,572		)	(30,080		)	(74,372		)	112,303			(136,721		)
Net loss attributable to non-controlling interest	—			—			4,013			—			4,013
Net loss attributable to Magnum Hunter Resources Corporation	(144,572		)	(30,080		)	(70,359		)	112,303			(132,708		)
Dividends on preferred stock	(22,842		)	—			(11,864		)	—			(34,706		)
Net income (loss) attributable to common shareholders	$	(167,414	)	$	(30,080	)	$	(82,223	)	$	112,303		$	(167,414	)

	For the Year Ended December 31, 2011
	Magnum Hunter Resources Corporation			Guarantor Subsidiaries			Non Guarantor Subsidiaries			Eliminations			Magnum Hunter Resources Corporation Consolidated
Revenues	$	1,071		$	84,957		$	31,431		$	(3,779	)	$	113,680
Expenses	68,772			99,314			29,458			(3,779		)	193,765
Loss from continuing operations before equity in net income of subsidiaries	(67,701		)	(14,357		)	1,973			—			(80,085		)
Equity in net income of subsidiaries	(8,960		)	(2,196		)	(939		)	12,095			—
Loss from continuing operations before income tax	(76,661		)	(16,553		)	1,034			12,095			(80,085		)
Income tax benefit	—			571			125			—			696
Loss from continuing operations	(76,661		)	(15,982		)	1,159			12,095			(79,389		)
Income from discontinued operations, net of tax	—			—			2,977			—			2,977
Net income (loss)	(76,661		)	(15,982		)	4,136			12,095			(76,412		)
Net income attributable to non-controlling interest	—			—			(249		)	—			(249		)
Net loss attributable to Magnum Hunter Resources Corporation	(76,661		)	(15,982		)	3,887			12,095			(76,661		)
Dividends on preferred stock	(14,007		)	—			—			—			(14,007		)
Net income (loss) attributable to common shareholders	$	(90,668	)	$	(15,982	)	$	3,887		$	12,095		$	(90,668	)

F-63

Magnum Hunter Resources Corporation and Subsidiaries

Condensed Consolidating Statements of Operations

(in thousands)

	For the Year Ended December 31, 2010
	Magnum Hunter Resources Corporation			Guarantor Subsidiaries		Non Guarantor Subsidiaries			Eliminations			Magnum Hunter Resources Corporation Consolidated
Revenues	$	1,395		$	18,308	$	11,984		$	(2,337	)	$	29,350
Expenses	27,421			15,389		11,558			(2,337		)	52,031
Loss from continuing operations before equity in net income of subsidiaries	(26,026		)	2,919		426			—			(22,681		)
Equity in net income of subsidiaries	3,769			—		—			(3,769		)	—
Loss from continuing operations	(22,257		)	2,919		426			(3,769		)	(22,681		)
Income from discontinued operations, net of tax	1,797			—		553			—			2,350
Gain on sale of discontinued operations, net of tax	6,660			—		—			—			6,660
Net income (loss)	(13,800		)	2,919		979			(3,769		)	(13,671		)
Net income attributable to non-controlling interest	—			—		(129		)	—			(129		)
Net loss attributable to Magnum Hunter Resources Corporation	(13,800		)	2,919		850			(3,769		)	(13,800		)
Dividends on preferred stock	(2,467		)	—		—			—			(2,467		)
Net income (loss) attributable to common shareholders	$	(16,267	)	$	2,919	$	850		$	(3,769	)	$	(16,267	)

F-64

Magnum Hunter Resources Corporation and Subsidiaries

Condensed Consolidating Statements of Cash Flows

(in thousands)

	For the Year Ended December 31, 2012
	Magnum Hunter Resources Corporation		Guarantor Subsidiaries		Non Guarantor Subsidiaries		Eliminations	Magnum Hunter Resources Corporation Consolidated
Cash flow from operating activities	(458,921	)	444,776		72,156		—	58,011
Cash flow from investing activities	(364,045	)	(449,897	)	(195,265	)	—	(1,009,207	)
Cash flow from financing activities	831,080		(1,966	)	167,328		—	996,442
Effect of exchange rate changes on cash	—		—		(2,474	)	—	(2,474	)
Net increase (decrease) in cash	8,114		(7,087	)	41,745		—	42,772
Cash at beginning of period	18,758		(5,771	)	1,864		—	14,851
Cash at end of period	26,872		(12,858	)	43,609		—	57,623

	For the Year Ended December 31, 2011
	Magnum Hunter Resources Corporation			Guarantor Subsidiaries			Non Guarantor Subsidiaries			Eliminations		Magnum Hunter Resources Corporation Consolidated
Cash flow from operating activities	$	(203,251	)	$	191,228		$	45,861		$	—	$	33,838
Cash flow from investing activities	(90,464		)	(195,621		)	(75,630		)	—		(361,715		)
Cash flow from financing activities	310,917			(310		)	31,586			—		342,193
Effect of exchange rate changes on cash	—			—			(19		)	—		(19		)
Net increase (decrease) in cash	17,202			(4,703		)	1,798			—		14,297
Cash at beginning of period	1,556			(1,068		)	66			—		554
Cash at end of period	$	18,758		$	(5,771	)	$	1,864		$	—	$	14,851

	For the Year Ended December 31, 2010
	Magnum Hunter Resources Corporation			Guarantor Subsidiaries			Non Guarantor Subsidiaries			Eliminations		Magnum Hunter Resources Corporation Consolidated
Cash flow from operating activities	$	(92,809	)	$	71,334		$	20,307		$	—	$	(1,168	)
Cash flow from investing activities	(21,926		)	(75,807		)	(20,548		)	—		(118,281		)
Cash flow from financing activities	117,998			(322		)	45			—		117,721
Net increase (decrease) in cash	3,263			(4,795		)	(196		)	—		(1,728		)
Cash at beginning of period	(1,707		)	3,727			262			—		2,282
Cash at end of period	$	1,556		$	(1,068	)	$	66		$	—	$	554

F-65

Senior Notes

Certain of the Company’s subsidiaries, including Alpha Hunter Drilling, LLC, Bakken Hunter, LLC, Eagle Ford Hunter, Inc., Hunter Aviation, LLC, Hunter Real Estate, LLC, Magnum Hunter Marketing, LLC, Magnum Hunter Production, Inc., Magnum Hunter Resources, GP, LLC, Magnum Hunter Resources, LP, NGAS Gathering, LLC, NGAS Hunter, LLC, PRC Williston, LLC, Triad Hunter, LLC, Williston Hunter, Inc., Williston Hunter ND, LLC, and Viking International Resources, Co., Inc. (collectively, "Guarantor Subsidiaries"), jointly and severally guarantee on a senior unsecured basis, the obligations of the Company under all the Senior Notes issued under the indenture entered into by the Company on May 16, 2012, as supplemented. Condensed consolidating financial information for Magnum Hunter Resources Corporation , the Guarantor Subsidiaries and the other subsidiaries of the Company (the "Non Guarantor Subsidiaries") as of December 31, 2012, 2011, 2010 and for the years then ended was as follows:

Magnum Hunter Resources Corporation and Subsidiaries

Condensed Consolidating Balance Sheets

(in thousands)

	As of December 31, 2012
	Magnum Hunter Resources Corporation		PRC Williston			Wholly-Owned Guarantor Subsidiaries		Non Guarantor Subsidiaries		Eliminations			Magnum Hunter Resources Corporation Consolidated
ASSETS
Current assets	$	63,167	$	703		$	109,666	$	61,991	$	(31,208	)	$	204,319
Intercompany accounts receivable	803,834		—			—		—		(803,834		)	—
Property and equipment (using successful efforts accounting)	9,596		18,257			1,491,402		405,158		—			1,924,413
Investment in subsidiaries	763,856		—			100,883		102,354		(967,093		)	—
Other assets	20,849		—			5,451		43,600		—			69,900
Total Assets	$	1,661,302	$	18,960		$	1,707,402	$	613,103	$	(1,802,135	)	$	2,198,632
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities	$	28,503	$	2,291		$	163,966	$	79,272	$	(30,376	)	$	243,656
Intercompany accounts payable	—		58,966			692,330		52,538		(803,834		)	—
Long-term liabilities	831,286		1,274			97,587		112,299		—			1,042,446
Redeemable preferred stock	100,000		—			—		100,878		—			200,878
Shareholders' equity (deficit)	701,513		(43,571		)	753,519		268,116		(967,925		)	711,652
Total Liabilities and Shareholders' Equity	$	1,661,302	$	18,960		$	1,707,402	$	613,103	$	(1,802,135	)	$	2,198,632

F-66

Magnum Hunter Resources Corporation and Subsidiaries

Condensed Consolidating Balance Sheets

(in thousands)

	As of December 31, 2011
	Magnum Hunter Resources Corporation		PRC Williston			Wholly-Owned Guarantor Subsidiaries		Non Guarantor Subsidiaries		Eliminations			Magnum Hunter Resources Corporation Consolidated
ASSETS
Current assets	$	25,401	$	2,188		$	39,559	$	9,876	$	645		$	77,669
Intercompany accounts receivable	667,557		—			—		—		(667,557		)	—
Property and equipment (using successful efforts accounting)	13,287		32,607			732,799		296,566		(125		)	1,075,134
Investment in subsidiaries	147,491		—			62,672		125,716		(335,879		)	—
Other assets	9,151		—			466		6,340		—			15,957
Total Assets	$	862,887	$	34,795		$	835,496	$	438,498	$	(1,002,916	)	$	1,168,760
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities	$	21,112	$	1,319		$	114,526	$	30,661	$	57		$	167,675
Intercompany accounts payable	—		60,173			309,332		316,071		(685,576		)	—
Long-term liabilities	253,319		1,983			97,118		58,013		—			410,433
Redeemable preferred stock	100,000		—			—		—		—			100,000
Shareholders' equity (deficit)	488,456		(28,680		)	314,520		33,753		(317,397		)	490,652
Total Liabilities and Shareholders' Equity	$	862,887	$	34,795		$	835,496	$	438,498	$	(1,002,916	)	$	1,168,760

F-67

Magnum Hunter Resources Corporation and Subsidiaries

Condensed Consolidating Statements of Operations

(in thousands)

	For the Year Ended December 31, 2012
	Magnum Hunter Resources Corporation			PRC Williston, Inc.			Wholly-Owned Guarantor Subsidiaries			Non Guarantor Subsidiaries			Eliminations			Magnum Hunter Resources Corporation Consolidated
Revenues	$	565		$	7,614		$	214,917		$	51,520		$	(3,645	)	$	270,971
Expenses	53,883			22,505			261,479			78,777			16,703			433,347
Loss from continuing operations before equity in net income of subsidiaries	(53,318		)	(14,891		)	(46,562		)	(27,257		)	(20,348		)	(162,376		)
Equity in net income of subsidiaries	(91,254		)	—			—			(23,362		)	114,616			—
Loss from continuing operations before income tax	(144,572		)	(14,891		)	(46,562		)	(50,619		)	94,268			(162,376		)
Income tax benefit	—			—			14,796			8,220			—			23,016
Loss from continuing operations	(144,572		)	(14,891		)	(31,766		)	(42,399		)	94,268			(139,360		)
Income from discontinued operations, net of tax	—			—			—			230			—			230
Gain on sale of discontinued operations, net of tax	—			—			2,409			—			—			2,409
Net income (loss)	(144,572		)	(14,891		)	(29,357		)	(42,169		)	94,268			(136,721		)
Net loss attributable to non-controlling interest	—						—			(160		)	4,173			4,013
Net loss attributable to Magnum Hunter Resources Corporation	(144,572		)	(14,891		)	(29,357		)	(42,329		)	98,441			(132,708		)
Dividends on preferred stock	(22,842		)	—			—			(11,864		)	—			(34,706		)
Net income (loss) attributable to common shareholders	$	(167,414	)	$	(14,891	)	$	(29,357	)	$	(54,193	)	$	98,441		$	(167,414	)

	For the Year Ended December 31, 2011
	Magnum Hunter Resources Corporation			PRC Williston, Inc.			Wholly-Owned Guarantor Subsidiaries			Non Guarantor Subsidiaries			Eliminations			Magnum Hunter Resources Corporation Consolidated
Revenues	$	1,071		$	8,687		$	94,383		$	13,317		$	(3,778	)	$	113,680
Expenses	68,772			11,704			108,860			13,212			(8,783		)	193,765
Loss from continuing operations before equity in net income of subsidiaries	(67,701		)	(3,017		)	(14,477		)	105			5,005			(80,085		)
Equity in net income of subsidiaries	(8,960		)	—			(2,196		)	(939		)	12,095			—
Loss from continuing operations before income tax	(76,661		)	(3,017		)	(16,673		)	(834		)	17,100			(80,085		)
Income tax benefit	—			—			571			125			—			696
Loss from continuing operations	(76,661		)	(3,017		)	(16,102		)	(709		)	17,100			(79,389		)
Income from discontinued operations, net of tax	—			—			—			2,977			—			2,977
Net income (loss)	(76,661		)	(3,017		)	(16,102		)	2,268			17,100			(76,412		)
Net income attributable to non-controlling interest	—			—			—			—			(249		)	(249		)
Net loss attributable to Magnum Hunter Resources Corporation	(76,661		)	(3,017		)	(16,102		)	2,268			16,851			(76,661		)
Dividends on preferred stock	(14,007		)	—			—			—			—			(14,007		)
Net income (loss) attributable to common shareholders	$	(90,668	)	$	(3,017	)	$	(16,102	)	$	2,268		$	16,851		$	(90,668	)

F-68

Magnum Hunter Resources Corporation and Subsidiaries

Condensed Consolidating Statements of Operations

(in thousands)

	For the Year Ended December 31, 2010
	Magnum Hunter Resources Corporation			PRC Williston, Inc.			Wholly-Owned Guarantor Subsidiaries		Non Guarantor Subsidiaries		Eliminations			Magnum Hunter Resources Corporation Consolidated
Revenues	$	1,395		$	8,178		$	21,699	$	415	$	(2,337	)	$	29,350
Expenses	27,421			15,275			19,466		332		(10,463		)	52,031
Loss from continuing operations before equity in net income of subsidiaries	(26,026		)	(7,097		)	2,233		83		8,126			(22,681		)
Equity in net income of subsidiaries	3,769			—			—		—		(3,769		)	—
Loss from continuing operations	(22,257		)	(7,097		)	2,233		83		4,357			(22,681		)
Income from discontinued operations, net of tax	1,797			—			—		553		—			2,350
Gain on sale of discontinued operations, net of tax	6,660			—			—		—		—			6,660
Net income (loss)	(13,800		)	(7,097		)	2,233		636		4,357			(13,671		)
Net income attributable to non-controlling interest	—			—			—		—		(129		)	(129		)
Net loss attributable to Magnum Hunter Resources Corporation	(13,800		)	(7,097		)	2,233		636		4,228			(13,800		)
Dividends on preferred stock	(2,467		)	—			—		—		—			(2,467		)
Net income (loss) attributable to common shareholders	$	(16,267	)	$	(7,097	)	$	2,233	$	636	$	4,228		$	(16,267	)

F-69

Magnum Hunter Resources Corporation and Subsidiaries

Condensed Consolidating Statements of Cash Flows

(in thousands)

	For the Year Ended December 31, 2012
	Magnum Hunter Resources Corporation			PRC Williston, Inc.			Wholly-Owned Guarantor Subsidiaries			Non Guarantor Subsidiaries			Eliminations			Magnum Hunter Resources Corporation Consolidated
Cash flow from operating activities	$	(458,921	)	$	1,256		$	450,644		$	66,242		$	(1,210	)	$	58,011
Cash flow from investing activities	(364,045		)	(49		)	(459,137		)	(185,979		)	3			(1,009,207		)
Cash flow from financing activities	831,080			(1,207		)	1,781			163,581			1,207			996,442
Effect of exchange rate changes on cash	—			—			—			(2,474		)	—			(2,474		)
Net increase (decrease) in cash	8,114			—			(6,712		)	41,370			—			42,772
Cash at beginning of period	18,758			—			(5,872		)	1,965			—			14,851
Cash at end of period	$	26,872		$	—		$	(12,584	)	$	43,335		$	—		$	57,623

	For the Year Ended December 31, 2011
	Magnum Hunter Resources Corporation			PRC Williston, Inc.			Guarantor Subsidiaries			Non Guarantor Subsidiaries			Eliminations			Magnum Hunter Resources Corporation Consolidated
Cash flow from operating activities	$	(203,251	)	$	(1,738	)	$	193,109		$	43,794		$	1,924		$	33,838
Cash flow from investing activities	(90,464		)	(175		)	(201,086		)	(69,979		)	(11		)	(361,715		)
Cash flow from financing activities	310,917			1,913			3,206			28,070			(1,913		)	342,193
Effect of exchange rate changes on cash	—			—			—			(19		)	—			(19		)
Net increase (decrease) in cash	17,202			—			(4,771		)	1,866			—			14,297
Cash at beginning of period	1,556			—			(1,101		)	99			—			554
Cash at end of period	$	18,758		$	—		$	(5,872	)	$	1,965		$	—		$	14,851

F-70

Magnum Hunter Resources Corporation and Subsidiaries

Condensed Consolidating Statements of Cash Flows

(in thousands)

	For the Year Ended December 31, 2010
	Magnum Hunter Resources Corporation			PRC Williston, Inc.			Wholly-Owned Guarantor Subsidiaries			Non Guarantor Subsidiaries			Eliminations			Magnum Hunter Resources Corporation Consolidated
Cash flow from operating activities	$	(92,809	)	$	(4,818	)	$	72,039		$	19,517		$	4,903		$	(1,168	)
Cash flow from investing activities	(21,926		)	(237		)	(76,476		)	(19,661		)	19			(118,281		)
Cash flow from financing activities	117,998			4,922			(520		)	243			(4,922		)	117,721
Net increase (decrease) in cash	3,263			(133		)	(4,957		)	99			—			(1,728		)
Cash at beginning of period	(1,707		)	133			3,856			—			—			2,282
Cash at end of period	$	1,556		$	—		$	(1,101	)	$	99		$	—		$	554

NOTE 20 – SUBSEQUENT EVENTS

Issuance of Series E Preferred Stock

We sold an additional 27,906 Depositary Shares representing our Series E Preferred Stock at prices ranging from $24.20 per share to $24.25 per share for net proceeds of approximately $663,000, pursuant to our ATM sales agreement subsequent to December 31, 2012 through the date of this report.  There are a total of 3,721,556 Depositary Shares representing Series E Preferred Stock outstanding as of the date of this report.

Issuance of Series D Preferred Stock

We sold an additional 216,068 shares of our Series D Preferred Stock at prices ranging from $44.54 per share to $46.02 per share for net proceeds of approximately $9.6 million, pursuant to our ATM sales agreement subsequent to December 31, 2012 through the date of this report.  There are a total of 4,424,889 shares of Series D Preferred Stock outstanding as of the date of this report.

Derivative Contracts

We entered into commodity derivative contracts subsequent to December 31, 2012, through the date of this report. Our objective for holding these commodity derivatives is to protect the operating revenues and cash flows related to a portion of our future natural gas and crude oil sales from the risk of significant declines in commodity prices, which helps insure our ability to fund our capital expenditure budget.  We have not designated any of these commodity derivatives as hedges under ASC 815.

F-71

The table below is a summary of our commodity derivatives entered into subsequent to December 31, 2012 through the date of this report:

			Weighted Avg
Natural Gas	Period	MMBTU/day	Price per MMBTU
Swaps	Apr 2013 - Dec 2013	10,000	$3.83
	Jan 2014 - Dec 2014	5,000	$4.26
Floors purchased (put)	Jan 2014 - Dec 2014	10,000	$4.25
Floors sold (put)	Jan 2014 - Dec 2014	10,000	$3.75
Ceilings purchased (call)	Apr 2013 - Dec 2013	10,000	$6.00
	Jan 2014 - Dec 2014	10,000	$6.15
Ceilings sold (call)	Jan 2014 - Dec 2014	10,000	$4.78
			Weighted Avg Price per Bbl
Crude Oil	Period	Bbls/day
Swaps	Jan 2013 - Jan 2013	2,200	$94.00
	Feb 2013 - Dec 2013	4,450	$93.00
Floors purchased (put)	Feb 2013 - Dec 2013	1,750	$90.00
Floors sold (put)	Feb 2013 - Dec 2013	4,000	$80.00
Ceilings purchased (call)	Feb 2013 - Dec 2013	2,250	$100.00
Ceilings sold (call)	Jan 2015 - Dec 2015	1,570	$120.00

Common Stock Options Granted to Employees, Management and Board Members

On January 17, 2013, the Company granted 3,942,575 common stock options to officers, executives, and employees of the Company, with an exercise price of $4.16, of which 3,080,000 have a term of 10 years and 862,575 have a term of 5 years. The options vest over a 3-year period with 25% of the options vesting immediately. The Company also granted to board members 420,000 common stock options, which have a term of 10 years and vest immediately.

Increase in the Number of Authorized Common and Preferred Shares

On January 17, 2013, upon shareholder approval, the Company’s certificate of incorporation was amended to increase the authorized number of shares of common stock from 250,000,000 to 350,000,000, and the Magnum Hunter Resources Corporation Amended and Restated Stock Incentive Plan was amended to increase the aggregate number of shares of the Company’s common stock that may be issued under the plan from 20,000,000 to 27,500,000.

Issuance of Series A Preferred Units of Eureka Hunter Holdings

Eureka Hunter Holdings has issued 229,434 Series A Preferred units with a redemption value of $4.6 million for dividends paid in kind subsequent to December 31, 2012 through May 1, 2012.

On April 11, 2013, Eureka Hunter Holdings issued 1,000,000 Series A Preferred Units to Ridgeline for net proceeds of $19.8 million, net of transaction costs. The Series A Preferred Units outstanding at the date of this report represent 39.5% of the ownership of Eureka Hunter Holdings on a basis as converted to Class A Common Units of Eureka Holdings.

F-72

Fourteenth Amendment to the Second Amended and Restated Credit Agreement

On February 25, 2013, pursuant to the Fourteenth Amendment to the Second Amended and Restated Credit Agreement, the MHR Senior Revolving Credit Facility was amended to eliminate the non-conforming borrowing base and increase the conforming borrowing base from $306.25 million to $350.0 million. The Fourteenth Amendment also increased the permitted debt basket for senior unsecured notes of the Company from $650.0 million to $800.0 million in principal amount, which will permit the Company to issue up to $200.0 million in principal amount of Senior Notes in the future, in addition to the $600.0 million aggregate principal amount of Senior Notes currently outstanding. Under this facility, the borrowing base will be automatically reduced by $0.25 for each $1.00 in principal amount of any Senior Notes issued by the Company in the future.

Amendment to Eureka Hunter Holdings Operating Agreement

On March 7, 2013, the Company and Ridgeline entered into the second amendment to the amended and restated limited liability company agreement of Eureka Hunter Holdings. The amendment provided for an equity contribution of $30.0 million by Magnum Hunter in March 2013, in exchange for 1,500,000 newly issued Class A Common Units of Eureka Hunter Holdings. The amendment also provided that Ridgeline or another affiliate of ArcLight has the exclusive right to fund the next $20.0 million of Eureka Hunter Holding's capital requirements, which Ridgeline did in April 2013, and then the next $70.5 million of such capital requirements will be funded by Ridgeline and the Company on a 40%/60% basis. After giving effect to this equity contribution by Magnum Hunter and the issuances of Series A Preferred Units noted above, as of May 1, 2013, the Company had a 58.3% controlling interest in Eureka Hunter Holdings.

Fifteenth Amendment to the Second Amended and Restated Credit Agreement

On March 17, 2013, pursuant to the Fifteenth Amendment to Second Amended and Restated Credit Agreement and Limited Consent (the “Fifteenth Amendment”), the deadline under the MHR Senior Revolving Credit Facility for the Company's delivery of its audited fiscal 2012 financial statements to the lenders under the MHR Senior Revolving Credit Facility was extended to May 20, 2013 (such date, the “Senior Credit Agreement Delivery Date”); provided, however, that, in the event that the requisite noteholders under the Company's senior notes indenture (the “Indenture”) agree to extend the date by which the Company is required to deliver its audited financial statements under the Indenture (such date, the “Indenture Delivery Date”), the Senior Credit Agreement Delivery Date will be further extended to the earlier of (i) three business days before the Indenture Delivery Date (as so extended), and (ii) June 17, 2013. In addition, under the Fifteenth Amendment, the lenders under the MHR Senior Credit Facility waived any event of default under the MHR Senior Revolving Credit Facility that may occur as a result of any default occurring under the Indenture due to the Company's failure to timely file its Annual Report on Form 10-K with the Securities and Exchange Commission.

Sixteenth Amendment to the Second Amended and Restated Credit Agreement

On April 2, 2013, pursuant to the Sixteenth Amendment to Second Amended and Restated Credit Agreement and Limited Consent (the “Sixteenth Amendment”), the lenders under the MHR Senior Revolving Credit Facility waived the requirement that 100% of the consideration the Company received for the sale of the stock of Eagle Ford Hunter, Inc. to Penn Virginia Oil & Gas Corporation be cash. In addition, pursuant to the Sixteenth Amendment, the MHR Senior Revolving Credit Facility was amended to permit the Company's investment in, and any later disposition of, the common stock of Penn Virginia Corporation that was received by the Company upon the sale of stock of Eagle Ford Hunter, Inc.

Seventeenth Amendment to the Second Amended and Restated Credit Agreement

On April 23, 2013, pursuant to the Seventeenth Amendment to Second Amended and Restated Credit Agreement and Limited Consent (the “Seventeenth Amendment”), the MHR Senior Revolving Credit Facility was amended to, among other things, provide for the decrease of the borrowing base from $350 million to $265 million, effective upon the closing of the Company's sale of 100% of the outstanding capital stock of Eagle Ford Hunter, Inc., the Company's wholly owned subsidiary, to Penn Virginia Oil & Gas Corporation pursuant to a stock purchase agreement dated April 2, 2013. In addition, pursuant to the Seventeenth Amendment, the deadline under the MHR Senior Revolving Credit Facility for the Company's delivery of its audited 2012 annual financial statements to the lenders under the MHR Senior Revolving Credit Facility was extended to the earlier of (i) 57 days after notice to the Company by the trustee under the Company's senior notes (the “Senior Notes”) of the Company's failure to comply with Section 4.02(a) of the indenture governing the Senior Notes (concerning the delivery of reports under the Securities Exchange Act of 1934) and (ii) June 17, 2013. The deadline under the MHR Senior Revolving Credit Facility for the Company's delivery of its first quarter 2013 financial statements to the lenders under the MHR Senior Revolving Credit Facility was also extended, to the earlier of (i) 30 days after the delivery date of the audited 2012 annual financial statements under the new deadline and (ii) July 12, 2013. Under the Seventeenth Amendment, the lenders under the MHR Senior Revolving Credit Facility waived any event of default under the facility that may occur as a result of a default occurring under the Indenture due to the Company's failure to comply with Section 4.02(a) of the Indenture with respect to the Company's Form 10-Q for the quarterly period ended March 31, 2013. The Seventeenth Amendment also revises Section 9.18

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of the MHR Senior Revolving Credit Facility to clarify that existing maximum hedging limits apply to each of crude oil (including natural gas liquids) and natural gas independently, with neither commodity impacting the Company's ability to hedge the other.

Sale of Eagle Ford Hunter

On April 24, 2013, the Company sold of all of its ownership interest in its wholly owned subsidiary, Eagle Ford Hunter, to an affiliate of Penn Virginia Corporation for a total purchase price of approximately $422.1 million made up of cash payment of $379.8 million (after initial purchase price adjustments) and 10.0 million shares of common stock of Penn Virginia Corporation valued at approximately $42.3 million. The effective date of the sale was January 1, 2013. Upon closing of the sale, $325 million of sale proceeds were used to pay down outstanding borrowings under the MHR Senior Revolving Credit Facility.

On June 24, 2011, the Company entered into a 40-month drilling contract, for a term from July 1, 2011 through October 31, 2014. Our remaining maximum liability under the drilling contract, which would apply if we terminated the contract before the end of its term, was approximately $10.7 million as of December 31, 2012. This drilling contract was assigned to the purchaser of Eagle Ford Hunter in connection with the sale of Eagle Ford Hunter in April 2013.

Purchase of Drilling Rig

On May 7, 2013, the Company, through its wholly-owned subsidiary, Alpha Hunter Drilling, LLC, completed the purchase of a new drilling rig intended for use in the Utica and Marcellus Shale formations located in southeastern Ohio and West Virginia. Costs to acquire and install the rig were $10.1 million, of which $1.1 million remains due in equal installments over twelve months beginning in June 2013.

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Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

Item 9A. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

The Company's management, including the Chief Executive Officer (CEO), Chief Financial Officer (CFO) and Chief Accounting Officer (CAO), performed an evaluation of the effectiveness of the Company's disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended) as of December 31, 2012. Based upon that evaluation, the CEO and CFO concluded that, as a result of the material weaknesses in internal control over financial reporting that are described below in Management's Report on Internal Control Over Financial Reporting, the Company's disclosure controls and procedures were not effective as of December 31, 2012.

Management's Report on Internal Control Over Financial Reporting

Our independent registered public accounting firm has audited the effectiveness of our internal control over financial reporting as of December 31, 2012 as stated in their report, dated June 14, 2013, which appears herein.

Management is responsible for establishing and maintaining adequate internal control over financial reporting. The Company's internal control over financial reporting is a process, under the supervision of the CEO , CFO and CAO, designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the Company's financial statements for external purposes in accordance with generally accepted accounting principles.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Our management, with the participation of our CEO, CFO, CAO and outside consultants, has conducted an assessment of the effectiveness of the Company's internal control over financial reporting as of December 31, 2012 based on the criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Management excluded from our assessment the internal control over financial reporting of Virco, which was acquired on November 2, 2012 and of TransTex Hunter, the assets of which were initially acquired on April 2, 2012. The subsidiaries excluded from management's assessment of internal controls over financial reporting made up combined total assets of approximately 8 percent and 3 percent of total revenue of the corresponding consolidated financial statement amounts as of and for the year ended December 31, 2012. Based on the assessment, management has concluded that, as of December 31, 2012, the Company's internal control over financial reporting was not effective due to the material weaknesses described below.

A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the Company's annual or interim financial statements will not be prevented or detected on a timely basis. Management has identified material weaknesses in the internal control over financial reporting relating to the following:

Effective Control Environment to Meet the Company's Growth

• In certain areas the Company did not have sufficient personnel with an appropriate level of knowledge, experience and training commensurate with the growth of the Company's corporate structure and financial reporting requirements.  The Company did not effectively establish controls, and upgrade resources around internal audit, tax, financial reporting and certain accounting areas.  Adequate controls were not designed and in place to achieve operating effectiveness thereby resulting in the aforementioned deficiency. The Company did not establish effective controls over risk assessments commensurate with the growth of the Company's corporate structure and financial reporting requirements.  Specifically, the Company did not have adequate processes to evaluate and scope business and information technology risks.  This deficiency resulted in either not having adequate controls designed and in place or not achieving the intended operating effectiveness of controls.

• The Company did not design or maintain effective controls for its wholly-owned subsidiary, Magnum Hunter Production, Inc. (MHP), specifically around segregation of duties and timeliness of reporting with respect to revenue, joint interest, partnership accounting, and division of interests.

These material weaknesses above also contributed to the material weaknesses described below.

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Financial Reporting

• The Company did not maintain effective controls over the recording and retention of journal entry support. The Company did not maintain effective monitoring of controls to ensure that journal entries were properly prepared with sufficient supporting documentation or were reviewed and approved to ensure the accuracy and completeness of the journal entries. 

• The Company did not maintain effective controls over financial statement disclosures to ensure completeness and accuracy of condensed consolidating guarantor financial statement footnote information for the nine-month period ended September 30, 2012. The Company was unable to demonstrate remediation of this deficiency as of December 31, 2012, as the control require at least two quarters for remediation testing.

• The Company did not maintain effective controls over the quarterly and annual financial reporting processes, with respect to preparation, review, supervision, and monitoring of accounting operations. The Company did not maintain effective controls over reconciliation of certain accounts and timely preparation and review of quarterly financial information.

• The Company did not design or maintain effective controls over the recording of capitalized interest regarding the recorded costs of pipeline assets and were understated in prior quarters for interest costs for debt related to assets under construction that had not been placed in service.

• The Company did not design effective controls over share-based compensation expense, which was recorded in the Company's general and administrative expenses.  The Company did not design effective controls related to the review of supporting details, including the accuracy of the volatility inputs and calculations and the manual journal entries for share-based compensation expense.  This control deficiency resulted in a misstatement of the Company's general and administrative expense and share-based compensation related disclosures for the three and six-month periods ended June 30, 2012 and resulted in the restatement of the financial statements for such fiscal periods, and resulted in revised condensed consolidated financial statements for the three-and nine-month periods ended September 30, 2012. The Company was unable to demonstrate remediation of this deficiency as there were not enough transactions to test for remediation as of December 31, 2012.

Leasehold Property Costs

• The Company did not design effective controls to provide reasonable assurance over the accuracy and completeness of master files of lease records.  The Company did not have effective controls over the allocation of leasehold property costs due to unreliable supporting lease and property records.

• The Company did not maintain effective controls over completeness and accuracy of the well acreage data resulting in inaccurate transfers of leasehold property costs during the year.

• The Company did not have effective controls over review of properties for expirations and impairments of unproven acreage, as events were not properly considered that affected the value of leases.

• The Company did not maintain adequate supporting documentation or effective controls over the review of changes to division of interest records.

Complex Accounting Issues

• The Company did not design an effective control environment over complex equity instruments including convertible preferred stock and related arrangements. This material weakness resulted in the restatement of the Company's Series A Convertible Preferred Units of Eureka Hunter Holdings, LLC, the Company's preferred stock embedded derivative liabilities, and the loss on derivatives and related disclosures for the three and six-month periods ended June 30, 2012. This issue also resulted in adjustments to the Company's condensed consolidated financial statements for the three-and nine-month periods ended September 30, 2012. The Company was unable to demonstrate remediation of this deficiency as of December 31, 2012 as the control requires at least two quarters for remediation testing.

Tax

• The Company did not design or maintain effective controls over income tax accounting, specifically related to the accuracy of the net operating loss deduction carryover disclosed in the Company's financial statements. 

Remediation Plan

The Board of Directors, the Audit Committee, and senior management of the Company understand their responsibility to provide the appropriate “tone at the top” to ensure the Company achieves effective and comprehensive internal controls over financial reporting.   In the second quarter of 2012 management began to expand staff, in an effort to establish and maintain effective and sustainable controls. As discussed below, this has resulted in the Company dedicating substantial resources and to hiring additional accounting personnel with greater expertise. The Company also began engaging outside consultants, accounting firms, and investing in updated technology.

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Effective Control Environment to Meet the Company's Growth

Senior management has evaluated its business and control environment needs and addressed these items by hiring and replacing resources which started in the second quarter of 2012.  The Company added a new Chief Accounting Officer, corporate level controllers, regional controllers, and managers of internal audit, tax, expenditure accounting, and financial reporting.  Management will continue to increase staffing as needed to address business and control environment risks.  Management will continue to supplement the Company's in-house internal audit and tax functions in 2013 with the use of a “Big Four” accounting firm as needed.  Additionally, management will develop a formal top-down risk assessment of the Company's personnel, processes, and technology as such relates to financial reporting to properly identify, develop, and maintain internal controls. As noted above, investments in the control environment have been made through existing resources and a re-designed risk assessment process.

Financial Reporting

In the fourth quarter of 2012, management began reorganizing the roles and responsibilities over the accounting and financial reporting processes. This effort has included the addition of a financial reporting manager and implementing additional detective and monitoring controls to remediate the material weaknesses.  This improvement in processes is continuing and some new or revised controls were put in place at year end.   

Areas of particular focus include:

• Journal entries

• Reconciliations

• Consolidations

• Financial reporting

• Accounting processes for share-based compensation

Management is also implementing additional internal controls with regards to share-based compensation activities including:

• Reviewer checklists 

• Implementation of a new software system

• Compensation expense

• Valuation of share-based compensation expense

Leasehold Property Costs

Management is implementing activities to ensure that there are appropriate effective controls over the leasehold property accounts.  Management is implementing controls over documentation retention and accuracy of records for leasehold property accounts.

In 2013, management will continue the process of transitioning the manually tracked leases to an automated land system in order to improve the completeness, accuracy, and control of the data.  Controls over maintenance of lease records will include authorization for updates to lease files, prevention of unauthorized access to or alteration of data, periodic monitoring of critical dates and decisions to pay delay rentals or lease extensions, and adequate support for and reconciliation of subsidiary property records.  Additional processes and controls will be implemented to address completeness and accuracy of well status, the review of acreage analysis, and proper review of related transfers of leasehold property costs.

Management plans to take appropriate measures to ensure that proved property costs and unproved leasehold costs are reviewed periodically for impairment. These measures include performing property analysis in order to identify any indicators that unproved properties may be impaired including lease expiration dates, likelihood of extending leases, unsuccessful wells drilled on the leases, commodity prices, operational and regulatory issues and future drilling plans. The remediation steps include coordination between the land, engineering, operating, and finance departments to develop processes and controls.

Management plans to implement additional review controls over setup and maintenance of division of interests records and retention of adequate support and documentation, through timely and coordinated communication between the land department and accounting.

Complex Accounting Issues

Management has added additional technical staff in tax, accounting and financial reporting to assist in the review of complex transactions including complex equity instruments for financial statement implications.  Management has retained outside consultants, including “Big Four” accounting firms, when management determines the complexity of certain transactions warrants additional review.  Further, management is evaluating accounting and financial reporting controls for purchase accounting, equity instrument accounting and related income tax accounting matters.

Tax

The Company has hired a full-time tax manager and engaged a “Big Four” accounting firm to provide advisory services on tax matters.

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Senior management is developing a formal remediation plan and time-line and will monitor the Company's remediation efforts.  Under the direction of the CEO, CFO, and the CAO reporting to the Audit Committee of the Board of Directors, management will continue to assess the design of the Company's control environment to improve the effectiveness of internal control over financial reporting.

Item 9B. OTHER INFORMATION

None

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PART III

Item 10. DIRECTORS, EXECUTIVE OFFICERS, AND CORPORATE GOVERNANCE

Corporate Governance Guidelines

The business, property and affairs of Magnum Hunter are managed by our Chief Executive Officer under the direction of our Board of Directors. The Board is responsible for establishing broad corporate policies and for overall performance and direction of Magnum Hunter, but is not involved in day-to-day operations. Members of the Board keep informed of Magnum Hunter's business by participating in Board and committee meetings, by reviewing analyses and reports sent to them regularly and through discussions with the Chief Executive Officer and other executive officers.

We have adopted Corporate Governance Guidelines that address significant issues of corporate governance and set forth the procedures by which the Board carries out its responsibilities. Among the areas addressed by the guidelines are director qualifications and responsibilities, Board committee responsibilities, selection and election of directors, director compensation and tenure, Board meeting requirements and Board and committee performance evaluations. The Governance Committee is responsible for assessing and periodically reviewing the adequacy of these guidelines. Our Corporate Governance Guidelines are available on the Company's website under the “Corporate Governance” link under the “Investors” tab at www.magnumhunterresources.com.

Biographical Information of Our Directors

The following is a brief biography of each of our directors. The biographies include information regarding each individual's service as a director of Magnum Hunter, business experience, director positions at public companies held currently or at any time during the last five years, and the experience, qualifications, attributes or skills that caused our Board and the Governance Committee to determine that the person should serve as a director of Magnum Hunter.

J. Raleigh Bailes, Sr., age 64, has been a director of Magnum Hunter since 2006. Mr. Bailes has been a partner of Bailes, Bates & Associates, LLP, a tax and accounting firm, since March 2003. Between November 1999 and March 2003, Mr. Bailes owned and managed J. Raleigh Bailes, CPA, a tax and accounting firm. Mr. Bailes is admitted to practice before the U.S. Tax Court and is licensed by the State of Texas as a certified public accountant. The Company's change to a “large accelerated filer” under applicable SEC rules and its increased subjectivity to Sarbanes-Oxley Act compliance were factors taken into account by the Board in determining that Mr. Bailes' tax, accounting and industry experience is beneficial to the Company.

Brad Bynum, age 43, has been a director of Magnum Hunter since 2006. Mr. Bynum currently serves as Director and President of Howard Energy Partners, an independent midstream energy services company, a position he has held since December 2011. Mr. Bynum previously served as Director, President and Chief Financial Officer of Howard Energy Partners from July 2011 to December 2011. Mr. Bynum was Chief Financial Officer of Hall-Houston Exploration Partners, L.L.C., a privately-held oil and gas exploration and development company, from February 2005 to July 2011. Between 1997 and February 2005, Mr. Bynum was employed at Merrill Lynch Pierce Fenner & Smith, or Merrill Lynch, most recently as a Director of Investment Banking in Merrill Lynch's Global Energy and Power Investment Banking Group, in Houston, Texas. Mr. Bynum received a degree in accounting from Texas A&M University and an M.B.A. from Rice University. Mr. Bynum's industry experience, industry and investment banking contacts and financial expertise were taken into consideration by the Board in determining that his service is beneficial to the Company.

Victor G. Carrillo, age 48, has been a director of Magnum Hunter since January 2011. Mr. Carrillo currently serves as President and Chief Operating Officer and a director of Zion Oil & Gas, Inc., or Zion, a company engaged in oil and gas exploration primarily in Israel and areas located on-shore between Haifa and Tel Aviv, a position he has held since October 2011. Mr. Carrillo has also served as a director of Zion since September 2010, and he served as an executive vice president and a director of Zion from January 2011 to October 2011. From 2003 to 2010, Mr. Carrillo served as a commissioner on the Texas Railroad Commission. During his time of service on the Texas Railroad Commission, Mr. Carrillo also served as Chairman of the Governor's Texas Energy Planning Council. During his career, Mr. Carrillo has also served as the Chairman of the Outer Continental Shelf Advisory Committee to the U.S. Secretary of the Interior, Vice Chairman of the Interstate Oil and Gas Compact Commission, a member of the Committee on Gas for the National Association of Regulatory Utility Commissioners and a member of the board of directors of Advisors to the Texas Journal of Oil, Gas & Energy Law at the University of Texas School of Law. Hispanic Business Magazine has named Mr. Carrillo one of the 100 Most Influential Hispanics in the United States. Mr. Carrillo received a B.S. in geology from Hardin-Simmons University, an M.S. in geology from Baylor University, a Juris Doctorate with emphasis in both environmental and oil and gas law from the University of Houston Law Center and an honorary Doctorate from Hardin-Simmons University. Mr. Carrillo's vast educational and professional experience related to the crude oil and natural gas exploration and production segment of the energy industry was taken into consideration by the Board in determining that his service is beneficial to the Company.

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Gary C. Evans, age 56, has been a director of Magnum Hunter since 2009. Mr. Evans was appointed as Chairman of the Board and Chief Executive Officer of the Company in May 2009. Mr. Evans previously founded and served as the Chairman and Chief Executive Officer of Magnum Hunter Resources, Inc., or MHRI, an unrelated NYSE-listed company of similar name, for twenty years before selling MHRI to Cimarex Energy for approximately $2.2 billion in June 2005. In 2005, Mr. Evans formed Wind Energy, LLC, a renewable energy company which was subsequently acquired in December 2006 by GreenHunter Resources, Inc., or GreenHunter, an NYSE MKT-listed company focusing on water resource management as it relates to the oil and gas industry. Mr. Evans has served as Chairman of GreenHunter since December 2006 and previously served as Chief Executive Officer from December 2006 through December 2012. Mr. Evans serves as an individual trustee of TEL Offshore Trust, a publicly-listed oil and gas trust, and is a director of Novavax Inc., a NASDAQ-listed clinical-stage vaccine biotechnology company. Mr. Evans was recognized by Ernst & Young LLP as the Southwest Area 2004 Entrepreneur of the Year for the Energy Sector and was subsequently inducted into the World Hall of Fame for Ernst & Young Entrepreneurs. Mr. Evans serves on the Board of the Maguire Energy Institute at Southern Methodist University and speaks regularly at energy industry conferences around the world on the current affairs of the oil and gas business. The Board has concluded that the Company benefits from Mr. Evans' extensive oil and gas industry expertise, his expertise as a chief executive officer with publicly held energy companies, his industry, investment banking and commercial lending contacts and his vast professional experience.

Stephen C. Hurley, age 63, has been a director of Magnum Hunter since October 2011. Mr. Hurley has 37 years of experience in the oil and gas industry. He is a former member of the board of directors of Brigham Exploration Company, serving from December 2002 to December 2011 when the company was sold to Statoil ASA. He also served on the audit and compensation committees of Brigham Exploration Company from January 2003 to December 2011. Mr. Hurley is a former President and director of Hunt Oil Company, having been associated with Hunt Oil Company from August 2001 to August 2011. Prior to joining Hunt Oil Company, Mr. Hurley served as Chief Operating Officer, Executive Vice President and a director for Chieftain International, Inc. from August 1995 to August 2001. Prior to joining Chieftain International, Inc., Mr. Hurley was Vice President of Exploration and Production for Murphy Exploration and Production Company. Earlier, he was affiliated with Ocean Drilling and Exploration Company and Exxon Company USA. Mr. Hurley holds a B.S. and an M.S. from the University of Arkansas and an advanced degree in business studies from Harvard University. The Board has concluded that the Company benefits from Mr. Hurley's extensive executive-level experience in the energy industry.

Joe L. McClaugherty, age 61, has been a director of Magnum Hunter since 2006. For the past 21 years, Mr. McClaugherty has been a senior partner of McClaugherty & Silver, P.C., a full service firm engaged in the practice of civil law, including oil and gas law, located in Santa Fe, New Mexico. Mr. McClaugherty is admitted to the State bars of New Mexico, Texas and Colorado, as well as the Federal bars of the Districts of New Mexico and Colorado, the United States Court of Appeals for the Tenth Circuit and the United States Supreme Court. The Board has concluded that Mr. McClaugherty's business and law degrees from the University of Texas at Austin, his approximately 36 years of legal experience in a broad-based civil practice and his extensive experience on boards of both international and domestic companies are beneficial to the Company.

Ronald D. Ormand, age 54, has been a director of Magnum Hunter since 2009. Mr. Ormand was appointed as Chief Financial Officer and Executive Vice President and a director of the Company in May 2009. Mr. Ormand has over 25 years of investment and commercial banking experience in the energy industry. From 1988 to December 2004, Mr. Ormand was with CIBC World Markets, or CIBC, and Oppenheimer & Co., which CIBC acquired in 1997. From 1997 to 2004, Mr. Ormand served as managing director and head of CIBC's U.S. Oil and Gas Investment Banking Group and a member of the firm's Investment Banking Management Committee. From April 2005 to October 2007, he served as a managing director with West LB, where he served as head of the Oil and Gas Investment Banking Group for the Americas.Prior to joining CIBC in 1988, Mr. Ormand worked in various investment banking positions. Mr. Ormand also served as President and Chief Financial Officer and a director of Tremisis Energy Acquisition Corporation II, an NYSE-listed company, from November 2007 to March 2009 and served on the board of directors of GreenHunter from December 2008 to January 2013. Mr. Ormand received a B.A. and an M.B.A. from the University of California at Los Angeles and attended Cambridge University in Cambridge, England where he studied economics. The Board has concluded that Mr. Ormand's extensive investment banking and commercial banking experience and related industry contacts facilitate the Company's acquisition and financing activities.

Steven A. Pfeifer, age 50, has been a director of Magnum Hunter since May 2006. Since January 2005, he has served as the managing partner of P. O. & G. Resources, LP, a privately held oil and natural gas exploration and production company with holdings in Texas, New Mexico, Oklahoma, Kansas, Montana, North Dakota, Wyoming, and Mississippi. Mr. Pfeifer has also served as a director of TS World Development Fund, Ltd., a fund that invests primarily in exchange-listed equities, since August 2010. From September 1999 to September 2004, Mr. Pfeifer was employed by Merrill Lynch, Pierce, Fenner, & Smith Incorporated, or Merrill Lynch, initially as the integrated oil stock analyst and later as First Vice President in charge of Merrill Lynch's Global Energy Research team. From April 1993 to September 1999, he was a Wall Street energy equity analyst in the New York offices of Deutsche Bank AG, Paine Webber and Company, and Prudential Securities. From August 1988 to April 1993, Mr. Pfeifer worked as a financial analyst in Amoco Corporation's strategic planning, exploration, and Russian venture groups in Houston and Chicago. From December 1984 to May 1986, he worked as a petroleum engineer in Atlantic Richfield Company's Tulsa, Denver and Midland offices. Mr.

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Pfeifer received a B.S. in petroleum engineering from the University of Texas at Austin, and an M.B.A. from the Wharton School of the University of Pennsylvania. He is a member of the Society of Petroleum Engineers (SPE) and the Independent Petroleum Association of America (IPAA). The Board has concluded that Mr. Pfeifer's industry experience, financial expertise and technical background are beneficial to the Company.

Jeff Swanson, age 57, has been a director of Magnum Hunter since 2009. Mr. Swanson currently serves as the President and Chief Executive Officer of GrailQuest Corp., a privately held company providing software and services to the oil and gas industry, a position he has held since January 1999. Mr. Swanson is also the President and Chief Executive Officer of Swanson Consulting Inc., a provider of geological and engineering geosciences studies for the oil and gas industry. He has been actively engaged in the exploration and production sectors of the oil and gas industry for over 30 years. Mr. Swanson co-founded Stratamodel, Inc., which developed the first commercially available 3-D geocellular technology, now a standard workflow tool in the oil and gas industry. He is co-author of two patents including ReservoirGrail, an increasingly used reservoir volumetric material balancing simulator. Mr. Swanson received his B.B.A. from Southern Methodist University and is a member of the Society of Petroleum Engineers (SPE), Association of Petroleum Geologists (AAPG), Houston Geological Society (HGS), Independent Petroleum Association of America (IPAA) and the National Stripper Well Association (NSWA). He is an individual trustee of TEL Offshore Trust, a publicly-listed oil and gas trust. Mr. Swanson is a published author of several papers and articles regarding various technologies and methodologies used for enhancing and increasing the value of mature oil and gas fields. The Board has concluded that Mr. Swanson's experience as a chief executive officer and his oil and gas industry expertise, particularly his technical expertise with respect to oil field and reserve estimation technology, are beneficial to the Company.

Biographical Information of Our Executive Officers

The following is a brief biography of each of our executive officers other than Messrs. Evans and Ormand, whose biographical information is included above.

Brian G. Burgher, age 51, has been Senior Vice President of Land for the Company since March 2011. He was Vice President of Land for the Company from September 2009 until he was appointed Senior Vice President of Land in March 2011. Mr. Burgher was formerly Vice President of Land at Sharon Resources, Inc. from September 2004 until the company was acquired by Magnum Hunter in September 2009. As Vice President of Land at Sharon Resources, Inc., Mr. Burgher was responsible for all land and legal activities related to oil and gas exploration and development in North America. Mr. Burgher brings more than 25 years of continuous experience in land related areas to our Company. Mr. Burgher is a fourth-generation oil and gas landman. In addition to being an independent producer, Mr. Burgher has worked as field landman, a field land broker, an in-house landman, and a land manager. Mr. Burgher attended both Baylor University and the University of Houston.

R. Glenn Dawson, age 56, currently serves as Executive Vice President of the Company and as President of our Williston Basin Division. Mr. Dawson joined the Company in May 2011 when it acquired NuLoch Resources, Inc., renamed Williston Hunter Canada, Inc., a company for which Mr. Dawson had served as President and CEO. He has over 30 years of experience in oil and gas exploration in North America. His principal responsibilities have involved the generation and evaluation of drilling prospects and production acquisition opportunities. In the early stages of his career, Mr. Dawson was employed as an exploration geologist by Sundance Oil and Gas, Inc., a public company located in Denver, Colorado, concentrating on their Canadian operations. From December 1985 to September 1998, Mr. Dawson held a variety of managerial and technical positions with Summit Resources, a then-public Canadian oil and gas exploration and production company, including Vice President of Exploration, Exploration Manager and Chief Geologist. He served as Vice President of Exploration with PanAtlas Energy Inc., a then-public Canadian oil and gas exploration and production company, from 1999 until its acquisition by Velvet Exploration Ltd. in July 2000. Mr. Dawson was a co-founder and Vice President of Exploration of TriLoch Resources Inc., a then-public Canadian oil and gas exploration company, from 2001 to 2005, until it was acquired by Enerplus Resources Fund. As a result of the sale of TriLoch Resources Inc. to Enerplus Resources Fund, Mr. Dawson founded NuLoch Resources, Inc. in 2005. Mr. Dawson graduated in 1980 from Weber State University of Utah with a Bachelor's degree in Geology and attended the University of Calgary from 1980 to 1982 in the Masters Program for Geology.

James W. Denny, III, age 65, currently serves as Executive Vice President of the Company and as President of our Appalachian Division. Mr. Denny has served as an Executive Vice President of the Company since March 2008. Mr. Denny brings more than 35 years of industry related experience to the Company. Prior to joining Magnum Hunter, Mr. Denny served as President and Chief Executive Officer of Gulf Energy Management Company, a wholly-owned subsidiary of Harken Energy Corporation from January 2005 to October 2007. Mr. Denny served in various positions of responsibility during his tenure with Harken Energy Corporation from 1998 to 2005. In his capacity as President and Chief Executive Officer of Gulf Energy Management, Mr. Denny was responsible for all facets of Gulf Energy Management's North American operations. He is a registered Professional Engineer (Louisiana) and is a Certified Earth Scientist. He is also a member of various industry associations, including the American Petroleum Institute, the National Society of Professional Engineers, the Society of Petroleum Engineers, and the Society of Petroleum Evaluation Engineers. He is a graduate of the University of Louisiana-Lafayette with a B. S. in Petroleum Engineering.

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H.C. “Kip” Ferguson, III, age 48, currently serves as Executive Vice President of the Company and as President of our Eagle Ford Shale Division. Mr. Ferguson has served as an Executive Vice President of the Company since October 2009. Mr. Ferguson was formerly the President of Sharon Resources, Inc., renamed Eagle Ford Hunter, Inc., from September 1999 until the company was acquired by Magnum Hunter in October 2009. As President of Sharon Resources, Inc., Mr. Ferguson's responsibilities included supervision of the day-to-day activities of that company, budget planning for operations, supervision of the development of exploratory projects within numerous basins and involvement in extensive field studies and trend analysis, using advanced drilling and completion technology. Mr. Ferguson brings more than 20 years of exploration and development experience in several major U.S. basins to the Company. Mr. Ferguson served on the board of Sharon Resources, Inc. and Sharon Energy Ltd. from September 1999 to October 2009. Mr. Ferguson served on the board for Diaz Resources, Inc. from 2005 to 2009. Mr. Ferguson is a third-generation geologist with a degree in Geology from the University of Texas at Austin.

Paul M. Johnston, age 58, has served as Senior Vice President and General Counsel of the Company since June 2010. Mr. Johnston has over 30 years of increasing responsibility and management experience in all facets of general corporate, finance, securities and regulatory related legal matters. He is a former partner with the Dallas-based law firm, Thompson & Knight, LLP, representing both private and publicly held companies during his twenty-year career with the firm. Mr. Johnston also had ten years of in-house counsel experience before joining Magnum Hunter, including his service as Vice President and Corporate Counsel, for an NYSE-listed Fortune 250 company from 2000 to 2007, and he most recently served as General Counsel for an SEC-registered investment advisor involved in the management of onshore and offshore hedge funds from 2007 to 2010. A 1977 graduate of Texas Tech University, Mr. Johnston received his Juris Doctorate from Texas Tech University in 1980.

Don Kirkendall, age 56, has served as Senior Vice President of the Company and as Senior Vice President of our subsidiary, Eureka Hunter Pipeline, LLC, since June 2010. Mr. Kirkendall has served as a Senior Vice President of the Company since September 2009. Prior to serving in his current roles, Mr. Kirkendall served as President of Magnum Hunter from March 2006 to September 2009 and as Executive Vice President of Magnum Hunter from August 2005 to March 2006. Mr. Kirkendall also served on the Company's Board from August 2005 to September 2009. Prior to his employment with Magnum Hunter in August 2005, Mr. Kirkendall was self-employed as a consultant focused on oil and gas upstream and midstream operations. Mr. Kirkendall brings more than 32 years of diversified energy experience to Magnum Hunter. His background includes interstate pipeline business along with natural gas marketing and exploration experience. He co-founded and managed a successful natural gas marketing company along with an associated exploration company that specialized in drilling Texas Gulf Coast and South Texas oil and gas prospects. Mr. Kirkendall received his B.B.A. from Southwest Texas State University.

Fred J. Smith, Jr., age 60, has served as Senior Vice President of Accounting and Chief Accounting Officer of the Company since October 2012. Prior to joining the Company, Mr. Smith was the Corporate Controller of Pioneer Natural Resources from 2008 to 2012. Prior to that time, Mr. Smith was employed by ConocoPhillips and held leadership positions in the Lower 48 Exploration and Production Finance division and Global Financial Services organizations from 2000 to 2008. Mr. Smith was Vice President of Finance and Chief Financial Officer from 1998 to 2000 of River Gas Corporation, a privately-owned coal bed methane operator which was acquired by ConocoPhillips in 2000. Mr. Smith joined ConocoPhillips following the acquisition of River Gas Corporation. Mr. Smith was previously employed by The Louisiana Land & Exploration Company in New Orleans, Louisiana, for over 20 years where he held a number of management positions within various financial and operational accounting areas. Mr. Smith began his professional career as a member of the audit staff of Ernst & Young LLP. Mr. Smith graduated from the University of New Orleans with a Bachelor of Science degree in Accounting and has been a licensed CPA since 1975.

Director Nomination Process

In assessing the qualifications of candidates for nomination as director, our Governance Committee and our Board consider, in addition to qualifications set forth in our bylaws, each potential nominee's:

• Personal and professional integrity, experience, reputation and skills;

• Ability and willingness to devote the time and effort necessary to be an effective Board member; and

• Commitment to act in the best interests of Magnum Hunter and its stockholders.

Consideration is also given to the requirement under the NYSE listing standards that the Board be composed of a majority of independent directors, as well as the qualifications required for membership on our Board committees under the NYSE listing standards and various other regulations.

In addition, the Board looks for nominees who possess a broad range of business experience, diversity (“diversity” being broadly construed to mean a variety of opinions, perspectives, experiences and backgrounds, such as gender, race and ethnicity differences, as well as other differentiating characteristics, all in the context of the requirements of our Board at that point in time), professional skills, geographic representation and other qualities it considers important in light of our business plan. The Board evaluates the makeup of its membership in the context of the Board as a whole, with the objective of recommending a group that

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can effectively work together using its diversity of experience to see that Magnum Hunter is well managed and represents the interests of the Company and its stockholders.

Under the terms of his then-existing employment agreement, Gary C. Evans, our Chairman of the Board, was entitled to nominate one member to our Board. He nominated Jeff Swanson in August 2009, and Mr. Swanson was elected to the Board at that time.

Our common stockholders may submit the names and other information regarding individuals they wish to be considered for nomination as directors by writing to the corporate secretary at the address indicated on the first page of this annual report on Form 10-K.

Board's Role in Risk Oversight

Our Board of Directors is responsible for the Company's risk-oversight function and is actively involved in the oversight of risks that could affect our Company. Management is responsible for the day-to-day management of risks we face, while the Board, as a whole and through its committees, has responsibility for the oversight of risk management.

The Audit Committee of our Board is charged by its charter with, among other duties, reviewing the significant accounting principles, policies and practices followed by the Company; reviewing financial, investment and risk management policies followed by Magnum Hunter in operating its business activities; reviewing the Company's annual audited financial statements; reviewing the effectiveness of our independent audits, including approval of the scope of and fees charged in connection with our annual audit and quarterly reviews; appointing and overseeing the work of the Company's independent auditor; and reviewing and discussing audit-related and independence matters with management, the Board and the Company's independent auditors. The Audit Committee must regularly update the Board and make appropriate recommendations. Additionally, at Audit Committee meetings, our management may present a particular area of risk, either independently as a result of its assessment of materiality or at the request of the Audit Committee. The Audit Committee works with management to address the strengths and weaknesses of the policies in each area presented or separately assessed. In addition to the formal compliance program, the Board and the Audit Committee encourage management to promote a corporate culture that understands risk management and incorporates it into the overall corporate strategy and day-to-day business operations.

Board of Directors' Leadership Structure

Gary C. Evans currently serves as Chairman of the Board in addition to his role as our Chief Executive Officer. The Board believes that our Chief Executive Officer is currently best situated to serve as Chairman because he is the director most familiar with our business and most capable of effectively identifying strategic priorities and leading the discussion and execution of strategy. Our independent directors bring experience, oversight and expertise from outside the Company, while the Chief Executive Officer brings company-specific experience and expertise. The Board believes that the combined role of Chairman and Chief Executive Officer facilitates information flow between management and the Board.

The Board appointed Mr. McClaugherty as the Company's lead independent director for a one-year term commencing on April 13, 2013. The additional responsibilities of the lead independent director include: (i) chairing executive sessions where independent directors meet either before or after regularly scheduled Board meetings and, as appropriate, providing prompt feedback to the Chairman of the Board and the CEO, (ii) calling, setting the agenda for and chairing periodic executive sessions and meetings of the independent directors and reporting accordingly to the full Board, (iii) chairing Board meetings in the absence of the Chairman of the Board, (iv) providing feedback to the Chairman of the Board and CEO on corporate and Board policies and strategies and acting as a liaison between the Board and the CEO, (v) facilitating one-on-one communication between directors and committee chairs and the Chairman of the Board and CEO and other senior managers to keep abreast of their perspectives, (vi) in concert with the Chairman of the Board and CEO, advising on the agenda and schedule for Board meetings and strategic planning sessions based on input from directors, (vii) providing advance feedback on background materials and resources necessary or desirable to assist the directors in carrying out their responsibilities, and reviewing Board materials and background papers in advance of Board meetings, (viii) interviewing potential candidates for election to the Board, (ix) holding one-on-one discussions with individual directors when deemed appropriate by the Chairman of the Board or the lead independent director, (x) overseeing the evaluation of individual members of the Board and of the CEO and (xi) carrying out such other duties as are requested by the Board from time to time.

Code of Conduct and Ethics

We have adopted a Code of Conduct and Ethics that applies to our directors, officers and employees, including our principal executive officer and principal financial and accounting officers. This code assists employees in resolving ethical issues that may arise in complying with its policies. The purpose of this code is to promote, among other things:

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• Honest and ethical conduct, including ethical handling of actual or apparent conflicts of interest;

• Full, fair, accurate and timely disclosure in filings with the SEC and other public disclosures;

• Compliance with the law and other regulations;

• Protection of our assets;

• Insider trading policies; and

• Prompt internal reporting of any violation of the code.

This code is available on our website at www.magnumhunterresources.com. We will provide this code free of charge to stockholders who request it. We will post information regarding any amendments to, or waivers from, the provisions of this code that apply to our principal executive officer, principal financial officer, principal accounting officer or controller or persons performing similar functions, on our website.

The Company maintains a third-party managed whistleblower hotline whereby employees can submit complaints or concerns regarding financial statement disclosures, accounting matters, internal accounting controls, auditing matters, compliance with applicable laws, rules and regulations and compliance with the Company's policies and procedures, including matters arising under our Code of Conduct and Ethics.

Stockholder Communications with the Board of Directors

Stockholders and other interested parties who wish to communicate with our non-management directors or the entire Board may do so by making a submission in writing to “Board of Directors (independent members)” or “Board,” respectively, in care of our Corporate Secretary at 777 Post Oak Boulevard, Suite 650, Houston, Texas 77056. Our Corporate Secretary will then forward all such communications (excluding routine advertisements and business solicitations) to each member of our Board, or the applicable individual directors.

We reserve the right to screen materials sent to our directors for potential security risks and/or harassment purposes. Stockholders also have an opportunity to communicate with our Board at our annual meetings of stockholders.

Attendance at Meetings of Stockholders

All directors are expected to attend annual meetings of our stockholders, subject to occasional excused absences due to illness or unavoidable conflicts. All of our directors attended the 2012 annual meeting of our stockholders.

Our Board Committees

The Board of Directors oversees the management of the business and affairs of our Company. The Board has three standing committees: the Audit Committee, the Compensation Committee and the Governance Committee, each of which is described below. Each committee operates under a written charter adopted by the Board.

In 2012, the Board met 10times and acted by unanimous written consent nine times; the Audit Committee met 20 times; the Compensation Committee met nine times; and the Governance Committee met four times. Each director attended more than 75% of the meetings of the Board and the committees on which he served. The following table sets forth the committees of the Board and their members as of the date of the filing of this annual report:

Director	Audit Committee	Compensation Committee	Governance Committee
J. Raleigh Bailes, Sr.	*ü
Brad Bynum
Victor G. Carrillo			*ü
Gary C. Evans
Joe L. McClaugherty	ü	*ü
Stephen C. Hurley	ü	ü	ü
Ronald D. Ormand
Steven A. Pfeifer
Jeff Swanson		ü	ü

(*) Denotes Chair

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Website Availability of Documents

This annual report on Form 10-K for the fiscal year ended December 31, 2012, the charters of the Audit Committee, Compensation Committee and Governance Committee, our Code of Conduct and Ethics and our Corporate Governance Guidelines can be found on our website at www.magnumhunterresources.com. The committee charters, Code of Conduct and Ethics and Corporate Governance Guidelines are located under the “Corporate Governance” link under the “Investors” tab. Unless specifically stated herein, documents and information on our website are not incorporated by reference in this annual report.

Audit Committee

Our Audit Committee assists the Board in fulfilling its oversight responsibilities by, among other things, reviewing the financial information that will be provided to the stockholders and others; reviewing the systems of internal controls that management has established; appointing, retaining and overseeing the performance of independent accountants; and overseeing our accounting and financial reporting processes and the audits of our financial statements. Our Audit Committee also consults with our management and our independent registered public accounting firm prior to the presentation of financial statements to stockholders and, as appropriate, initiates inquiries into aspects of our financial affairs. Our Audit Committee, along with our Governance Committee, are responsible for establishing procedures for the receipt, retention and treatment of complaints regarding accounting, internal accounting controls or auditing matters, and for the confidential, anonymous submission by our employees of concerns regarding questionable accounting or auditing matters. In addition, our Audit Committee is directly responsible for the appointment, retention, compensation and oversight of the work of our independent auditors, including approving services and fee arrangements.

The current members of our Audit Committee are Messrs. Bailes, Hurley and McClaugherty. Mr. Bailes serves as Chairman of the Audit Committee.

Our Audit Committee must include at least one member who has been determined by our Board to meet the qualifications of an audit committee financial expert in accordance with SEC rules. Our Board has determined that all of the members of our Audit Committee meet the independence and other requirements for audit committee membership of the NYSE listing standards and SEC requirements. The Board has also determined that Mr. Bailes is an audit committee financial expert, as that term is defined in the SEC rules. Mr. Bailes is a certified public accountant and has been engaged in a public accounting and tax practice for approximately the last 39 years. Each of the members of our Audit Committee is independent, as independence for Audit Committee members is defined by the rules of the NYSE. In addition, Messrs. Hurley and McClaugherty have an understanding of fundamental financial statements.

Since its formation in April 2006, the Audit Committee has approved all audit fees, audit-related fees, tax fees and special engagement fees. The Audit Committee approved 100% of such fees for the year ended December 31, 2012.

Based on the Audit Committee's review and discussions noted above, the Audit Committee recommended to our Board of Directors that Magnum Hunter's audited financial statements for the year ended December 31, 2012 be included in this annual report on Form 10-K for the year ended December 31, 2012.

Compensation Committee

Our Board's Compensation Committee discharges the Board's responsibilities relating to the compensation of our directors and officers. The Compensation Committee has the overall responsibility for, among other things, establishing the compensation levels and direct and indirect benefits of our officers and directors; making recommendations to the Board with respect to the establishment and terms of incentive compensation plans and equity-based plans and administering such plans; reviewing and evaluating the Company's compensation program and such program's coordination and execution; establishing and reviewing policies with respect to management and director perquisites; engaging any outside consultant to assist in determining appropriate compensation levels for our officers and directors; and reviewing and discussing with management the Compensation Discussion and Analysis included in the Company's annual report on Form 10-K or proxy statement. In addition, our Compensation Committee administers our Stock Incentive Plan, including reviewing and granting stock options and other share-based awards, with respect to our directors, officers and employees.

The current members of our Compensation Committee are Messrs. McClaugherty, Hurley and Swanson. Mr. McClaugherty serves as Chairman of the Compensation Committee. The members of our Compensation Committee are independent, as independence for directors is defined by NYSE rules.

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Governance Committee

Our Governance Committee's responsibilities include identifying individuals qualified to become Board members consistent with criteria approved by the Board and recommending candidates for election to our Board; reviewing and recommending changes, when necessary, to the Board regarding the Corporate Governance Guidelines of the Company; overseeing the director nomination process and the evaluation of the Board and management; reviewing the independence of each Board member and making recommendations to the Board regarding director independence; reviewing and resolving issues pertaining to related-party transactions and conflicts of interests; and evaluating and, if necessary, recommending changes to the Board regarding Board processes and policies.

The Governance Committee has established procedures for the nomination process and leads the searches for, selects and recommends candidates for election to our Board, subject to legal rights, if any, of third parties to nominate or appoint directors. Consideration of new director candidates typically involves a series of committee discussions, review of information concerning candidates and interviews with selected candidates. Candidates for nomination to our Board typically have been suggested by other members of our Board or by our executive officers. From time to time, our Governance Committee may engage the services of a third-party search firm to identify director candidates. Our Governance Committee recommends candidates for election to our Board. Candidates proposed by common stockholders will be evaluated by our Governance Committee using the same criteria as for all other candidates.

The Board will consider recommendations of director nominees from common stockholders that are submitted in accordance with the procedures for nominations set forth under the section entitled “Other Matters-Stockholder Proposals for 2013 Annual Meeting” in the Company's proxy statement for its 2013 annual meeting of stockholders when the proxy statement is filed. In addition, such recommendations should be accompanied by the candidate's name, biographical data, qualifications and a written statement from the individual evidencing his or her consent to be named as a candidate and, if nominated and elected, to serve as a director. Other than as stated herein, we do not have a formal policy with respect to consideration of director candidates recommended by stockholders, as the Board believes that each candidate, regardless of the source of the recommendation, should be evaluated in light of all relevant facts and circumstances.

Nominees for director are selected on the basis of, among other things, independence, experience, knowledge, skills, expertise, integrity, ability to make independent analytical inquiries, understanding of the Company's business environment, ability to devote adequate time and effort to Board responsibilities and commitments to other public company boards. Other criteria for director candidates considered by the Governance Committee and by the full Board include age, diversity (“diversity” being broadly construed to mean a variety of opinions, perspectives, experiences and backgrounds, such as gender, race and ethnicity differences, as well as other differentiating characteristics, all in the context of the requirements of our Board at that point in time), whether the candidate has any conflicts of interest, whether the candidate has the requisite independence and skills for Board and committee service under applicable SEC and NYSE rules, how the candidate's skills and experience enhance the overall competency of the Board, and whether the candidate has any special background relevant to Magnum Hunter's business.

The current members of our Governance Committee are Messrs. Carrillo, Hurley and Swanson. Mr. Carrillo serves as Chairman of the Governance Committee. The members of our Governance Committee are independent, as independence for directors is defined by NYSE rules.

Committee Interlocks and Insider Participation

Two of our directors, Gary C. Evans and Ronald D. Ormand, also serve as executive officers of Magnum Hunter. Neither Mr. Evans nor Mr. Ormand serves on any of our standing committees and no other member of our Board is employed by Magnum Hunter or its subsidiaries.

Mr. Evans also serves on the board of directors of GreenHunter. In addition, Mr. Evans is the Chairman and a major stockholder of GreenHunter. Other than as described above, none of our executive officers serves on the board of directors of another entity whose executive officers serve on our Board. No officer or employee of Magnum Hunter, other than Mr. Evans, participated in the deliberations of our Board or our Compensation Committee concerning executive officer or director compensation.

Director and Officer Indemnification

Our bylaws permit the Company to indemnify the Company's directors and officers to the fullest extent permitted by law. We also maintain directors' and officers' liability insurance.  Additionally, we have entered into separate indemnification agreements with our directors and executive officers that provide broader indemnification than that required under the Delaware General Corporation Law. These agreements, among other things, require us to indemnify our directors and executive officers to the fullest extent permitted by applicable law for certain expenses, including attorneys' fees, judgments, penalties, fines and settlement amounts

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actually and reasonably incurred by a director or executive officer in any action or proceeding arising out of his service as one of our directors or executive officers, or any of our subsidiaries, or any other company or enterprise to which the person provides services at our request, including liability arising out of negligence or active or passive wrongdoing by the officer or director.  We believe that these agreements are necessary to attract and retain qualified directors and executives.

The limitation of liability and indemnification provisions in our restated certificate of incorporation and bylaws and the indemnification agreements may discourage stockholders from bringing a lawsuit against our directors and officers for breach of their fiduciary duty. They may also reduce the likelihood of derivative litigation against our directors and officers, even though an action, if successful, might benefit us and other stockholders. Further, a stockholder's investment may be adversely affected to the extent that we pay the costs of settlement and damage awards against directors and officers as required by these indemnification provisions.

Section 16(a) Beneficial Ownership Reporting Compliance

Section 16(a) of the Exchange Act requires our directors, executive officers and beneficial holders of more than 10% of our common stock to file reports with the SEC regarding their ownership and changes in ownership of our stock. Based solely upon a review of Forms 3 and 4 and amendments thereto furnished to us during the year ended December 31, 2012 and Forms 5 and amendments thereto furnished to us with respect to the year ended December 31, 2012, and any written representations provided to us, we believe that all of our directors, executive officers and beneficial holders of more than 10% of the outstanding shares of our common stock complied with Section 16(a) of the Exchange Act for the year ended December 31, 2012, except for Joe McClaugherty, a director of the Company, who made one late filing on Form 4, resulting in a failure to timely report one transaction, and Donald L. Kirkendall, an executive officer of the Company, who made one late filing on Form 4, resulting in a failure to timely report one transaction.

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Item 11. EXECUTIVE COMPENSATION

Director Compensation

Our Compensation Committee reviews, not less frequently than bi-annually, and recommends to our Board for approval, fees and other compensation and benefits for our non-employee directors. Also, our Compensation Committee frequently consults with Longnecker and Associates, or Longnecker, an independent compensation consultant, on the competitiveness of our executive compensation. Longnecker's most recent formal peer group review for the Compensation Committee on overall director compensation was performed in 2012. Longnecker assists our Compensation Committee in evaluating the appropriateness of our non-employee directors' compensation program, including the mix of meeting fees and annual chairperson retainers, to ensure that the program compensates our non-employee directors for the level of responsibility the Board has assumed in today's corporate governance environment and to remain competitive relative to companies in our peer group.

The Company's non-employee directors' compensation program remained fundamentally unchanged in 2012. Accordingly, for 2012, fees for attending meetings of the Board and its committees were set at $1,500 per Board meeting and $1,000 per committee meeting. The Company pays a $10,000 annual retainer to the chairman of each Board committee. Meeting fees and chairperson retainers are paid on a quarterly basis. Beginning in 2013, all of our non-employee directors also receive a $45,000 annual retainer, payable quarterly, in addition to the fees described above.

The non-employee directors that served on the GreenHunter special committee described under the GreenHunter Transactions identified below in Item 13 each received a one-time payment of $15,000 in recognition of the significant time commitment associated with participation on that special committee. The members of the special committee were Messrs. Swanson (Chair), Bynum and Carrillo.

Each non-employee director may elect to receive his compensation, including meeting fees, committee chairperson fees and annual retainer, in cash or in shares of our common stock, or a combination thereof. Each director's election will remain in effect until a new election is made, and new elections may be made on an annual basis. As of the date of the filing of this annual report, all of our non-employee directors have elected to receive compensation in shares of common stock.

The number of shares paid in lieu of cash compensation is based on the volume weighted average price of our common stock for the calendar quarter in which the meetings were held or the chairperson fee or annual retainer was accrued. Non-employee directors are also eligible to receive annual grants of shares of Magnum Hunter common stock and options to purchase shares of Magnum Hunter common stock under our Stock Incentive Plan.

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The following table presents compensation earned by each non-employee member of our Board for 2012. Compensation information for Messrs. Evans and Ormand is contained in the Summary Compensation Table below. Messrs. Evans and Ormand did not receive any compensation in their capacities as directors of the Company.

2012 Director Compensation Table

Name	Fees Earned or Paid in Cash	Option Awards (1) (2)	Stock Awards (1)	All Other Compensation (3)	Total
J. Raleigh Bailes, Sr.	—	$178,817	$43,766	—	$222,583
Brad Bynum	—	$178,817	$49,854	—	$225,671
Victor G. Carrillo	—	$178,817	$40,079	—	$218,896
Stephen C. Hurley	—	$178,817	$45,549	—	$224,366
Joe L. McClaugherty	—	$178,817	$55,367	—	$234,184
Steven A. Pfeifer	—	$178,817	$26,841	—	$205,658
Jeff Swanson	—	$178,817	$37,998	—	$216,815

(1) Represents the aggregate grant date fair value, in accordance with Accounting Standards Codification 718, “Stock Compensation”, referred to in this annual report as ASC 718 (except no assumptions for forfeitures were included), with respect to (a) shares of common stock (under the Stock Awards column), and (b) stock options (under the Option Awards column). See "Note 12 - Share-Based Compensation", for information regarding the assumptions made in determining these values.

As of December 31, 2012, Messrs. Bailes, Bynum, Carrillo, Hurley, McClaugherty, Pfeifer and Swanson did not hold any shares of unvested restricted stock. As of December 31, 2012, the aggregate number of outstanding option awards held by non-employee directors were: 115,000 for Mr. Bailes, 115,000 for Mr. Bynum, 115,000 for Mr. Carrillo, 76,000 for Mr. Hurley, 80,000 for Mr. McClaugherty, 115,000 for Mr. Pfeifer and 115,000 for Mr. Swanson.

(2) On April 13, 2012, Messrs. Bailes, Bynum, Carrillo, Hurley, McClaugherty, Pfeifer and Swanson were each granted an option to purchase up to 45,000 shares of our common stock at an exercise price of $6.08 per share with a ten-year expiration date.

(3) We reimburse the reasonable travel and accommodation expenses of directors to attend meetings and other corporate functions. In 2012, the incremental cost to the Company to provide these perquisites was less than $10,000 per director.

Executive Compensation Discussion and Analysis

This compensation discussion and analysis provides information regarding our executive compensation program in 2012 for the following executive officers of the Company, collectively referred to as our Named Executive Officers, or NEOs:

• Gary C. Evans, Chairman and Chief Executive Officer

• Ronald D. Ormand, Executive Vice President, Chief Financial Officer and Secretary

• James W. Denny III, Executive Vice President and President, Appalachian Division

• H.C. “Kip” Ferguson, Executive Vice President and President, Eagle Ford Division

• R. Glenn Dawson, Executive Vice President and President, Williston Basin Division

2011 Stockholder Advisory Vote on Executive Compensation

At our 2011 annual meeting of stockholders, we held our first advisory vote on executive compensation. Over 85% of the votes cast were in favor of the compensation of the NEOs. The Compensation Committee considered this favorable outcome and believed it conveyed our stockholders' support of the Compensation Committee's decisions and the existing executive compensation programs. The Compensation Committee continues to look for ways to attract and retain top executive talent whose interests are aligned with those of the Company's stockholders. At the 2014 annual meeting, we will again hold an advisory vote to approve executive compensation, as supported by the common stockholders in accordance with the Company's recommendation in 2011. The Compensation Committee will continue to consider the results from the 2011 vote and future advisory votes on executive compensation.

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Our Compensation Philosophy

The objective of the Company's executive compensation program is to enable us to recruit and retain highly qualified managerial talent by providing competitive levels of compensation in an increasingly competitive market for executive talent. We also seek to motivate our executives to achieve individual and business performance objectives by varying their compensation in accordance with the success of our business.

We believe compensation programs can drive the behavior of employees covered by the programs, and accordingly we seek to design our executive compensation program to align compensation with current and desired corporate performance and stockholder interests. Actual compensation in a given year will vary based on the Company's performance and on subjective appraisals of individual performance. In other words, while compensation targets will to a large extent reflect the market, actual compensation generally will reflect the Company's attainment of (or failure to attain) financial and operational performance objectives.

 We maintain competitive benefit programs for our employees, including our NEOs, with the objective of retaining their services. Our benefits reflect competitive practices at the time the benefit programs were implemented and, in some cases, reflect our desire to maintain similar benefits treatment for all employees in similar positions. To the extent possible, we structure these programs to deliver benefits in a manner that is tax efficient to both the recipient and the Company.

We seek to provide compensation that is competitive with the companies we believe are our peers and other likely competitors for executive talent. Competitive compensation is normally sufficient to attract executive talent to the Company. Competitive compensation also makes it less likely that executive talent will be lured away by higher compensation to perform a similar role with a similarly-sized competitor. We also believe that a significant portion of compensation for executives should be “at risk,” meaning that the executives will receive a significant portion of their total compensation only to the extent the Company and the executive accomplish goals established by our Compensation Committee.

We frequently consult with Longnecker on the competitiveness of our executive compensation. In 2012, Longnecker performed a formal peer group review on the compensation of our senior executives. That review looked at the following companies in our peer group:

Carrizo Oil & Gas, Inc.	Goodrich Petroleum Corp.	Penn Virginia Corp.
Comstock Resources, Inc.	Gulfport Energy Corp.	Resolute Energy Corp.
Endeavor International Corp.	Kodiak Oil & Gas Corp.	Rex Energy Corp.
GeoResources, Inc.	Northern Oil & Gas, Inc.	Stone Energy Corp.
GMX Resources Inc.	Oasis Petroleum Inc.	Swift Energy Company

Base Salary

Base salary is the foundation of total compensation. Base salary recognizes the job being performed and the value of that job in the competitive market. Base salary must be sufficient to attract and retain the talent necessary for our continued success and provides an element of compensation that is not at risk in order to avoid fluctuations in compensation that could distract the executives from the performance of their responsibilities.

 Adjustments to base salary primarily reflect either changes or responses to changes in market data or increased experience and individual contribution of the employee. Working with Longnecker, we noted in 2010 that our base salaries were, in many cases, significantly below market. We have instituted salary increases each year to ensure that our overall compensation remains competitive, but continue to place more emphasis on incentive compensation because of its link to the creation of stockholder value.

Short-Term Incentives

Our short-term incentive program, which we refer to in this annual report as the Executive Bonus Program, provides an annual cash and/or stock award that is designed to link each employee's annual compensation to the achievement of annual performance objectives for the Company, as well as to recognize the employee's performance during the year. The target for each employee is expressed as a percentage of base salary earned during the year and classified as a bonus. Generally, a portion of this award is based upon short-term goals and the remaining portion of the bonus is based upon the discretion of the Compensation Committee. The Compensation Committee retains the ability to exercise discretion in determining all payments under the Executive Bonus Program.

Each year, the Compensation Committee establishes and approves the specific performance objectives after reviewing the performance achieved by our executives the previous year. Performance objectives are based on Company financial and operational

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factors determined to be critical to achieving our desired business plans. Performance objectives are designed to reflect goals and objectives to be accomplished over a specific period; therefore, incentive opportunities under the plan are not impacted by compensation amounts earned in prior years.

Performance objectives for the NEOs are generally based on performance objectives for the Company as a whole. Examples of performance objectives include (1) achieving specified levels of volume weighted average stock price, (2) achieving specified levels of production, (3) achieving specified levels of reserves and (4) operational performance objectives.

The 2012 Executive Bonus Program applied to all NEOs. It provided the NEOs with a goal-weighted bonus of up to 50% of base salary and a merit bonus of up to 50% of base salary. The goal-weighted portion of the 2012 Executive Bonus Program consisted of high (125%), target (100%) and low (75%) performance goals. The following chart identifies the weight given to each metric. All criteria require employment with the Company on the date the bonus is paid. The Compensation Committee has not yet made a determination regarding the achievement of these goals. Accordingly, bonuses under the 2012 Executive Bonus Program have not yet been paid. Unless otherwise indicated, the Compensation Committee will use March 31, 2013 as the measurement date for the achievement of the performance goals.

		75%	100%	125%
1	10%	Not applicable.	Employed by the Company as of the close of business on February 28, 2013.	Not applicable.
2	25%	The Company exits 2012 at or above 16,000 BOE of daily production.	The Company exits 2012 at or above 17,000 BOE of daily production.	The Company exits 2012 at or above 20,000 BOE of daily production.
3	20%	The common stock of the Company has traded at a daily VWAP at or above $9.00 per share for 60 consecutive trading days.	The common stock of the Company has traded at a daily VWAP at or above $10.00 per share for 60 consecutive trading days.	The common stock of the Company has traded at a daily VWAP at or above $12.50 per share for 60 consecutive trading days.
4	25%	The Company has increased total proved reserves to 55 million or more BOE.	The Company has increased total proved reserves to 60 million or more BOE.	The Company has increased total proved reserves to 65 million or more BOE.
5	10%	The Company has reduced Lifting Costs to a fourth quarter average less than $15.00 per BOE.	The Company has reduced Lifting Costs to a fourth quarter average less than $12.00 per BOE.	The Company has reduced Lifting Costs to a fourth quarter average less than $10.00 per BOE.
6	10%	The Company has reduced Recurring Cash G&A to a fourth quarter average less than $9.00 per BOE.	The Company has reduced Recurring Cash G&A to a fourth quarter average less than $8.00 per BOE.	The Company has reduced Recurring Cash G&A to a fourth quarter average less than $7.00 per BOE.

Long-Term Incentives

Our Stock Incentive Plan, in which each of our executive officers, including each of our NEOs, and certain other employees participate, is designed to reward participants for sustained improvements in the Company's financial performance and increases in the value of our common stock over an extended period. Long-term incentives are a key component of the Company's overall compensation structure.

The Compensation Committee authorizes grants throughout the year depending upon the Company's activities during that time period. Grants can be made from a variety of award types authorized under our Stock Incentive Plan. Prior to 2012, our stock, stock option and stock appreciation right awards contained vesting provisions based on continued service, generally over three or four-year periods, satisfaction of performance-based vesting hurdles, or a combination of these. The performance periods in those awards would vary given the rate at which the Company was growing. When evaluating the satisfaction of performance-based vesting hurdles, the Compensation Committee reserved the ability to toll the deadline for achieving a given objective because of delays outside of management's control.

Beginning in 2012, the vesting criteria for most stock option awards is service based. The Compensation Committee has made this change to ensure that our equity compensation awards have the effect of retaining our employees. The Company's performance, the competitive environment and the skill of our employees made retention an important factor in the Compensation Committee's decision to make this change.

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Change in Control Payments

In 2011, the Company approved a change in control program that provides the Company's executives with certain specified severance payments following a change in control of the Company, provided that the severance occurs either without cause or by the executive for good reason within 24 months following the change in control. The definition of what constitutes a change in control tracks the language of the Company's Stock Incentive Plan.

Immediately prior to a change in control, all outstanding equity awards will vest and any performance targets will be deemed to have been met at 100%. This occurs without regard to whether a termination of employment occurs.

For the 24 months following a change in control, an executive who is terminated without cause or who terminates employment for good reason will be entitled to the severance payments. Generally, senior executives, including the NEOs, would receive a severance payment equal to two times base salary plus two times targeted bonus and 24 months of continued medical coverage. The “targeted bonus” is defined as the highest of (1) the maximum bonus opportunity established by the Compensation Committee for the executive or, if the Compensation Committee has not established the executive's bonus opportunity for the year in which the executive's termination occurs, 100% of the executive's base salary, (2) the maximum bonus opportunity established by the Compensation Committee for the executive for the immediately preceding year or (3) the maximum bonus opportunity established by the Compensation Committee for the executive immediately prior to the change in control.

As a condition to receiving severance payments, an executive must sign a release and waiver of claims that includes non-disparagement and confidentiality provisions. In most circumstances, the executive will, by statute, have 21 days to consider the release and seven days following execution of the release where the executive can revoke it. The executive will receive health coverage during this consideration period even if the executive does not ultimately execute the release. In order to avoid duplicative payment provided for in their employment agreements, which have since expired, Messrs. Evans, Ormand and Ferguson were required to agree to waive payments under their employment agreements that were based on a multiplier of the executive's compensation and health coverage reimbursement.

Severance benefits paid to an executive will be reduced to the extent necessary to avoid the imposition of any excise tax associated with parachute payments. Before the expiration of their employment agreements, Messrs. Evans, Ormand and Ferguson would have been entitled to a tax-gross up for any excise taxes on parachute payments.

In developing the change in control program, the Compensation Committee engaged the services of Longnecker as compensation consultants. As part of their analysis, Longnecker used the following peer group of companies for benchmarking purposes:

Oasis Petroleum	Comstock Resources, Inc.	Penn Virginia Corporation
Swift Energy Company	Kodiak Oil & Gas Corporation	GeoResources, Inc.
Stone Energy Corporation	Northern Oil & Gas, Inc.	Rex Energy Corporation
Carrizo Oil & Gas, Inc.	Resolute Energy Corporation	Endeavour International Corp.
Gulfport Energy Corporation	Goodrich Petroleum Corp.	GMX Resources, Inc.

Risk Assessment

As part of its oversight of the Company's executive and non-executive compensation programs, the Compensation Committee considers the impact of the Company's compensation programs, and the incentives created by the compensation awards that it administers, on the Company's risk profile. In addition, the Company reviews all of its compensation policies and procedures, including the incentives that they create and factors that may reduce the likelihood of excessive risk taking, to determine whether they present a significant risk to the Company. Based on this review, the Company has concluded that its compensation policies and procedures are not reasonably likely to have a material adverse effect on the Company. As a result of this analysis, the Compensation Committee identified the following risk mitigating factors:

• use of long-term incentive compensation;

• vesting periods for equity compensation awards that encourage executives and other key employees to focus on sustained stock price appreciation;

• the Compensation Committee's discretionary authority to adjust annual incentive awards, which helps mitigate any business risks associated with such awards;

• the Company's internal controls over financial reporting and other financial, operational and compliance policies and practices currently in place;

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• base salaries consistent with executives' responsibilities so that they are not motivated to take excessive risks to achieve a reasonable level of financial security; and

• design of long-term compensation to reward executives and other key employees for driving sustainable and/or profitable growth for stockholders.

As a result of the above assessment, the Compensation Committee determined that the Company's policies and procedures largely achieve a proper balance between competitive compensation and prudent business risk.

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Executive Compensation Tables

The following tables include compensation information for our NEOs for the last three years. For a discussion of 2012 NEO compensation, please read the Executive Compensation Discussion and Analysis above.

The 2012 Summary Compensation Table below sets forth compensation information for our NEOs relating to 2012, 2011 and 2010. Pursuant to SEC rules, the 2012 Summary Compensation Table is required to include for a particular fiscal year only those restricted stock awards, stock appreciation rights and options to purchase common stock granted during that year, rather than awards granted after year-end, even if awarded for services in that year. SEC rules require disclosure of variable cash compensation to be included in the year earned, even if payment is made after year-end. Generally, we pay any cash variable compensation for a particular year after the Compensation Committee has had an opportunity to review the Company's and each individual's performance for that year. As a result, cash variable compensation reported in the “Bonus” column was paid in the year following the year in which it is reported in the table.

2012 Summary Compensation Table

Name and Principal Position	Year	Salary (1)		Bonus (2)		Stock Awards (3)		Option Awards (3)		All Other Compensation (4)		Total
Gary C. Evans (5)	2012	$	465,000	—		—		$	2,943,232	$	90,507	$	3,498,739
Chairman and CEO	2011	$	415,000	$	650,000	—		$	3,181,100	$	73,129	$	4,319,229
	2010	$	300,000	$	550,000	$	1,188,001	$	9,158,722	$	28,999	$	11,225,722
Ronald D. Ormand (6)	2012	$	275,000	—		—		$	981,077	$	28,057	$	1,284,134
Executive V.P., CFO, and Secretary	2011	$	250,000	$	240,625	—		$	1,223,500	$	36,966	$	1,751,091
	2010	$	225,000	$	200,000	—		$	425,946	$	16,869	$	867,815
James W. Denny, III	2012	$	275,000	—		—		$	981,077	$	61,454	$	1,317,531
Executive V.P. and President, Appalachian Division	2011	$	250,000	$	240,625	—		$	1,223,500	$	68,981	$	1,783,106
	2010	$	225,000	$	200,000	—		$	170,379	$	18,496	$	613,875
H.C. "Kip" Ferguson (7)	2012	$	275,000	—		—		$	981,077	$	27,199	$	1,283,276
Executive V.P. and President, Eagle Ford Division	2011	$	250,000	$	240,625	—		$	1,223,500	$	36,324	$	1,750,449
	2010	$	225,000	$	200,000	—		$	511,136	$	15,304	$	951,440
R. Glenn Dawson (8)	2012	$	274,342	—		—		$	981,077	$	13,668	$	1,269,087
Executive V.P. and President, Williston Basin Division

(1) The amounts reflected in this column show each NEO's annualized salary for the majority of the year. For 2012, the amounts shown were effective April 16, 2012. For 2011, the amounts shown were effective March 1, 2011. For 2010, the amounts shown were effective April 1, 2010.

(2)   Our Compensation Committee has not yet determined bonuses under the 2012 Executive Bonus Program. For a discussion of the 2012 Executive Bonus Program, refer to Short-Term Incentives above.

(3) Represents the aggregate grant date fair value in accordance with Accounting Standards Codification 718, “Stock Compensation” (except no assumptions for forfeitures were included). For a discussion of the assumptions made in the valuation of stock and option awards, please refer to "Note 11 - Share-Based Compensation".

(4) Amounts in this column are detailed in the following All Other Compensation Table.

(5) We entered into an employment agreement with Mr. Evans in May 2009. Pursuant to his employment agreement, Mr. Evans agreed to serve as the Chairman and Chief Executive Officer of the Company for a three-year term that expired on May 22, 2012. Mr. Evans' duties and authorities under the agreement included those typically associated with the Chief Executive Officer.

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We agreed to pay Mr. Evans a minimum base salary of $254,000 during the first year of the employment agreement and minimums of $274,000 and $294,000 during the second and third years of the agreement, respectively. Mr. Evans' employment agreement provided that he was eligible for an annual bonus based on performance criteria set by the Compensation Committee and to otherwise participate in all benefits, plans and programs, including improvements or modifications of the same, that were available to other executive employees of the Company. Mr. Evans' employment agreement provided that he would serve as Chairman during the term of his agreement and that he could nominate to our Board one additional independent member. Mr. Evans' employment agreement contained standard provisions concerning noncompetition, nondisclosure and indemnification. Mr. Evans' employment agreement expired in May 2012.

(6) We entered into an employment agreement with Mr. Ormand in May 2009. Pursuant to his employment agreement, Mr. Ormand agreed to serve as Executive Vice President and Chief Financial Officer for a three-year term that expired on May 22, 2012. Mr. Ormand's duties and authorities under the agreement included those typically associated with the Chief Financial Officer. We agreed to pay Mr. Ormand a minimum base salary of $180,000 during the first year of the agreement and minimums of $200,000 and $220,000 during the second and third years of the agreement, respectively. Mr. Ormand's employment agreement provided that he was eligible for an annual bonus based on performance criteria set by the Compensation Committee and to otherwise participate in all benefits, plans and programs, including improvements or modifications of the same, that were available to other executive employees of Company. Mr. Ormand's employment agreement contained standard provisions concerning noncompetition, nondisclosure and indemnification. Mr. Ormand's employment agreement expired in May 2012.

(7) We entered into an employment agreement with Mr. Ferguson effective October 2009. Pursuant to his employment agreement, Mr. Ferguson agreed to serve for a three-year term that expired on October 1, 2012. We agreed to pay Mr. Ferguson a minimum base salary of $180,000, which was increased to $225,000 for 2010, and Mr. Ferguson's employment agreement provided that he was eligible for an annual bonus based on performance criteria set by the Compensation Committee of our Board and to otherwise participate in all benefits, plans and programs, including improvements or modifications of the same, that were available to other executive employees of Company. Mr. Ferguson's employment agreement contained standard provisions concerning noncompetition, nondisclosure and indemnification. Mr. Ferguson's employment agreement expired in October 2012.

(8) Mr. Dawson's 2012 annualized salary was $275,000 CAD. The amount shown is converted to U.S. dollars using the nominal noon exchange rate on April 16, 2012, the effective date of his 2012 annual salary, as published by the Bank of Canada.

All Other Compensation Table

The charts and narrative below describe the benefits and perquisites for 2012 contained in the “All Other Compensation” column of the 2012 Summary Compensation Table.

	401(k) Matching Contribution (1)		Health, Dental, Vision, and Executive Illness Premiums		Life Insurance Premiums		Disability Insurance Premiums		Other
Mr. Evans	$	8,925	$	10,944	$	579	$	7,711	$	62,348	(a), (b)
Mr. Ormand	$	8,925	$	11,020	$	579	$	7,533	$	—
Mr. Denny	$	8,925	$	8,565	$	752	$	7,212	$	36,000	(b)
Mr. Ferguson	$	8,925	$	11,020	$	579	$	6,675	$	—
Mr. Dawson (2)	$	—	$	4,791	$	1,595	$	7,282	$	—

(1) The Company's "safe harbor" matching contributions to its 401(k) plan have not yet been made. When made, the Company expects that the contribution will be made in shares of the Company's common stock. Once dollar amounts for the Company's contributions are determined, the Company uses the closing price of the common stock the day prior to making its contribution to convert the dollar amounts to shares on a unitized basis. The amount of this contribution will change if the Company chooses to make a discretionary matching contribution for 2012.

(2) Amounts paid for the benefit of Mr. Dawson have been converted from Canadian dollars to U.S. dollars using the nominal noon exchange rate for December 31, 2012, as published by the Bank of Canada.

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(a) We provide Mr. Evans with memberships to certain private country and city clubs to facilitate business meetings and initiate and strengthen business relationships. Mr. Evans uses one country club for business and non-business purposes. The cost of membership in that club is included in this total.

(b) Because of extensive business travel requirements, we make corporate apartments available to Messrs. Evans and Denny and other employees. In 2012, Mr. Evans did not maintain a residence near the Company's Houston offices and the Company incurred an incremental cost of $33,016 associated with Mr. Evans' use of a Houston apartment with other executives. Mr. Denny used corporate apartments near the Company's operations in Marietta, Ohio, and Lexington, Kentucky, with incremental costs to the Company of $13,200 and $22,800 respectively. We also provide vehicles at various locations. The amount shown for Mr. Evans includes the incremental cost of Mr. Evans' use of Company vehicles. We did not attribute any incremental cost to Mr. Denny's use of Company vehicles because the vehicles driven by Mr. Denny in 2012 had fully depreciated prior to 2012 and Mr. Denny's limited personal use of those vehicles.

2012 Grants of Plan-Based Awards

The following table sets forth plan-based awards made in 2012. Each of our NEOs was granted options to purchase shares of the Company's common stock. All grants featured 25% immediate vesting and 25% additional vesting on the first three anniversaries of the grant date.

	Grant Date	Number of Securities Underlying Options	Exercise Price of Option Awards	Grant Date Fair Value of Option Awards
Mr. Evans	4/13/2012	750,000	$6.08	$2,943,232
Mr. Ormand	4/13/2012	250,000	$6.08	$981,077
Mr. Denny	4/13/2012	250,000	$6.08	$981,077
Mr. Ferguson	4/13/2012	250,000	$6.08	$981,077
Mr. Dawson	4/13/2012	250,000	$6.08	$981,077

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2012 Outstanding Equity Awards at Year-End

The following table identifies the outstanding equity-based awards held by the NEOs as of December 31, 2012. For all unvested awards, continued employment through the vesting date is required.

	Option and Stock Appreciation Right Awards						Stock Awards
	Award Year	Number of Securities Underlying Unexercised Options/SARs (Exercisable)	Number of Securities Underlying Unexercised Options/SARs (Unexercisable)	Equity Incentive Plan Awards: Number of Securities Underlying Unexercised Unearned SARs	Option Exercise Price/ SAR Base Price	Option Expiration Date	Number of Shares of Stock That Have Not Vested	Market Value of Shares of Stock That Have Not Vested
Mr. Evans	2012	187,500	562,500 (a)	—	$6.08	4/13/2022	—	—
	2011	601,250	—	—	$7.95	5/2/2021	—	—
	2010	333,500	—	2,749,832 (b)	$6.09	11/29/2015	65,025 (c)	$259,501
Mr. Ormand	2012	62,500	187,500 (a)	—	$6.08	4/13/2022	—	—
	2011	231,250	—	—	$7.95	5/2/2021	—	—
	2010	—	—	—	$2.25	2/11/2020	—	—
Mr. Denny	2012	62,500	187,500 (a)	—	$6.08	4/13/2022	—	—
	2011	231,250	—	—	$7.95	5/2/2021	—	—
	2010	—	—	—	$2.25	2/11/2020	—	—
	2009	12,500	—	—	$1.17	9/30/2014	—	—
	2009	250,000	—	—	$1.69	10/23/2014	—	—
	2008	—	—	—	$1.69	3/1/2013	—	—
Mr. Ferguson	2012	62,500	187,500 (a)	—	$6.08	4/13/2022	—	—
	2011	231,250	—	—	$7.95	5/2/2021	—	—
	2010	270,000	—	—	$2.25	2/11/2020	—	—
	2009	100,000		—	$1.17	9/30/2014	—	—
Mr. Dawson	2012	62,500	187,500 (a)	—	$6.08	4/13/2022	—	—
	2011	675,000	—	—	$7.58	5/3/2021	—	—

(a) All 2012 grants featured 25% immediate vesting and 25% additional vesting on the first three anniversaries of the grant date, which was April 13, 2012.

(b) We awarded Mr. Evans stock appreciation rights on 3,083,332 shares of the Company's common stock, with vesting subject to specific stock price performance measures and certain specific reserve growth performance achievements over the five-year period following the grant date. If the performance measures are achieved, the stock appreciation rights become exercisable in three annual tranches based on the anniversary of the grant date. As of December 31, 2012, stock appreciation rights on 500,000 shares were vested and, of those, the stock appreciation rights on 333,300 shares were exercisable.     

(c) Forfeiture restrictions will lapse on these shares on November 29, 2013.

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2012 Option Exercises and Stock Vested

The following table summarizes the options that our NEOs exercised in 2012. For stock awards that vested in 2012, the value that the NEO realized on the date the restrictions on the award lapsed is provided.

	Option Awards		Stock Awards
	Number of Shares Acquired on Exercise	Value Realized on Exercise	Number of Shares With Lapse of Restrictions	Value Realized on Lapse of Restrictions
Mr. Evans	—	—	65,038	$260,152
Mr. Ormand	125,000	$376,000	—	—
Mr. Denny	227,500	$988,275	—	—
Mr. Ferguson	—	—	—	—
Mr. Dawson	—	—	—	—

Potential Payments Upon Termination or Change in Control

The following table identifies the payments that may be made to our NEOs following a change in control of the Company. For a detailed discussion of these payments, please see the Compensation Discussion and Analysis above. These calculations assume a change in control of the Company on December 31, 2012, and a closing stock price on that date of $3.99. Although the employment agreements for Messrs. Evans, Ormand and Ferguson, which have expired, provided for certain tax reimbursements, those would not have applied had a change in control of the Company occurred on December 31, 2012.

	Cash (1)	Equity (2)	Perquisites / Benefits (3)	Total
Mr. Evans	$1,860,000 (a)	$259,501	$23,280	$2,142,781
Mr. Ormand	$1,100,000 (b)	—	$25,280	$1,125,280
Mr. Denny	$1,100,000 (b)	—	$17,736	$1,117,736
Mr. Ferguson	$1,100,000 (b)	—	$23,280	$1,123,280
Mr. Dawson	$1,098,568 (c)	—	$8,552	$1,107,120

(1) Cash compensation is subject to each NEO's severance from employment without cause or by the NEO with good reason within 24 months following a change in control.

(2) The 2012 Outstanding Equity Awards at Year-Endtable details the unvested awards that would have been subject to accelerated vesting on December 31, 2012. All outstanding equity awards are immediately vested upon a change in control.

(3) The benefits identified in the third column consist of 24 months of continued Company contributions towards the cost of coverage for medical, dental and vision plans. The amounts were calculated by taking each NEO's actual coverage elections for 2013 and assuming that the cost of coverage would not change in 2014. Accordingly, these amounts are only estimates.

(a) This consists of 2x base salary of $465,000 plus 2x targeted bonus with the bonus set at 100% of base salary.

(b) This consists of 2x base salary of $275,000 plus 2x targeted bonus with the bonus set at 100% of base salary.

(c) This consists of 2x base salary of $274,342 plus 2x targeted bonus with the bonus set at 100% of base salary.

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Report of Our Compensation Committee

Our Compensation Committee reviewed the Executive Compensation Discussion and Analysis, or CD&A, as prepared by management of the Company, and discussed the CD&A with the Company's management. Based on the Committee's review and discussions, the Committee recommended to the Board that the CD&A be included in this annual report.

The Compensation Committee

Joe L. McClaugherty, Chair

Stephen C. Hurley

Jeff Swanson

Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

The following table sets forth information regarding beneficial ownership of Magnum Hunter's common stock and preferred stock as of May 1, 2013 held by (i) each of our current directors and named executive officers; (ii) all current directors and executive officers as a group; and (iii) any person (or group) who is known to us to be the beneficial owner of more than 5% of any class of our stock. Beneficial ownership is determined in accordance with Rule 13d-3 under the Exchange Act and, except as otherwise indicated, the respective holders have sole voting and investment power over such shares. To our knowledge, there are no single holders of 5% or more of any series of our preferred stock.

Unless otherwise specified, the address of each of the persons set forth below is in care of Magnum Hunter Resources Corporation, 777 Post Oak Boulevard, Suite 650, Houston, Texas 77056.

Title of Class	Name of Beneficial Owner	Amount and Nature of Beneficial Ownership (1)	Percent of Class (%)
Common Stock	Gary C. Evans (a)	7,238,797	4%
Common Stock	Ronald D. Ormand (b)	2,185,606	1%
Common Stock	H.C. "Kip" Ferguson, III (c)	926,396	*
Common Stock	R. Glenn Dawson (d)	1,947,594	1%
Common Stock	James W. Denny, III (e)	670,786	*
Common Stock	J. Raleigh Bailes, Sr. (f)(l)	397,548	*
Common Stock	Brad Bynum (f)(m)	597,348	*
Common Stock	Victor G. Carrillo (h)(n)	191,123	*
Common Stock	Stephen C. Hurley (g)(o)	173,647	*
Common Stock	Joe L. McClaugherty (i) (j)	1,045,553	*
Common Stock	Steven A. Pfeifer (h)(p)	587,734	*
Common Stock	Jeff Swanson (h) (k)	266,503	*
Common Stock	BlackRock, Inc. (q)	14,087,134	8%
Common Stock	The Vanguard Group (r)	8,915,346	5%
Common Stock	Directors and executive officers as a group (16 persons) (s)	17,545,064	10%
Series C Preferred Stock	Directors and executive officers as a group	—	—
Series D Preferred Stock	James W. Denny, III	4,680	*
Series D Preferred Stock	Directors and executive officers as a group (1 person named above)	4,680	*
Series E Preferred Stock (represented by depositary shares)	Directors and executive officers as a group	—	—

*Less than 1%.

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(1) Each beneficial owner has sole voting and investment power with respect to all shares, unless otherwise indicated below.

(a) Includes 195,074 shares of restricted common stock, 130,036 of which has vested; 126,500 shares of common stock held in an account under the name of Mr. Evans' children and Mr. Evans' Special Inheritance account; an option to purchase 976,250 shares of common stock which has vested; an option to purchase 583,275 shares of common stock pursuant to stock appreciation rights which has vested; 561,492 shares of common stock underlying presently exercisable warrants; and an indirect interest in 4,186 shares of common stock held by the Company’s 401(k) plan. Mr. Evans has pledged 4,987,094 shares of common stock as security.

(b) Includes an option to purchase 418,750 shares of common stock which has vested; 191,010 shares of common stock underlying presently exercisable warrants; 1,571,660 shares held in a personal account and in a private family investment company controlled by Mr. Ormand; and an indirect interest in 4,186 shares of common stock held by the Company’s 401(k) plan. Mr. Ormand has pledged 1,571,660 shares of common stock as security.

(c) Includes an option to purchase 788,750 shares of common stock which has vested; 11,870 shares underlying presently exercisable warrants; and an indirect interest in 4,186 shares of common stock held by the Company’s 401(k) plan.

(d) Includes an option to purchase 881,250 shares of common stock which has vested and 96,940 shares of common stock underlying presently exercisable warrants. Mr. Dawson has pledged 377,444 shares of common stock as security.

(e) Includes an option to purchase 681,250 shares of common stock which has vested, 14,350 shares of common stock underlying presently exercisable warrants and an indirect interest in 4,186 shares of common stock held by the Company’s 401(k) plan.

(f) The amounts for each of Messrs. Bailes and Bynum include an option to purchase 275,000 shares of common stock which have vested. Mr. Bynum has pledged 175,314 shares of common stock as security.

(g) Includes an option to purchase 136,000 shares of common stock which has vested.

(h) The amounts for each of Messrs. Carrillo, Pfeifer and Swanson include an option to purchase 175,000 shares of common stock, which options have vested. Mr. Swanson has pledged 124,551 shares of common stock as security, and Mr. Pfeifer has pledged 338,572 shares of common stock as security.

(i) Includes an option to purchase 140,000 shares of common stock which has vested.

(j) Includes 75,605 shares of common stock underlying presently exercisable warrants.

(k) Includes 4,522 shares of common stock underlying presently exercisable warrants.

(l) Includes 13,904 shares of common stock underlying presently exercisable warrants.

(m) Includes 27,774 shares of common stock underlying presently exercisable warrants.

(n) Includes 175 shares of common stock underlying presently exercisable warrants.

(o) Includes 1,500 shares of common stock underlying presently exercisable warrants.

(p) Includes 36,814 shares of common stock underlying presently exercisable warrants.

(q) BlackRock, Inc.'s principal business office address is 40 East 52nd Street, New York, New York 10022. Information relating to this reporting stockholder is based on the stockholder’s Schedule 13G filed with the SEC on February 1, 2013.

(r) The Vanguard Group's principal business office address is 100 Vanguard Blvd. Malver, PA 19355. Information relating to this reporting stockholder is based on the stockholder’s Schedule 13G filed with the SEC on February 13, 2013.

(s) Includes 7,574,635 shares pledged by our officers and directors.

Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Under SEC rules, public companies, such as Magnum Hunter, must disclose certain “Related Person Transactions.” These are transactions in which the Company is a participant; the amount involved exceeds $120,000; and a director, executive officer or holder of more than 5% of our common stock has a direct or indirect material interest.

Review, Approval or Ratification of Transactions with Related Persons

Our Governance Committee charter requires, among other things, that (i) our Governance Committee will be comprised exclusively of members of our Board who satisfy the independence requirements of the NYSE and (ii) our Governance Committee is responsible for approving all related party transactions, as defined by the rules of the NYSE, to which we are a party. We currently do not have a written, stand-alone policy for evaluating related party transactions, but review related party transactions on a case-by-case basis. The Governance Committee's review procedures include evaluating the following:

• The nature of the relationships among the parties;

• The materiality of the transaction to Magnum Hunter;

• The related person's interest in the transaction; and

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• The benefit of the transaction to the related person and to our Company.

Additionally, in cases of transactions in which a director or executive officer may have an interest, the Audit Committee also evaluates the effect of the transaction on such individual's willingness or ability to properly perform his or her duties at Magnum Hunter.

Certain Relationships and Related Transactions

Airplane Rental

During 2012, we rented an airplane for business use at various times from Pilatus Hunter, LLC, an entity wholly-owned by Mr. Evans. Airplane rental expenses totaled $174,000 for the year ended December 31, 2012.

GreenHunter Transactions

As discussed in the “Committee Interlocks and Insider Participation” section, Gary C. Evans, our Chairman and Chief Executive Officer, is the Chairman and a major stockholder of GreenHunter; and Ronald D. Ormand, our Chief Financial Officer and a member of our Board, was a director of GreenHunter from June 2009 to December 2012. David S. Krueger, who previously served as our Chief Accounting Officer from October 2009 to October 2012, is the Chief Financial Officer of GreenHunter.

In October 2011, the Company purchased an office building from GreenHunter for $1.7 million. In conjunction with the purchase, the Company obtained a term loan from a financial institution in the amount of $1.4 million due on November 30, 2017, a portion of which loan is guaranteed by Mr. Evans. The building houses the accounting functions of Magnum Hunter.

During the year ended December 31, 2012, Eagle Ford Hunter, Inc., Triad Hunter, LLC and Hunter Disposal, LLC, wholly-owned subsidiaries of the Company, rented storage tanks for disposal water, frac tanks and equipment from GreenHunter. Rental costs totaled $1.0 million for the year ended December 31, 2012. The Company believes that such services were provided to it at competitive market rates and were comparable to or more attractive than rates that could have been obtained from unaffiliated third-party suppliers of such services. Additionally, these companies regularly obtained, and we continue to obtain, services from GreenHunter Resources, Inc. for water disposal which are at competitive market rates. These disposal charges recorded in lease operating expenses totaled $2.4 million for the year ended December 31, 2012.

In February 2012, Triad Hunter, LLC sold all of its equity interests in Hunter Disposal, LLC to GreenHunter Water, LLC, referred to as GreenHunter Water, a wholly-owned subsidiary of GreenHunter, for a purchase price of $8.8 million, subject to adjustment for certain working capital, earnings and other similar items. The terms and conditions of the purchase agreement between the parties were approved by an independent special committee of our Board. The special committee retained independent counsel and an independent consultant to assist in the negotiation, execution and closing of the sale. The consideration received by Triad Hunter, LLC consisted of cash, restricted common stock of GreenHunter, 10% cumulative preferred stock of GreenHunter and a convertible promissory note of GreenHunter. In connection with the sale, Triad Hunter, LLC entered into agreements with Hunter Disposal, LLC and GreenHunter Water for wastewater hauling and disposal capacity in Kentucky, Ohio and West Virginia pursuant to which Triad Hunter, LLC paid fees totaling $1,802,572 for the period from January 1, 2012 through November 26, 2012. Triad Hunter, LLC also entered into tank rentals with GreenHunter Water pursuant to which Triad Hunter, LLC paid fees totaling $370,905 for the period from January 1, 2012 through November 26, 2012.

Eagle Ford Hunter Inc., Triad Hunter, LLC and Alpha Hunter Drilling, LLC, wholly owned subsidiaries of the Company, regularly obtained, and we continue to obtain, services from GreenHunter Resources, Inc. for vacuum hauling, rig washing, waste fluid management and water management. The Company believes that such services are provided at competitive market rates and are comparable to or more attractive than rates that could be obtained from unaffiliated third-party suppliers of such services. Charges related to vacuum hauling, rig washing, waste fluid management and water management services recorded in lease operating expenses totaled $134,544 for the year ended December 31, 2012.

In August 2012, Alpha Hunter Drilling, LLC, or Alpha Hunter Drilling, a wholly-owned subsidiary of the Company, entered into two IADC drilling contracts with GreenHunter Water pursuant to each of which Alpha Hunter Drilling agreed to provide drilling rig and contract operator services to GreenHunter Water for the purpose of drilling saltwater disposal wells for GreenHunter Water to service the Company's Eagle Ford Shale operations in south Texas.

The Company anticipates that Eureka Hunter Pipeline, LLC, or Eureka Pipeline, which is a wholly-owned subsidiary of Eureka Hunter Holdings, LLC, or Eureka Holdings, a majority-owned subsidiary of the Company, will enter into a Water Hauling and Disposal Agreement with GreenHunter Water pursuant to which GreenHunter Water would dispose of condensate and salt water from wellhead production that is delivered into Eureka Pipeline's pipeline gathering system from various producers. Pursuant to the

125

Water Hauling and Disposal Agreement, Eureka Pipeline would pay GreenHunter Water a per-barrel fee for transportation and disposal of the condensate and salt water that over the course of eight years, the anticipated term of the agreement, could total up to $5 million.

TransTex Assets Acquisition

In April 2012, the Company, through Eureka Holdings, acquired certain assets of TransTex Gas Services, LP, or TransTex Gas Services. The purchase price paid for the acquired assets consisted of cash and Class A Common Units, or Eureka Common Units, representing membership interests in Eureka Holdings. In connection with the acquisition, the Company agreed to provide the limited partners of TransTex Gas Services the opportunity to purchase Eureka Common Units in lieu of a portion of the cash TransTex Gas Services would otherwise receive for the acquired assets. Consequently, during April 2012, certain limited partners of TransTex Gas Services, which included Mr. Evans, who held a small limited partnership interest in TransTex Gas Services, purchased Eureka Common Units, and the cash consideration paid to TransTex Gas Services for the acquired assets was reduced. Mr. Evans purchased 27,641 of such Eureka Common Units for $553,000 at the same per unit purchase price offered to all TransTex Gas Services limited partners. As of the date of the filing of this annual report, Mr. Evans owned less than 1% of the total number of Eureka Common Units outstanding.

Other

In 2011, we entered into a lease with an executive of the Company, as lessor, whereby we leased a corporate apartment in Houston, Texas from the executive, who had been transferred to our Appalachian operations, for monthly rent of $4,500, for use by Company employees. During the year ended December 31, 2012, the Company paid rent of $22,500 under this lease. The lease terminated in May 2012.

Director Independence

In accordance with the NYSE listing standards and applicable SEC rules and guidelines, our Board and our Governance Committee assess the independence of its members from time to time. Applying the applicable NYSE listing standards and SEC rules for independence, our Board, upon the recommendation of our Governance Committee, determined that Messrs. J. Raleigh Bailes, Sr., Brad Bynum, Victor G. Carrillo, Joe L. McClaugherty, Stephen C. Hurley, Steven A. Pfeifer and Jeff Swanson are independent directors.

Under the NYSE listing standards, a majority of our directors must be independent, and our Audit, Compensation and Governance Committees are each required to be composed solely of independent directors. The standards for Audit Committee membership include additional requirements under rules of the SEC. The Board has determined that all of the members of our Audit, Compensation and Governance Committees meet the applicable independence requirements. The listing standards relating to general independence consist of both a requirement for a Board determination that the director has no material relationship with the Company and a listing of several specific relationships that preclude independence.

Item 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

Aggregate fees for professional services rendered by BDO USA, LLP for the fiscal year ended December 31, 2012, and Hein & Associates LLP for the fiscal year ended December 31, 2011, are set forth below.

(In thousands)	2012	2011
Audit Fees	1,150	851
Audit-Related Fees	—	283
Total Auditor Fees	1,150	1,135

Audit Fees

The audit fees for the year ended December 31, 2012 were for professional services rendered by BDO USA, LLP. The audit fees for the year ended December 31, 2011 were for professional services rendered by Hein & Associates LLP. Audit fees relate to professional services rendered in connection with the audit of the Company's consolidated annual financial statements and internal control over financial reporting, quarterly review of consolidated financial statements included in the Company's Quarterly Reports on Form 10-Q and audit services provided in connection with other statutory and regulatory filings, including the filing of registration statements and audited and reviewed financial statements filed on certain Current Reports on Form 8-K.

126

Audit-Related Fees

Audit-related fees consist of fees for assurance and related services that are traditionally performed by the independent auditor, including consultation regarding accounting and reporting matters, review of pro forma financial statements and other financial information in regulatory and statutory filings and the issuance of comfort letters in connection with offerings by Magnum Hunter of common stock and preferred stock.

Audit Committee Pre-Approval Policy

The Audit Committee is responsible for appointing, setting the compensation for and overseeing the work of Magnum Hunter's independent auditor. In recognition of this responsibility, the Audit Committee is required to approve all audit and non-audit services performed by the Company's independent registered public accounting firm in order to assure that the provision of these services does not impair the independent auditor's independence; except that the Chairman of the Audit Committee has discretion to unilaterally engage accounting professionals previously approved by the Audit Committee to perform additional services, provided that the cost of such services does not exceed certain predetermined amounts. For 2012, the cost of pre-approved services could not exceed $15,000. The Chairman of the Audit Committee must report any such engagement at the next Audit Committee meeting.

The Audit Committee specifically approved all audit and non-audit services performed by our independent accountants in 2012.     

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PART IV

Item 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES

1. Consolidated Financial Statements: See Special Financial Report on Form 10-K of PRC Williston, LLC for fiscal year ended December 31, 2012. See Index to Financial Statements on page F-1 for PRC Williston, LLC financial statements included herein.

2. Financial Statement Schedules: All financial statement schedules are omitted as inapplicable or because the required information is contained in the financial statements or the notes thereto.

3. Exhibits: See the list of exhibits in the Index to Exhibits to this annual report on Form 10-K, which is incorporated by reference herein.

128

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

_____________________________________

Form 10-K

SPECIAL FINANCIAL REPORT PURSUANT TO RULE 15d-2 OF THE SECURITIES
EXCHANGE ACT OF 1934

Contains only the financial statements for the year ended December 31, 2012

Commission file number: 001-32997

_____________________________________

PRC Williston, LLC

(Name of registrant as specified in its charter)

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

777 Post Oak Boulevard, Suite 650, Houston, Texas 77056
(Address of principal executive offices, including zip code) (832) 369-6986

(Registrant’s telephone number including area code)

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

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  ¨    No   x

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  x    No   ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, 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   ¨    No   ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.    x

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer	¨		Accelerated filer	¨
Non-accelerated filer	¨	(Do not check if a smaller reporting company)	Smaller reporting company	x

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

State the aggregate market value of the voting and non-voting common equity held by non-affiliates: The membership interests, or participation interests that may be functionally equivalent to membership interests, of the registrant are not publicly traded. There is no aggregate market value for the registrant’s outstanding equity that is readily determinable.

_____________________________________

DOCUMENTS INCORPORATED BY REFERENCE

None.

PRC WILLISTON, LLC

EXPLANATORY NOTE

On February 7, 2013, the Securities and Exchange Commission (the “SEC”) declared effective the Registration Statement on Form S-4 of Magnum Hunter Resources Corporation (“Parent”), relating to Parent’s sale of Senior Notes. A detailed description of the offering is included in the Form S-4 Registration Statement.

Rule 15d-2 (“Rule 15d-2”) under the Securities Exchange Act of 1934, as amended, provides generally that if a company’s registration statement under the Securities Act of 1933, as amended, does not contain certified financial statements for the company’s last full fiscal year preceding the year in which the registration statement becomes effective (or for the life of the company if less than a full fiscal year), then the company must, within 90 days after the effective date of the registration statement, file a special financial report furnishing certified financial statements for the last full fiscal year or other period, as the case may be, meeting the requirements of the form appropriate for annual reports of that company. Rule 15d-2 further provides that the special financial report is to be filed under cover of the facing sheet of the form appropriate for annual reports of the company.

The Form S-4 Registration Statement did not contain the certified financial statements of PRC Williston, LLC, for the year ended December 31, 2012; therefore, as required by Rule 15d-2, Parent is hereby filing the certified financial statements of PRC Williston, LLC, with the SEC under cover of the facing page of an annual report on Form 10-K.

PRC WILLISTON, LLC

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO FINANCIAL STATEMENTS

Reports of Independent  Registered Public Accounting Firms	F-2
Balance Sheets at December 31, 2012 and 2011	F-4
Statements of Operations for the years ended December 31, 2012, 2011, and 2010	F-5
Statements of Changes in Member’s Deficit for the years ended December 31, 2012, 2011, and 2010	F-6
Statements of Cash Flows for the years ended December 31, 2012, 2011, and 2010	F-7
Notes to Financial Statements	F-8

F-1

PRC WILLISTON, LLC

Report of Independent Registered Public Accounting Firm

Board of Directors and Member

PRC Williston, LLC

Houston, Texas

We have audited the accompanying balance sheet of PRC Williston, LLC as of December 31, 2012, and the related statements of operations, changes in member's deficit, and cash flows for the year then ended. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting.Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of PRC Williston, LLC as at December 31, 2012 and the results of its operations and its cash flows for the year then ended, in conformity with accounting principles generally accepted in the United States of America.

/s/ BDO USA, LLP

Dallas, Texas

June 14, 2013

F-2

PRC WILLISTON, LLC

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Members

PRC Williston, LLC

We have audited the accompanying balance sheet of PRC Williston, LLC (the “Company”) as of December 31, 2011, and the related statements of operations, changes in member's deficit, and cash flows for each of the years ended December 31, 2011 and 2010. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of PRC Williston, LLC as of December 31, 2011, and the results of its operations and its cash flows for each of the years ended December 31, 2011 and 2010, in conformity with U.S. generally accepted accounting principles.

/s/ Hein & Associates LLP

Dallas, Texas

January 11, 2013

F-3

PRC WILLISTON, LLC

BALANCE SHEETS

(In thousands)

	December 31,
	2012			2011
ASSETS
CURRENT ASSETS:
Accounts receivable	$	703		$	2,188
Total current assets	703			2,188
PROPERTY AND EQUIPMENT:
Oil and natural gas properties, successful efforts method	33,800			46,462
Accumulated depletion and depreciation	(15,543		)	(13,855		)
Total oil and natural gas properties, net	18,257			32,607
Total Assets	$	18,960		$	34,795
LIABILITIES AND MEMBER’S DEFICIT
CURRENT LIABILITIES:
Accounts payable and accrued liabilities	$	1,402		$	1,319
Current portion of asset retirement obligation	889			-
Accounts payable due to Parent	58,966			60,173
Total current liabilities	61,257			61,492
Asset retirement obligation	1,274			1,983
Total liabilities	62,531			63,475
MEMBER’S DEFICIT:	(43,571		)	(28,680		)
Total Liabilities and Member’s Deficit	$	18,960		$	34,795

The accompanying Notes to Financial Statements are an integral part of these Statements.

F-4

PRC WILLISTON, LLC

STATEMENTS OF OPERATIONS

(In thousands)

	Year Ended December 31,
	2012			2011			2010
REVENUE:
Oil and gas sales	$	7,552		$	8,687		$	8,178
Other income	62			—			—
Total revenue	7,614			8,687			8,178
EXPENSES:
Lease operating	4,253			4,518			4,045
Severance taxes and marketing	384			603			874
Exploration and abandonments	10,461			—			1
Impairment of proved oil and gas properties	2,250			—			17
Depreciation, depletion, and accretion	1,868			1,868			2,315
General and administrative	1,197			2,650			5,567
Total expenses	20,413			9,639			12,819
OPERATING LOSS	(12,799		)	(952		)	(4,641		)
INTEREST EXPENSE	(2,092		)	(2,065		)	(2,456		)
Net loss	$	(14,891	)	$	(3,017	)	$	(7,097	)

The accompanying Notes to Financial Statements are an integral part of these Statements.

F-5

PRC WILLISTON, LLC

STATEMENT OF CHANGES IN MEMBER’S DEFICIT

(In thousands)

Balance, January 1, 2010	$	(18,566	)
Net loss	(7,097		)
Balance, December 31, 2010	$	(25,663	)
Net loss	(3,017		)
Balance, December 31, 2011	$	(28,680	)
Net loss	(14,891		)
Balance, December 31, 2012	$	(43,571	)

The accompanying Notes to Financial Statements are an integral part of these Statements.

F-6

PRC WILLISTON, LLC

STATEMENTS OF CASH FLOWS

(In thousands)

	Year Ended December 31,
	2012			2011			2010
Cash flows from operating activities
Net loss	$	(14,891	)	$	(3,017	)	$	(7,097	)
Adjustments to reconcile net loss to net cash used in operating activities:
Exploration and abandonments	10,461			—			—
Depletion, depreciation, and accretion	1,868			1,868			2,315
Impairment of proved oil and gas properties	2,250			—			17
Changes in operating assets and liabilities:
Accounts receivable	1,485			(1,131		)	(341		)
Accounts payable and accrued liabilities	83			542			288
Net cash (used in)/provided by operating activities	1,256			(1,738		)	(4,818		)
Cash flows from investing activities
Capital expenditures	(49		)	(175		)	(237		)
Net cash used in investing activities	(49		)	(175		)	(237		)
Cash flows from financing activities
(Repayments to) Advances from parent	(1,207		)	1,913			4,922
Net cash (used in)/provided by financing activities	(1,207		)	1,913			4,922
Net change in cash and cash equivalents	—			—			(133		)
Cash and cash equivalents, beginning of year	—			—			133
Cash and cash equivalents, end of year	$	—		$	—		$	—
Cash paid for interest	$	—		$	—		$	—

The accompanying Notes to Financial Statements are an integral part of these Statements.

F-7

NOTE 1—ORGANIZATION AND NATURE OF OPERATIONS

PRC Williston, LLC (the “Company or “PRC Williston”) is a subsidiary of Magnum Hunter Resources Corporation, a Delaware corporation, operating directly and indirectly through its subsidiaries (“Magnum Hunter” or “Parent”), a Houston, Texas based independent exploration and production company engaged in the acquisition and development of producing properties and undeveloped acreage and the production of oil and natural gas in the United States and Canada and certain midstream and oil field service activities. PRC Williston is engaged in secondary enhanced oil recovery projects in the United States, and all of its properties are non-operated in the Williston Basin.

The Company is a limited liability company (“LLC”). As an LLC, the amount of loss at risk for each individual member is limited to the amount of capital contributed to the LLC, and unless otherwise noted, the individual member’s liability for indebtedness of an LLC is limited to the member’s actual capital contribution. Magnum Hunter is the sole member of the company; however, the company has granted a 12.5% net profits interest. The net profits interest is functionally equivalent to a nonvoting class of membership interest in that it allows participation in any future distributions.

NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

Our financial statements are prepared in accordance with accounting principles generally accepted in the United States of America. The preparation of our financial statements requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses. These estimates are based on information that is currently available to us and on various other assumptions that we believe to be reasonable under the circumstances. Actual results could differ from those estimates under different assumptions and conditions. Significant estimates are required for proved oil and gas reserves which, as described below under Estimates of Proved Oil and Gas Reserves, may have a material impact on the carrying value of oil and gas property.

Financial Instruments

The carrying amounts of financial instruments including accounts receivable, accounts payable and accrued liabilities, and accounts payable to Parent approximate fair value as of December 31, 2012 and 2011.

Oil and Gas Properties

Capitalized Costs

Our oil and gas properties consisted of the following:

	December 31,
	2012			2011
	(in thousands)
Unproved properties	$	—		$	10,298
Proved properties	33,800			36,164
Total costs	33,800			46,462
Less accumulated depreciation and depletion	(15,543		)	(13,855		)
Net capitalized costs	$	18,257		$	32,607

We follow the successful efforts method of accounting for our oil and gas producing activities. Costs to acquire mineral interests in oil and gas properties and to drill and equip development wells and related asset retirement costs are capitalized. Costs to drill exploratory wells are capitalized pending determination of whether the wells have proved reserves. If we determine that the wells do not have proved reserves, the costs are charged to expense. There were no costs capitalized for exploratory wells pending the determination of proved reserves at either December 31, 2012 or 2011. Geological and geophysical costs, including seismic studies and costs of carrying and retaining unproved properties are charged to expense as incurred. We capitalize interest on expenditures for significant exploration and development projects that last more than six months while activities are in progress to bring the assets to their intended use. No interest was capitalized during the periods presented.

On the sale or retirement of a complete unit of a proved property, the cost and related accumulated depreciation, depletion, and amortization are eliminated from the property accounts, and the resultant gain or loss is recognized. On the retirement or sale of a partial unit of proved property, the cost is charged to accumulated depreciation, depletion, and amortization with a resulting gain or loss recognized in income.

F-8

Capitalized amounts attributable to proved oil and gas properties are depleted by the unit-of-production method over proved reserves using the unit conversion ratio of six Mcf of gas to one Bbl of oil and the ratio of forty-two Gal of natural gas liquids to one Bbl of oil. Well costs and related equipment are depleted over proved developed reserves, and leasehold costs are depleted over total proved reserves. Depreciation and depletion expense for oil and gas producing property and related equipment was $1.9 million, $1.9 million, and $2.3 million for the years ended December 31, 2012, 2011, and 2010, respectively.

Capitalized costs related to proved oil and gas properties, including wells and related equipment and facilities, are evaluated for impairment based on an analysis of undiscounted future net cash flows. If undiscounted cash flows are insufficient to recover the net capitalized costs related to proved properties, then we recognize an impairment charge in income from operations equal to the difference between the net capitalized costs related to proved properties and their estimated fair values based on the present value of the related future net cash flows. We recorded an impairment charge to our proved properties of $2.3 million during the year ended December 31, 2012, we recorded no impairments for the year ended December 31, 2011, and we incurred an impairment charge to our proved properties of $17,000 for the year ended December 31, 2010 based on our analysis.

Unproved oil and gas properties that are individually significant are periodically assessed for impairment of value, and a loss is recognized at the time of impairment by providing an impairment allowance in the Company's statement of operations. We recorded impairment to unproved properties of $10.5 million during the year ended December 31, 2012, and we did not record impairment during the years ended December 31, 2011, and 2010.

On the sale of an entire interest in an unproved property for cash or cash equivalent, gain or loss on the sale is recognized, taking into consideration the amount of any recorded impairment if the property had been assessed individually. If a partial interest in an unproved property is sold, the amount received is treated as a reduction of the cost of the interest retained.

Estimates of Proved Oil and Gas Reserves

Estimates of our proved reserves included in this report are prepared in accordance with U.S. generally accepted accounting principles (“GAAP”) and SEC guidelines. The accuracy of a reserve estimate is a function of:

·      the quality and quantity of available data;

·      the interpretation of that data;

·      the accuracy of various mandated economic assumptions;

·      and the judgment of the persons preparing the estimate.

Our proved reserve information included in this report was predominately based on evaluations prepared by independent petroleum engineers. Estimates prepared by other third parties may be higher or lower than those included herein. Because these estimates depend on many assumptions, all of which may substantially differ from future actual results, reserve estimates will be different from the quantities of oil and gas that are ultimately recovered. In addition, results of drilling, testing and production after the date of an estimate may justify material revisions to the estimate.

In accordance with SEC requirements, we based the estimated discounted future net cash flows from proved reserves on the unweighted arithmetic average of the  prior 12-month commodity prices as of the first day of each of the months constituting the period and costs on the date of the estimate. Future prices and costs may be materially higher or lower than these prices and costs which would impact the estimated value of our reserves.

The estimates of proved reserves may materially impact depreciation, depletion, and amortization (“DD&A”) expense. If the estimates of proved reserves decline, the rate at which we record depreciation and depletion expense will increase, reducing net income. Such a decline may result from lower estimated market prices.

Revenue Recognition

Revenues associated with sales of crude oil, natural gas, natural gas liquids and petroleum products, and other items are recognized when title passes to the customer, which is when the risk of ownership passes to the purchaser and physical delivery of goods occurs, either immediately or within a fixed delivery schedule that is reasonable and customary in the industry.

Revenues from the production of natural gas and crude oil properties in which we have an interest with other producers are recognized based on the actual volumes we sold during the period. Any differences between volumes sold and entitlement volumes, based on our

F-9

net working interest, which are deemed to be non-recoverable through remaining production, are recognized as accounts receivable or accounts payable, as appropriate. Cumulative differences between volumes sold and entitlement volumes are generally not significant.

Cash

The Company’s cash is held by its Parent. When the Company receives revenue, the cash is swept to Parent’s bank account and is applied against the accounts payable due to affiliate balance. Parent will not request payment of the intercompany payable balance for at least one year after December 31, 2012.

Accounts Receivable

Accounts receivable consists of oil and gas sales, due under normal trade terms, generally requiring payment within 30 to 60 days of production. Payments made on all accounts receivable are applied to the earliest unpaid items. We review our accounts receivable periodically and reduce the carrying amount by a valuation allowance that reflects our best estimate of the amount that may not be collectible. Based on our review, no allowance was warranted at either December 31, 2012 or 2011.

Production Costs

Production costs, including compressor rental and repair, pumpers’ salaries, saltwater disposal, ad valorem taxes, insurance, repairs and maintenance, expensed workovers and other operating expenses are expensed as incurred and included in lease operating expense on our consolidated statements of operations.

Severance Tax and Marketing

Severance taxes comprise production taxes charged by the state of North Dakota on oil and natural gas produced. These taxes are computed on the basis of volumes and/or value of production or sales. These taxes are usually levied at the time and place the minerals are severed from the producing reservoir. Marketing costs are those directly associated with marketing our production and are based on volumes produced.

Exploration and abandonments

Exploration expenses include dry hole costs, delay rentals, and geological and geophysical costs. Abandonment costs are charges to leasehold costs associated with properties that we chose not to develop and impair such costs.

Dependence on Major Customers

For the years ended December 31, 2012, 2011, and 2010, we sold 99%; 98%; and 98%, respectively, of our oil and gas produced to Plains Marketing, L.P. (“Plains”), a subsidiary of Plains All American Pipeline, L.P. Additionally, substantially all of our accounts receivable related to oil and gas sales were due from Plains at December 31, 2012 and 2011. We believe that there are potential alternative purchasers and that it may be necessary to establish relationships with new purchasers if our production grows. However, there can be no assurance that we can establish such relationships and that those relationships will result in increased purchasers. Although we are exposed to a concentration of credit risk, we believe that Plains is credit worthy.

Dependence on Suppliers

Our industry is cyclical, and from time to time there is a shortage of drilling rigs, fracture stimulation services, equipment, supplies and qualified personnel. During these periods, the costs and delivery times of rigs, equipment and supplies are substantially greater. If the unavailability or high cost of drilling rigs, equipment, supplies or qualified personnel were particularly severe in the areas where we operate, we could be materially and adversely affected. We believe that there are potential alternative providers of drilling services and that it may be necessary to establish relationships with new contractors as our activity level and capital program grows. However, there can be no assurance that we can establish such relationships and that those relationships will result in increased availability of drilling rigs.

Asset Retirement Obligation

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

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Our liability is determined using significant assumptions, including current estimates of plugging and abandonment costs, annual inflation of these costs, the productive lives of wells and our risk-adjusted interest rate. Changes in any of these assumptions can result in significant revisions to the estimated asset retirement obligation. See "Note 3 – Asset Retirement Obligations” to our financial statements for more information.

Income Taxes

The Company is not subject to federal income taxes and does not have a tax sharing agreement or allocate taxes with its member. Therefore, no provision has been made for federal or state income taxes on the Company’s books. It is the responsibility of the member to report its share of taxable income or loss on its separate income tax return. Accordingly, no recognition has been given to federal or state income taxes in the accompanying financial statements.

Based on management’s analysis, the Company did not have any uncertain tax positions as of December 31, 2012 or 2011. The Company’s income tax returns for the periods subsequent to December 31, 2009 remain open for examination by taxing authorities. Interest and penalties, and the associated tax expense related to uncertain tax positions, when applicable, will be recorded in income tax expense as the positions are recognized. At December 31, 2012, and 2011, there were no material income tax interest or penalty items recorded in the statement of operations or as a liability on the balance sheet.

NOTE 3 - ASSET RETIREMENT OBLIGATIONS

The Company accounts for asset retirement obligations based on the guidance of ASC 410 which addresses accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. ASC 410 requires that the fair value of a liability for an asset’s retirement obligation be recorded in the period in which it is incurred and the corresponding cost capitalized by increasing the carrying amount of the related long-lived asset. The liability is accreted to its present value each period, and the capitalized cost is depreciated over the estimated useful life of the related asset. Both the accretion of the liability and the depreciation of the asset are included in DD&A. We have included estimated future costs of abandonment and dismantlement in our successful efforts oil and gas properties base and deplete these costs as a component of our DD&A expense in the accompanying financial statements.

The following table summarizes the Company’s asset retirement obligation transactions during the years ended December 31:

	(in thousands)
	2012			2011
Asset retirement obligation at beginning of period	$	1,983		$	1,827
Accretion expense	180			156
Asset retirement obligation at end of period	2,163			1,983
Less: current portion	(889		)	—
Asset retirement obligation at end of period	$	1,274		$	1,983

NOTE 4 – RELATED PARTY TRANSACTIONS

The Company and its parent, Magnum Hunter, have an arrangement whereby Magnum Hunter provides funding to the Company for costs of developing oil and gas properties and Magnum Hunter allocates interest expense and general and administrative expenses to the Company. The allocation of interest expense is computed based on the amount funded to the Company multiplied by the interest rate applicable to Magnum Hunter’s revolving credit facility. The effective interest rate due by the Company to Magnum Hunter was approximately 3.56%, 3.55%, and 4.50% for the years ended December 31, 2012, 2011, and 2010, respectively. The interest expense allocated to PRC Williston was $2.1 million, $2.1 million, and $2.5 million, for the years ended December 31, 2012, 2011, and 2010, respectively. Accrued interest is included in accounts payable due to Parent. General and administrative expenses are allocated to the Company from Magnum Hunter on a pro rata basis relating to the Company’s revenues in proportion to the consolidated oil and gas sales of Magnum Hunter and all its subsidiaries. The general and administrative expense allocated to PRC Williston was $1.2 million, $2.7 million, and $5.6 million for the years ended December 31, 2012, 2011, and 2010, respectively. The accumulated charges from the general and administrative expense allocation are included in accounts payable due to Parent. At December 31, 2012, the balance due to Magnum Hunter was $59.0 million, and the balance was $60.2 million as of December 31, 2011.

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NOTE 5 - GUARANTEE

On May 16, 2012, the Company was named a guarantor subsidiary to the Senior Notes issued by the Parent, which are due November 2020. The Senior Notes were issued by the Parent pursuant to an indenture entered into on May 16, 2012 as supplemented, among the Parent, the subsidiary guarantors party thereto, Wilmington Trust, National Association, as the trustee, and Citibank, N.A., as the paying agent, registrar and authenticating agent.  The terms of the Senior Notes are governed by the indenture, which contains affirmative and restrictive covenants that, among other things, limit the Parent’s and the guarantors’ ability to incur or guarantee additional indebtedness or issue certain preferred stock; pay dividends on capital stock or redeem, repurchase or retire capital stock or subordinated indebtedness or make certain other restricted payments; transfer or sell assets; make loans and other investments; create or permit to exist certain liens; enter into agreements that restrict dividends or other payments from restricted subsidiaries to the Company; consolidate, merge or transfer all or substantially all of their assets; engage in transactions with affiliates; and create unrestricted subsidiaries.

The indenture also contains events of default.  Upon the occurrence of events of default arising from certain events of bankruptcy or insolvency, the Senior Notes shall become due and payable immediately without any declaration or other act of the trustee or the holders of the Senior Notes.  Upon the occurrence of certain other events of default, the trustee or the holders of at least 25% in aggregate principal amount of the then outstanding Senior Notes may declare all outstanding Senior Notes to be due and payable immediately.

The Parent had $600.0 million in principal outstanding under the Senior Notes as of December 31, 2012. The Company shares joint and several liability with other guaranteeing subsidiaries of the Parent, and the Company does not expect the default provisions to require recourse to the lenders. As such, the Company cannot estimate any potential loss as a result of the guarantee of indebtedness of the Parent.

NOTE 6 – SUPPLEMENTAL OIL AND GAS DISCLOSURES (UNAUDITED)

The following table sets forth the costs incurred in oil and gas property acquisition, exploration, and development activities.

	(in thousands)
	2012		2011		2010
Acquisition costs	$	—	$	—	$	—
Exploration costs	—		—		1
Development costs	49		—		80
	$	49	$	—	$	81

F-12

Oil and Gas Reserve Information

Proved oil and gas reserve quantities are based on estimates prepared by Magnum Hunter’s third party reservoir engineering firms. There are numerous uncertainties inherent in estimating quantities of proved reserves and projecting future rates of production and timing of development expenditures. The following reserve data only represent estimates and should not be construed as being exact.

Total Proved Reserves

	Crude oil and Condensate	Natural Gas
	(mbbl)	(mmcf)
Balances January 1, 2010	2,972	757
Extensions, discoveries and other additions	(444)	(94)
Production	(112)	(105)
Balances December 31, 2010	2,416	558
Revisions of previous estimates	(195)	119
Production	(103)	(82)
Balances December 31, 2011	2,118	595
Revisions of previous estimates	15	65
Production	(98)	(69)
Balances December 31, 2012	2,035	591
Developed reserves, included above
December 31, 2010	1,161	504
December 31, 2011	1,209	594
December 31, 2012	1,170	591

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Reserves

The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves and the changes in standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves were prepared in accordance with current provisions of ASC 932. Future cash inflows at December 31, 2012, 2011, and 2010 were computed by applying the unweighted, arithmetic average on the closing price on the first day of each month for the 12-month period prior to December 31, 2012, 2011, and 2010 to estimated future production. Future production and development costs are computed by estimating the expenditures to be incurred in developing and producing the proved oil and natural gas reserves at year-end, based on year-end costs and assuming continuation of existing economic conditions.

The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves are as follows:

	(in thousands)
	as of December 31,
	2012			2011			2010
Future cash inflows	$	159,290		$	185,867		$	166,661
Future production costs	(60,207		)	(79,959		)	(65,638		)
Future development costs	(6,966		)	(7,192		)	(8,360		)
Future net cash flows	92,117			98,716			92,663
10% annual discount for estimated timing of cash flows	(48,287		)	(47,401		)	(46,098		)
Standardized measure of discounted future net cash flows	$	43,830		$	51,315		$	46,565

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Changes in Standardized Measure of Discounted Future Net Cash Flows

The changes in the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves are as follows:

	(in thousands)
	Year Ended December 31,
	2012			2011			2010
Balances, beginning of period	$	51,315		$	46,565		$	45,681
Net change in sales and transfer prices and in production (lifting) costs related to future production	(1,454		)	9,324			11,320
Changes in estimated future development costs	108			1,074			4,277
Sales and transfers of oil and gas produced during the period	(2,650		)	(3,566		)	(3,259		)
Net change due to revisions in quantity estimates	571			(5,846		)	(15,431		)
Previously estimated development costs incurred during the period	—			—			80
Accretion of discount	5,132			4,656			3,442
Changes in timing and other	(9,192		)	(892		)	455
Standardized measure of discounted future net cash flows	$	43,830		$	51,315		$	46,565

The commodity prices inclusive of adjustments for quality and location used in determining future net revenues related to the standardized measure calculation are as follows.

	2012		2011		2010
Oil (per bbl)	$	77.90	$	86.86	$	68.59
Gas (per mcf)	$	1.24	$	3.11	$	1.78

F-14

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

MAGNUM HUNTER RESOURCES CORPORATION
By:	/s/ GARY C. EVANS
	Gary C. Evans
	Chairman of the Board and Chief Executive Officer

Date: June 14, 2013

Signature	Title	Date
/s/ Gary C. Evans	Chairman of the Board and	June  14, 2013
Gary C. Evans	Chief Executive Officer (Principal Executive Officer)
/s/ Ronald D. Ormand	Executive Vice President,	June  14, 2013
Ronald D. Ormand	Chief Financial Officer and Director (Principal Financial Officer)
/s/ Fred J. Smith, Jr.	Senior Vice President and	June  14, 2013
Fred J. Smith, Jr.	Chief Accounting Officer (Principal Accounting Officer)
/s/ J. Raleigh Bailes, Sr.	Director	June  14, 2013
J. Raleigh Bailes, Sr.
/s/ Brad Bynum	Director	June 14, 2013
Brad Bynum
/s/ Victor G. Carrillo	Director	June  14, 2013
Victor G. Carrillo
/s/ Stephen C. Hurley	Director	June  14, 2013
Stephen C. Hurley
/s/ Joe L. McClaugherty	Director	June  14, 2013
Joe L. McClaugherty
/s/ Steven A. Pfeifer	Director	June  14, 2013
Steven A. Pfeifer
/s/ Jeff Swanson	Director	June  14, 2013
Jeff Swanson

129

INDEX TO EXHIBITS
Exhibit Number	Description
2.1	Arrangement Agreement between the Registrant and NGAS Resources, Inc., dated December 23, 2010 (incorporated by reference from the Registrant’s current report on Form 8-K filed on December 30, 2010).+
2.2	Purchase and Sale Agreement between the Registrant, Quest Eastern Resource LLC and PostRock MidContinent Production, LLC, dated December 24, 2010 (incorporated by reference from the Registrant’s current report on Form 8-K/A filed on March 2, 2011).+@
2.3	Arrangement Agreement between the Registrant and NuLoch Resources Inc., dated January 19, 2011 (incorporated by reference from the Registrant’s current report on Form 8-K filed on January 25, 2011).+
2.3.1	Plan of Arrangement under Section 193 of the Business Corporations Act (Alberta) with respect to the Acquisition of NuLoch Resources Inc. by the Registrant (incorporated by reference from the Registrant’s registration statement on Form S-4 filed on April 8, 2011).+
2.4	Purchase and Sale Agreement by and among Triad Hunter, LLC and Windsor Marcellus, LLC (incorporated by reference from the Registrant’s current report on Form 8-K filed on April 12, 2011).+
2.5	Purchase and Sale Agreement by and among Triad Hunter, LLC, Quest Eastern Resource LLC and PostRock Energy Corporation, dated June 16, 2011 (incorporated by reference from the Registrant’s current report on Form 8-K filed on June 21, 2011).+
2.6	Purchase and Sale Agreement by and among Eagle Operating Inc., Williston Hunter ND, LLC and for the limited purposes set forth therein, the Registrant, dated August 4, 2011 (incorporated by reference from the Registrant’s current report on Form 8-K filed on August 5, 2011).+
2.6.1	Amendment to Purchase and Sale Agreement, dated as of March 5, 2012, by and among Eagle Operating, Inc., Williston Hunter ND, LLC, and the Registrant (incorporated by reference from the Registrant’s current report on Form 8-K filed on March 9, 2012).
2.6.2	Second Amendment to Purchase and Sale Agreement, dated April 2, 2012, by and among Eagle Operating, Inc., Williston Hunter ND, LLC, and the Registrant (incorporated by reference from the Registrant’s current report on Form 8-K filed on April 5, 2012).
2.7	Asset Purchase Agreement, dated March 21, 2012, by and among Eureka Hunter Holdings, LLC, TransTex Gas Services LP, and Eureka Hunter Acquisition Sub LLC (incorporated by reference from the Registrant’s current report on Form 10-Q filed on May 3, 2012).+
2.7.1	First Amendment to Asset Purchase Agreement, dated April 2, 2012, by and between Eureka Hunter Holdings, LLC, TransTex Gas Services, LP, and Eureka Hunter Acquisition Sub LLC (incorporated by reference from the Registrant’s quarterly report on Form 10-Q filed on May 3, 2012).
2.8	Purchase and Sale Agreement, dated as of April 17, 2012, by and between Baytex Energy USA Ltd. and Bakken Hunter, LLC (incorporated by reference from the Registrant’s current report on Form 8-K filed on April 24, 2012).+
2.8.1	First Amendment to Purchase and Sale Agreement, dated May 17, 2012, by and between Baytex Energy USA Ltd. and Bakken Hunter, LLC (incorporated by reference from the Registrant’s current report on Form 8-K filed on May 23, 2012).
2.8.2	Second Amendment to Purchase and Sale Agreement, dated May 22, 2012, by and between Baytex Energy USA Ltd. and Bakken Hunter, LLC (incorporated by reference from the Registrant’s current report on Form 8-K filed on May 23, 2012).
2.9	Stock Purchase Agreement, dated as of October 24, 2012, by and among Triad Hunter, LLC, Viking International Resources Co., Inc., all of the stockholders of Viking International Resources Co., Inc., and solely for the purposes set forth therein, the Registrant (incorporated by reference from the Registrant’s current report on Form 8-K filed on October 30, 2012).+
2.10	Purchase and Sale Agreement, dated as of November 21, 2012, between Samson Resources Company and Bakken Hunter, LLC (incorporated by reference from the Registrant’s current report on Form 8-K filed on November 28, 2012).+
2.11	Stock Purchase Agreement, dated as of April 2, 2013, between the Registrant, Penn Virginia Oil & Gas Corporation, and Penn Virginia Corporation (incorporated by reference from the Registrant's current report on Form 8-K filed on April 8, 2013).+
3.1	Restated Certificate of Incorporation of the Registrant, filed February 13, 2002 (incorporated by reference from the Registrant’s Registration Statement on Form SB-2 filed on March 21, 2006).

130

Exhibit Number	Description
3.1.1	Certificate of Amendment of Certificate of Incorporation of the Registrant, filed May 8, 2003 (incorporated by reference from the Registrant’s registration statement on Form SB-2 filed on March 21, 2006).
3.1.2	Certificate of Amendment of Certificate of Incorporation of the Registrant, filed June 6, 2005 (incorporated by reference from the Registrant’s registration statement on Form SB-2 filed on March 21, 2006).
3.1.3	Certificate of Amendment of Certificate of Incorporation of the Registrant, filed July 18, 2007 (incorporated by reference from the Registrant’s quarterly report on Form 10-QSB filed on August 14, 2007).
3.1.4	Certificate of Ownership and Merger Merging Magnum Hunter Resources Corporation with and into Petro Resources Corporation, filed July 13, 2009 (incorporated by reference from the Registrant’s current report on Form 8-K filed on July 14, 2009).
3.1.5	Certificate of Amendment of Certificate of Incorporation of the Registrant, filed November 3, 2010 (incorporated by reference from the Registrant’s current report on Form 8-K filed on November 2, 2010).
3.1.6	Certificate of Amendment of Certificate of Incorporation of the Registrant, filed May 9, 2011 (incorporated by reference from the Registrant’s quarterly report on Form 10-Q filed on March 31, 2011).
3.1.7	Certificate of Amendment of Certificate of Incorporation of the Registrant, filed June 29, 2011 (incorporated by reference from the Registrants registration statement on Form S-4 filed on January 14, 2013).
3.1.8	Certificate of Amendment of Certificate of Incorporation of the Registrant, filed January 25, 2013 (incorporated by reference from Amendment No. 1 to the Registrant’s registration statement on Form S-4 filed on February 5, 2013).
3.2	Amended and Restated Bylaws of the Registrant, dated March 15, 2001 as amended on April 14, 2006, and May 26, 2011 (incorporated by Reference from the Registrant's Quarterly Report on Form 10-Q filed on August 9, 2011).
4.1	Form of certificate for common stock (incorporated by reference from the Registrant’s annual report on Form 10-K filed on February 18, 2011).
4.2	Certificate of Designation of Rights and Preferences of 10.25% Series C Cumulative Perpetual Preferred Stock, dated December 10, 2009 (incorporated by reference from the Registrant’s registration statement on Form 8-A filed on December 10, 2009).
4.2.1	Certificate of Amendment of Certificate of Designation of Rights and Preferences of 10.25% Series C Cumulative Perpetual Preferred Stock, dated August 2, 2010 (incorporated by reference from the Registrant’s quarterly report on Form 10-Q filed on August 12, 2010).
4.2.2	Certificate of Amendment of Certificate of Designation of Rights and Preferences of 10.25% Series C Cumulative Perpetual Preferred Stock, dated September 8, 2010 (incorporated by reference from the Registrant’s current report on Form 8-K filed on September 15, 2010).
4.3	Certificate of Designation of Rights and Preferences of 8.0% Series D Cumulative Preferred Stock, dated March 16, 2011 (incorporated by reference from the Registrant’s current report on Form 8-K filed on March 17, 2011).
4.4	Certificate of Designations, Preferences and Rights of the Special Voting Preferred Stock (incorporated by reference from the Registrant's current report on Form 8-K filed on May 5, 2011).
4.5	Registration Rights Agreement, dated May 16, 2012, by and among the Registrant, the Guarantors named therein and Credit Suisse Securities (USA) LLC and Citigroup Global Markets Inc., as the representatives of the several Initial Purchasers named therein (incorporated by reference from the Registrant’s current report on Form 8-K filed on May 16, 2012).
4.5.1	Amendment Agreement to Registration Rights Agreement, dated December 13, 2012, by and among the Registrant, the Guarantors named therein and Credit Suisse Securities (USA) LLC and Citigroup Global Markets Inc., as the representatives of the several Initial Purchasers named therein (incorporated by reference from the Registrant's registration statement on Form S-4 filed on January 14, 2013).
4.6	Indenture, dated May 16, 2012, by and among the Registrant, the Guarantors named therein, Wilmington Trust, National Association and Citibank, N.A., as Paying Agent, Registrar and Authenticating Agent (incorporated by reference from the Registrant’s current report on Form 8-K filed on May 16, 2012).
4.6.1	First Supplemental Indenture, dated October 18, 2012, by and among the Registrant, the Guarantors named therein, Wilmington Trust, National Association, as Trustee, and Citibank, N.A., as Paying Agent, Registrar and Authenticating Agent (incorporated by reference from the Registrant's registration statement on Form S-4 filed on January 14, 2013).

131

Exhibit Number	Description
4.6.2	Second Supplemental Indenture, dated December 13, 2012, by and among the Registrant, the Guarantors named therein, Wilmington Trust, National Association, as Trustee, and Citibank, N.A., as Paying Agent, Registrar and Authenticating Agent (incorporated by reference from the Registrant's registration statement on Form S-4 filed on January 14, 2013).
4.6.3	Third Supplemental Indenture, dated April 24, 2013, by and among the Registrant, the Guarantors named therein, Wilmington Trust, National Association, as Trustee, and Citibank, N.A., as Paying Agent, Registrar and Authenticating Agent.#
4.7	Certificate of Designations of Rights and Preferences of the 8.0% Series E Cumulative Convertible Preferred Stock of the Registrant, dated November 2, 2012 (incorporated by reference from the Registrant’s current report on Form 8-K filed on November 8, 2012).
4.8	Deposit Agreement, dated as of November 2, 2012, by and among the Registrant, American Stock Transfer & Trust Company, as Depositary, and the holders from time to time of the depositary receipts described therein (incorporated by reference from the Registrant’s current report on Form 8-K filed on November 8, 2012).
4.9	Registration Rights Agreement dated December 18, 2012 among the Registrant, the Guarantors named therein and Citigroup Global Markets Inc., as representative of the Purchasers (incorporated by reference from the Registrant’s current report on Form 8-K filed on December 21, 2012).
10.1	Employment Agreement between the Registrant and Gary C. Evans, dated May 22, 2009 (incorporated by reference from the Registrant’s current report on Form 8-K filed on May 28, 2009).*
10.1.1	Amendment to Employment Agreement between the Registrant and Gary C. Evans, dated of November 14, 2011 (incorporated by reference from the Registrant’s annual report on Form 10-K filed on February 29, 2012).*
10.2	Employment Agreement between the Registrant and Ronald D. Ormand, dated May 22, 2009 (incorporated by reference from the Registrant’s current report on Form 8-K filed on May 28, 2009).*
10.2.1	Amendment to Employment Agreement between the Registrant and Ronald O. Ormand, dated of November 14, 2011 (incorporated by reference from the Registrant’s annual report on Form 10-K filed on February 29, 2012).*
10.3	Employment Agreement between the Registrant and H.C. “Kip” Ferguson, dated October 1, 2009 (incorporated by reference from the Registrant’s annual report on Form 10-K filed on February 18, 2011).*
10.3.1	Amendment to Employment Agreement between Registrant and H.C. “Kip” Ferguson, dated November 14, 2011 (incorporated by reference from the Registrant’s annual report on Form 10-K filed on February 29, 2012).*
10.4	Amended and Restated Stock Incentive Plan of Registrant (incorporated by reference from the Registrant’s current report on Form 8-K filed on December 3, 2010).*
10.4.1	First Amendment to Amended and Restated Stock Incentive Plan (incorporated by reference from the Registrant’s proxy statement on Annex C of Schedule 14A filed on April 1, 2011).*
10.4.2	Second Amendment to the Magnum Hunter Resources Corporation Amended and Restated Stock Incentive Plan (incorporated by reference from the Registrant’s registration statement on Form S-8 filed on February 14, 2013).
10.4.3	Third Amendment to the Magnum Hunter Resources Corporation Amended and Restated Stock Incentive Plan (incorporated by reference from the Registrant’s current report on Form 8-K filed on January 23, 2013).*
10.5	Form of Stock Option Agreement under the Registrant’s Amended and Restated Stock Incentive Plan (incorporated by reference from the Registrant’s annual report on Form 10-K filed on February 18, 2011).*
10.6	Form of Restricted Stock Award Agreement under the Registrant’s Amended and Restated Stock Incentive Plan (incorporated by reference from the Registrant’s current report on Form 8-K filed on December 3, 2010).*
10.7	Form of Stock Appreciation Right Agreement under the Registrant’s Amended and Restated Stock Incentive Plan (incorporated by reference from the Registrant’s current report on Form 8-K filed on December 3, 2010).*
10.8	Form of Executive Change of Control Retention Agreements (incorporated by reference from the Registrant’s annual report on Form 10-K filed on February 29, 2012).*
10.8.1	Amendment to Form of Executive Change of Control Retention Agreements (incorporated by reference from the Registrant’s annual report on Form 10-K filed on February 29, 2012).*

132

Exhibit Number	Description
10.9	Form of $3.00 Warrant sold as part of February 2006 private placement (incorporated by reference from the Registrant’s registration statement on Form SB-2 filed on March 21, 2006).
10.10	Purchase and Sale Agreement between the Registrant and Eagle Operating, Inc., dated December 11, 2006 (incorporated by reference from the Registrant’s annual report on Form 10-KSB for the year ended December 31, 2006, filed on April 2, 2007).
10.10.1	First Amendment to Purchase and Sale Agreement between the Registrant and Eagle Operating, Inc., dated January 25, 2007 (incorporated by reference from the Registrant’s annual report on Form 10-K filed on February 18, 2011).
10.11	Agreement and Plan of Merger between the Registrant, Sharon Hunter, Inc., Sharon Resources, Inc. and Sharon Energy Ltd., dated September 9, 2009 (incorporated by reference from the Registrant’s current report on Form 8-K filed on September 15, 2009).
10.12	Purchase and Sale Agreement between the Registrant and Centurion Exploration Company, LLC, dated September 14, 2009 (incorporated by reference from the Registrant’s current report on Form 8-K filed on September 15, 2009).
10.13	Asset Purchase Agreement between the Registrant and Triad Energy Corporation, dated October 28, 2009 (incorporated by reference from the Registrant’s current report on Form 8-K filed on October 29, 2009).
10.14	Form of Securities Purchase and Registration Rights Agreement with respect to November 5, 2009 offering (incorporated by reference from the Registrant’s current report on Form 8-K filed on November 6, 2009).
10.15	Form of Support Agreement between the Registrant and certain NGAS Resources, Inc. shareholders, dated December 23, 2010 (incorporated by reference from the Registrant’s current report on Form 8-K filed on December 30, 2010).
10.16	Omnibus Agreement between the Registrant, NGAS Resources, Inc., NGAS Production Co., NGAS Gathering, LLC, Seminole Energy Services, L.L.C., Seminole Gas Company, L.L.C. and NGAS Gathering II, LLC, dated March 10, 2011 (incorporated by reference from the Registrant’s current report on Form 8-K filed on March 16, 2011).@
10.17	Second Amended and Restated Credit Agreement between the Registrant, Bank of Montreal, Capital One, N.A., Amegy Bank National Association, KeyBank National Association, UBS Securities LLC, BMO Capital Markets, and the lenders party thereto, dated April 13, 2011 (incorporated by reference from the Registrant’s current report on Form 8-K filed on April 14, 2011).
10.17.1	First Amendment to Second Amended and Restated Credit Agreement (incorporated by reference from the Registrant’s Current Report on Form 8-K filed on July 19, 2011).
10.17.2	Second Amendment to Second Amended and Restated Credit Agreement (incorporated by reference from the Registrant’s current report on Form 8-K filed on August 18, 2011).
10.17.3	Third Amendment to Second Amended and Restated Credit Agreement (incorporated by reference from the Registrant’s current report on Form 8-K filed on October 4, 2011).
10.17.4	Fourth Amendment to Second Amended and Restated Credit Agreement (incorporated by reference from the Registrant’s current report on Form 8-K filed on December 12, 2011).+
10.17.5	Fifth Amendment to Second Amended and Restated Credit Agreement, dated February 14, 2012, by and among the Registrant, the Bank of Montreal, as Administrative Agent, and the lenders and guarantors party thereto (incorporated by reference from the Registrant’s current report on Form 8-K filed on February 21, 2012).+
10.17.6	Sixth Amendment to Second Amended and Restated Credit Agreement and Limited Waiver, dated May 2, 2012, by and among the Registrant, Bank of Montreal, as Administrative Agent, and the lenders and guarantors party thereto (incorporated by reference from the Registrant’s current report on Form 8-K filed on May 8, 2012).
10.17.7	Seventh Amendment to Second Amended and Restated Credit Agreement, dated May 2, 2012, by and among the Registrant, Bank of Montreal, as Administrative Agent, and the lenders and guarantors party thereto (incorporated by reference from the Registrant’s current report on Form 8-K filed on May 8, 2012).
10.17.8	Eighth Amendment to Second Amended and Restated Credit Agreement, dated May 10, 2012, by and among the Registrant, Bank of Montreal, as Administrative Agent, and the lenders and guarantors party thereto (incorporated by reference from the Registrant’s quarterly report on Form 10-Q filed on August 9, 2012).
10.17.9	Ninth Amendment to Second Amended and Restated Credit Agreement, dated August 8, 2012, by and among the Registrant, Bank of Montreal, as Administrative Agent, and the lenders and guarantors party thereto (incorporated by reference from the Registrant’s current report on Form 8-K filed on August 13, 2012).

133

Exhibit Number	Description
10.17.10	Tenth Amendment to Second Amended and Restated Credit Agreement, dated October 29, 2012, by and among the Registrant, Bank of Montreal, as Administrative Agent, and the lenders and guarantors party thereto (incorporated by reference from the Registrant’s current report on Form 8-K filed on November 14, 2012).
10.17.11	Eleventh Amendment to Second Amended and Restated Credit Agreement, dated November 7, 2012, by and among the Registrant, Bank of Montreal, as Administrative Agent, and the lenders and guarantors party thereto (incorporated by reference from the Registrant’s current report on Form 8-K filed on November 14, 2012).
10.17.12	Twelfth Amendment to Second Amended and Restated Credit Agreement, dated as of December 3, 2012, by and among the Registrant, Bank of Montreal, as administrative agent, and the lenders and guarantors party thereto (incorporated by reference from the Registrant’s current report on Form 8-K filed on December 7, 2012).
10.17.13	Thirteenth Amendment to Second Amended and Restated Credit Agreement, and Amendment to Amended and Restated Security Agreement dated as of December 18, 2012, by and among the Registrant, Bank of Montreal, as administrative agent, and the lenders and guarantors party thereto (incorporated by reference from the Registrant’s current report on Form 8-K filed on December 21, 2012).
10.17.14	Fourteenth Amendment to Second Amended and Restated Credit Agreement, and Amendment to Amended and Restated Security Agreement dated as of February 25, 2013, by and among the Registrant, Bank of Montreal, as administrative agent, and the lenders and guarantors party thereto (incorporated by reference from the Registrant’s current report on Form 8-K filed on March 1, 2013).
10.17.15	Fifteenth Amendment to Second Amended and Restated Credit Agreement and Limited Consent, entered into on March 18, 2013 and effective as of March 17, 2013, by and among the Registrant, Bank of Montreal, as administrative agent, and the lenders and guarantors party thereto (incorporated by reference from the Registrant's current report on Form 8-K filed on March 22, 2013).
10.17.16	Sixteenth Amendment to Second Amended and Restated Credit Agreement and Limited Consent, entered into on April 2, 2013 and effective as of April 2, 2013, by and among the Registrant, Bank of Montreal, as administrative agent, and the lenders and guarantors party thereto (incorporated by reference from the Registrant's current report on Form 8-K filed on April 8, 2013).
10.17.17	Seventeenth Amendment to Second Amended and Restated Credit Agreement, dated April 23, 2013, by and among the Registrant, Bank of Montreal, as administrative agent, and the lenders and guarantors party thereto (incorporated by reference from the Registrant's current report on Form 8-K filed on April 26, 2013).
10.18	Warrants Agreement (including Form of Warrant Certificate) between the Registrant and American Stock Transfer & Trust Company, dated October 13, 2011 (incorporated by reference from the Registrant’s current report on Form 8-K filed on October 18, 2011).
10.19	First Lien Credit Agreement by and among Eureka Hunter Pipeline, LLC, the lenders party thereto and SunTrust Bank (incorporated by reference from the Registrant’s current report on Form 8-K filed on August 22, 2011).
10.19.1	First Amendment to First Lien Credit Agreement, dated May 2, 2012, by and among Eureka Hunter Pipeline, LLC, SunTrust Bank, as Administrative Agent, and the lenders party thereto (incorporated by reference from the Registrant’s current report on Form 8-K filed on May 8, 2012).
10.19.2	Consent to First Lien Credit Agreement, dated March 18, 2013 and effective as of March 17, 2013, by and among Eureka Hunter Pipeline, LLC, SunTrust Bank, as Administrative Agent, and the lenders party thereto (incorporated by reference from the Registrant's current report on Form 8-K filed on March 22, 2013).
10.19.3	Consent to First Lien Credit Agreement, dated May 15, 2013, by and among Eureka Hunter Pipeline, LLC, SunTrust Bank, as Administrative Agent, and the lenders party thereto (incorporated by reference from the Registrant's current report on Form 8-K filed on May 21, 2013).
10.20	Second Lien Term Loan Agreement by and among Eureka Hunter Pipeline, LLC, the lenders party thereto and PennantPark Investment Corporation (incorporated by reference from the Registrant’s current report on Form 8-K filed on August 22, 2011).+
10.20.1	First Amendment to Second Lien Term Loan Agreement, dated September 20, 2011, by and among Eureka Hunter Pipeline, LLC, PennantPark Investment Corporation and the other lenders party thereto (incorporated by reference from the Registrant’s current report on Form 8-K filed on May 8, 2012).
10.20.2	Limited Waiver to Second Lien Term Loan Agreement, dated May 2, 2012, by and among Eureka Hunter Pipeline, LLC, U.S. Bank National Association, as Collateral Agent, PennantPark Investment Corporation and the other lenders party thereto (incorporated by reference from the Registrant’s current report on Form 8-K filed on May 8, 2012).

134

Exhibit Number	Description
10.20.3	Second Amendment to Second Lien Term Loan Agreement by and among Eureka Hunter Pipeline, LLC, PennantPark Investment Corporation and the other lenders party thereto (incorporated by reference from Registrant’s current report on Form 8-K filed on May 8, 2012).
10.20.4	Limited Waiver and Third Amendment to Second Lien Term Loan Agreement, dated June 29, 2012, by and among Eureka Hunter Pipeline, LLC, PennantPark Investment Corporation and the other lenders party thereto (incorporated by reference from Registrant’s current report on Form 8-K filed on July 6, 2012).
10.20.5	Consent to Second Lien Term Loan Agreement, dated March 18, 2013 and effective as of March 17, 2013, by and among Eureka Hunter Pipeline, LLC, PennantPark Investment Corporation and the other lenders party thereto (incorporated by reference from the Registrant's current report on Form 8-K filed on March 22, 2013).
10.20.6	Consent and Fourth Amendment to Second Lien Term Loan Agreement, dated May 15, 2013, by and among Eureka Hunter Pipeline, LLC, PennantPark Investment Corporation and the other lenders party thereto (incorporated by reference from the Registrant's current report on Form 8-K filed on May 21, 2013).
10.21	Second Lien Credit Agreement by and among the Registrant, Capital One, N.A., and the lenders and guarantors party thereto, dated September 28, 2011 (incorporated by reference from the Registrant’s current report on Form 8-K filed on October 4, 2011).
10.21.1	Second Lien Credit Agreement by and among the Registrant, Capital One, N.A., and the lenders and guarantors party thereto, dated September 28, 2011 (incorporated by reference from the Registrant’s current report on Form 8-K filed on October 4, 2011).
10.21.2	Second Amendment to Second Lien Term Loan Credit Agreement, dated February 14, 2012, by and among the Registrant, Capital One, N.A., as Administrative Agent, and the lenders and guarantors party thereto (incorporated by reference from the Registrant’s current report on Form 8-K filed on February 21, 2012).+
10.21.3	Third Amendment to Second Lien Term Loan Credit Agreement and Limited Waiver, dated May 2, 2012, by and among the Registrant, Capital One, N.A., as Administrative Agent, and the lenders and guarantors party thereto (incorporated by reference from the Registrant’s current report on Form 8-K filed on May 8, 2012).
10.21.4	Fourth Amendment to Second Lien Term Loan Credit Agreement, dated May 2, 2012, by and among the Registrant, Capital One, N.A., as Administrative Agent, and the lenders and guarantors party thereto (incorporated by reference from the Registrant’s current report on Form 8-K filed on May 8, 2012).
10.22	At the Market Sales Agreement (Series D Preferred Stock), dated January 18, 2012 between the Registrant and MLV & Co., LLC (incorporated by reference from Registrant’s current report on Form 8-K filed on January 18, 2012) (incorporated by reference from the Registrant’s current report on Form 8-K filed on January 19, 2012).
10.23	At the Market Sales Agreement (Series D Preferred Stock) between the Registrant and Wunderlich Securities, Inc., dated January 18, 2012 (incorporated by reference from the Registrant’s current report on Form 8-K filed on January 19, 2012).
10.24	At the Market Sales Agreement (Common Stock) between the Registrant and MLV & Co., LLC, dated January 18, 2012 (incorporated by reference from the Registrant’s current report on Form 8-K filed on January 19, 2012).
10.25	Amended and Restated Limited Liability Company Agreement of Eureka Holdings, dated March 21, 2012, between the Registrant and ArcLight Capital Partners, LLC. (incorporated by reference from the Registrant’s quarterly report on Form 10-Q filed on May 3, 2012). +
10.25.1	First Amendment to Amended and Restated Limited Liability Company Agreement of Eureka Hunter Holdings, LLC, dated April 2, 2012, by and between the Registrant, Ridgeline Midstream Holdings, LLC, and TransTex Gas Services LP (incorporated by reference from the Registrant’s quarterly report on Form 10-Q filed on May 3, 2012).
10.25.2	Second Amendment to Amended and Restated Limited Liability Company Agreement of Eureka Hunter Holdings, LLC, dated March 7, 2013 by and between the Registrant, Ridgeline Midstream Holdings, LLC, and TransTex Gas Services LP (incorporated by reference from the Registrant’s current report on Form 8-K filed on March 13, 2013, 2013).

135

Exhibit Number	Description
10.26	Series A Convertible Preferred Unit Purchase Agreement, dated March 21, 2012, by and among Eureka Hunter Holdings, LLC, the Registrant, and Ridgeline Midstream Holdings, LLC (incorporated by reference from the Registrant’s quarterly report on Form 10-Q filed on May 3, 2012). +
10.27	At the Market Sales Agreement (Series E Preferred Stock) between the Registrant and MLV Co., LLC, dated January 23, 2013 (incorporated by reference from the Registrant's current report on Form 8-K filed on January 25, 2013).
10.28	Registration Rights, Lock-up and Buy-back Agreement, dated as of April 24, 2013, between the Registrant and Penn Virginia Corporation (incorporated by reference from the Registrant's current report on Form 8-K filed on April 30, 2013).
10.29	Standstill Agreement, dated as of April 24, 2013, between the Registrant and Penn Virginia Corporation (incorporated by reference from the Registrant's current report on Form 8-K filed on April 30, 2013).
10.30	Form of Indemnification Agreement for Directors (incorporated by reference from the Registrant's current report on Form 8-K filed on June 7, 2013).*
10.31	Form of Indemnification Agreement for Officers (incorporated by reference from the Registrant's current report on Form 8-K filed on June 7, 2013).*
12.1	Computation of Ratio of Earnings to Fixed Charges.#
16.1	Letter from PricewaterhouseCoopers LLP to the Securities and Exchange Commission, dated April 18, 2013 (incorporated by reference from the Registrant's current report on Form 8-K/A filed on April 22, 2013).
21.1	List of Subsidiaries.#
23.1	Consent of BDO USA, LLP.#
23.2	Consent of Hein & Associates LLP.#
23.3	Consent of Cawley Gillespie & Associates, Inc.#
31.1	Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.#
31.2	Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.#
32.1	Certification of the Chief Executive Officer and Chief Financial Officer provided pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.#
99.1	Independent Engineer Reserve Report for the year ended December 31, 2012 prepared by Cawley Gillespie & Associates, Inc.#
101.INS^	XBRL Instance Document.
101.SCH^	XBRL Taxonomy Extension Schema Document.
101.CAL^	XBRL Taxonomy Extension Calculation Linkbase Document.
101.LAB^	XBRL Taxonomy Extension Label Linkbase Document.
101.PRE^	XBRL Taxonomy Extension Presentation Linkbase Document.
101.DEF^	XBRL Taxonomy Extension Definition Presentation Linkbase Document.

136

*	The referenced exhibit is a management contract, compensatory plan or arrangement.
+	The schedules to this exhibit have been omitted pursuant to Item 601(b)(2) of Regulation S-K and will be provided to the SEC upon request.
@	Portions of this exhibit are subject to a request for confidential treatment and have been redacted and filed separately with the SEC.
#	Filed Herewith
^	These exhibits are furnished herewith. In accordance with Rule 406T of Regulation S-T, these exhibits are not deemed to be filed or part of a registration statement or prospectus for purposes of Section 11 or 12 of the Securities Act of 1933, as amended, are not deemed to be filed for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, and otherwise are not subject to liability under these sections.

137