Ngas Gathering 424B3 Prospectus supplement

PROSPECTUS Filed Pursuant to Rule 424(b)(3)

Registration No. 333-190956

MAGNUM HUNTER RESOURCES CORPORATION

Offer to Exchange

$600,000,000 Registered
9.750% Senior Notes due 2020 and Related Guarantees

for
$600,000,000 Outstanding
9.750% Senior Notes due 2020 and Related Guarantees

Offer for outstanding 9.750% Senior Notes due 2020, in the aggregate principal amount of $600,000,000, consisting of (i) $450,000,000 aggregate principal amount of 9.750% Senior Notes due 2020 issued on May 16, 2012 (the “original notes”), and (ii) $150,000,000 aggregate principal amount of 9.750% Senior Notes due 2020 issued on December 18, 2012 as additional notes under the indenture governing the original notes (the “add-on notes” and, together with the original notes, the “outstanding notes”) in exchange for up to $600,000,000 in aggregate principal amount of 9.750% Senior Notes due 2020 which have been registered under the Securities Act of 1933, as amended (the “exchange notes” and, together with the outstanding notes, the “notes”).

The Exchange Offer

The exchange offer expires at 5:00 p.m., New York City time, on November 7, 2013, unless extended.

The exchange offer is not conditioned upon the tender of any minimum aggregate amount of the outstanding notes.

All of the outstanding notes tendered according to the procedures set forth in this prospectus and not withdrawn will be exchanged for an equal principal amount of exchange notes.

The exchange offer is not subject to any condition other than that it does not violate applicable laws or any applicable interpretation of the staff of the Securities and Exchange Commission, or the SEC.

We urge you to carefully review the risk factors beginning on page 8 of this prospectus, which you should consider before participating in the exchange offer.

The Exchange Notes

The terms of the exchange notes to be issued in the exchange offer are substantially identical to the outstanding notes, except that we have registered the exchange notes with the SEC. In addition, the exchange notes will not be subject to the transfer restrictions applicable to the outstanding notes or contain provisions relating to additional interest, will bear a different CUSIP or ISIN number from the outstanding notes and will not entitle the holder to registration rights. We will not apply for listing of the exchange notes on any securities exchange or arrange for them to be quoted on any quotation system.

The Guarantees

Like the outstanding notes, the exchange notes will be jointly and severally guaranteed on a senior unsecured basis by certain of our existing and future direct or indirect domestic subsidiaries, including subsidiaries that guarantee obligations under certain of our existing credit facilities.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

Each broker-dealer that receives exchange notes for its own account pursuant to the exchange offer must acknowledge that it will deliver a prospectus in connection with any resale of such exchange notes. The letter of transmittal states that by so acknowledging and by delivering a prospectus, a broker-dealer will not be deemed to admit that it is an “underwriter” within the meaning of the Securities Act of 1933, as amended. This prospectus, as it may be amended or supplemented from time to time, may be used by a broker-dealer in connection with resales of exchange notes received in exchange for outstanding notes where such outstanding notes were acquired by such broker-dealer as a result of market-making activities or other trading activities. The Company has agreed that, for a period of 180 days after the expiration date (as defined herein), it will use commercially reasonable efforts to make this prospectus available to any broker-dealer for use in connection with any such resale. We may be unable to provide a current prospectus, however. See “Plan of Distribution" and “Risk Factors-You may be required to deliver a prospectus and comply with other requirements in connection with any resale of the exchange notes. We may be unable to provide a current prospectus, however, due to our inability to incorporate by reference.”

The date of this prospectus is October 8, 2013.

TABLE OF CONTENTS



	Page
CAUTIONARY NOTICE REGARDING FORWARD-LOOKING STATEMENTS	v
NON-GAAP FINANCIAL MEASURES	vii
GLOSSARY OF OIL AND NATURAL GAS TERMS	viii
SUMMARY	1
RISK FACTORS	8
THE EXCHANGE OFFER	35
DESCRIPTION OF THE EXCHANGE NOTES	42
USE OF PROCEEDS	81
CERTAIN MATERIAL UNITED STATES FEDERAL INCOME TAX CONSIDERATIONS	82
PLAN OF DISTRIBUTION	83
RATIO OF EARNINGS TO FIXED CHARGES	85
SELECTED FINANCIAL DATA	86
DESCRIPTION OF OTHER MATERIAL INDEBTEDNESS	87
BUSINESS	90
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	107
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	144
PROPERTIES	146
CONTROLS AND PROCEDURES	169
LEGAL PROCEEDINGS	172
MANAGEMENT	174
EXECUTIVE COMPENSATION	179
SECURITY OWNERSHIP OF MANAGEMENT AND CERTAIN BENEFICIAL OWNERS	188
TRANSACTIONS WITH RELATED PERSONS	191
LEGAL MATTERS	193
EXPERTS	193
WHERE YOU CAN FIND ADDITIONAL INFORMATION	193
INDEX TO FINANCIAL STATEMENTS	F-1

____________________

We have not authorized anyone to give you any information or to make any representations about anything we discuss in this prospectus other than those contained in the prospectus. If you are given any information or representation about these matters that is not discussed in this prospectus, you must not rely on that information.

We are not making an offer to sell, or a solicitation of an offer to buy, the exchange notes or the outstanding notes in any jurisdiction where, or to any person to or from whom, the offer or sale is not permitted.

In making an investment decision, investors must rely on their own examination of the issuer and the terms of the offer, including the merits and risks involved. These securities have not been recommended by any federal or state securities commission or regulatory authority. Furthermore, the foregoing authorities have not confirmed the accuracy or determined the adequacy of this document. Any representation to the contrary is a criminal offense.

We are not making any representation to any holder of the outstanding notes regarding the legality of an investment in the exchange notes under any legal investment or similar laws or regulations. We are not providing you with any legal, business, tax or other advice in this prospectus. You should consult your own attorney, business advisor and tax advisor to assist you in making your investment decision and to advise you whether you are legally permitted to invest in the exchange notes.

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In connection with the exchange offer, we have filed with the U.S. Securities and Exchange Commission, or the “SEC,” a registration statement on Form S-4, under the Securities Act of 1933, as amended, or the “Securities Act,” relating to the exchange notes to be issued in the exchange offer. As permitted by the SEC, this prospectus omits information included in the registration statement. For a more complete understanding of the exchange offer, you should refer to the registration statement, including its exhibits, which is available at the SEC website - www.sec.gov.

You may also obtain this information without charge by writing or telephoning us at the following address and telephone number:

Magnum Hunter Resources Corporation,

777 Post Oak Boulevard, Suite 650,

Houston, Texas 77056

Telephone: (832) 369-6986)

To obtain timely delivery of any requested information, holders of outstanding notes must make any request no later than five business days prior to the expiration of the exchange offer, or by October 31, 2013.

____________________

CAUTIONARY NOTICE REGARDING FORWARD-LOOKING STATEMENTS

The statements and information contained in this prospectus 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. The safe harbor protections of the Securities Act and Exchange Act are not available for forward-looking statements made in connection with an exchange offer.

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 and globally;


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


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


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


•	the effects of government regulation, permitting and other legal requirements;


•	future developments with respect to the quality of our properties, including, among other things, the existence of reserves in economic quantities;


•	uncertainties about the estimates of our oil and natural gas reserves;


•	our ability to increase our production and oil and natural gas income through exploration and development;


•	our use of geoscientific, petrophysical 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 gathering and transportation pipelines;


•	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;


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


•	the risks described under the heading “Risk Factors” in this prospectus.

These factors are in addition to the risks described in the “Management’s Discussion and Analysis of Financial Condition and Results of Operations” sections of this prospectus. 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 filings 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 SEC.

NON-GAAP FINANCIAL MEASURES

We refer to the term PV-10 in this prospectus. 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 and June 30, 2013, see “Properties—Non-GAAP Measures; Reconciliations."

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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 prospectus.


bbl	Stock tank barrel, or 42 U.S. gallons liquid volume, used in this prospectus 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.

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Leasehold	Mineral rights leased in a certain area to form a project area.


mbbls	Thousand barrels of crude oil or other liquid hydrocarbons.


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.


mgal	Thousands of gallons of natural gas liquids.


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.


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.

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 well bore, 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.


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.

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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.


/d	“Per day” when used with volumetric units or dollars.

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SUMMARY

This summary highlights information appearing elsewhere in this prospectus. This summary does not contain all of the information that you should consider before investing in our notes. You should carefully read this entire prospectus, including the section captioned “Risk Factors” beginning on page 8, the financial statements and other information in this prospectus before making an investment decision with respect to the securities offered hereby. Unless stated otherwise or unless the context otherwise requires, all references in this prospectus to Magnum Hunter, the Company, we, our, ours and us are to Magnum Hunter Resources Corporation and its consolidated subsidiaries.

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 NGLs 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, Kentucky, Texas and Saskatchewan, Canada. 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 on acquired acreage. 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 and mineral leasehold acreage positions in our core operating regions, expansion of our midstream operations and, ultimately, the possible monetization of our assets.

On April 24, 2013, we monetized certain of the Company’s 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 (after customary initial purchase price adjustments) and $42.3 million in Penn Virginia common stock (valued based on the closing market price of the stock of $4.23 per share as of April 24, 2013). In accordance with the stock purchase agreement, the Company supplied Penn Virginia with its calculation of the final cash purchase price adjustments on August 22, 2013, with final settlement expected to occur within 60 days of such date. 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 and Utica Shale plays in Appalachia and our Bakken and Sanish plays in the Williston Basin. (See “Note 6—Divestments and Discontinued Operations” to our consolidated financial statements for further details.)

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 area, for a total 2013 upstream capital expenditure budget of $300 million.

We are exploring the possible monetization in 2014 of all or part of our midstream operations. In addition, we have also identified a number of properties (our remaining properties in south Texas and certain properties in North Dakota, Kentucky and Canada), which we believe represent up to $300 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 robotic walking drilling rig that can also drill the horizontal sections of wells in the shale plays where we are active. This drilling rig was designed especially for pad drilling with its unique footprint and capability to walk and rotate without being dismantled.

Corporate Information

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 prospectus to Magnum Hunter, the Company, we, our, ours and us are to Magnum Hunter Resources Corporation and its consolidated subsidiaries.

Risk Factors

Investing in our notes involves substantial risks. You should carefully consider all of the information set forth in this prospectus and, in particular, the information under the heading “Risk Factors” beginning on page 8 in evaluating an investment in the exchange notes and participation in the exchange offer.

The Exchange Offer



Background of the Outstanding Notes	Magnum Hunter issued $600,000,000 aggregate principal amount of the outstanding notes, consisting of (i) $450,000,000 aggregate principal amount of the original notes issued on May 16, 2012 to Citigroup Global Markets Inc., Credit Suisse Securities (USA) LLC, BMO Capital Markets Corp., Capital One Southcoast, Inc., Deutsche Bank Securities Inc., Goldman, Sachs & Co., RBC Capital Markets, LLC, UBS Securities LLC, ABN AMRO Securities (USA) LLC, KeyBanc Capital Markets Inc., SunTrust Robinson Humphrey, Inc., Canaccord Genuity Inc., MLV & Co., Simmons & Company International, Stephens Inc. and Wunderlich Securities, Inc. as the initial purchasers (the “original initial purchasers”), and (ii) $150,000,000 aggregate principal amount of the add-on notes issued on December 18, 2012 to Citigroup Global Markets Inc., BMO Capital Markets Corp., Deutsche Bank Securities Inc., Goldman, Sachs & Co., Capital One Southcoast, Inc., RBC Capital Markets, LLC, Merrill Lynch Pierce, Fenner & Smith Incorporated, Credit Suisse Securities (USA) LLC, UBS Securities LLC, ABN AMRO Securities (USA) LLC, KeyBanc Capital Markets Inc. and SunTrust Robinson Humphrey, Inc. as the initial purchasers (the “add-on initial purchasers” and, together with the original initial purchasers, the “initial purchasers”). The original notes and the add-on notes have identical terms, were issued under the same indenture, are treated as a single class of securities under the indenture and, once exchanged for the exchange notes, will trade fungibly. After each issuance, the initial purchasers sold the outstanding notes to qualified institutional buyers and certain non-U.S. investors in reliance on Rule 144A and Regulation S under the Securities Act of 1933, or the Securities Act. Because they were sold pursuant to exemptions from registration, the outstanding notes are subject to transfer restrictions. In connection with the issuances of the original notes and the add-on notes, we entered into registration rights agreements in which we agreed to file a registration statement, of which this prospectus forms a part, with respect to a registered offer to exchange the exchange notes for the outstanding notes. We agreed to use our commercially reasonable efforts to consummate the exchange offer not later than May 15, 2013, but failed to consummate the exchange offer by such date for reasons discussed in this prospectus, including in the section entitled “Risks Related to our Business. We have been required to pay additional interest on our outstanding notes since May 16, 2013 as a result of our failure to complete an exchange offer for our outstanding notes, and we may encounter additional difficulties in completing the exchange offer for our outstanding notes due to our loss of eligibility to incorporate information by reference in our SEC registration statements.”



The Exchange Offer	We are offering to exchange up to $600 million principal amount of the exchange notes for an identical principal amount of the outstanding notes. The terms of the exchange notes are identical in all material respects to the outstanding notes except that the exchange notes will be registered under the Securities Act and will not be subject to provisions relating to additional interest. Because we are registering the exchange notes, the exchange notes generally will not be subject to transfer restrictions and holders of exchange notes will have no registration rights.
Resale of Exchange Notes	We believe you may offer, sell or otherwise transfer the exchange notes you receive in the exchange offer without compliance with the registration and prospectus delivery provisions of the Securities Act, provided that: § you acquire the exchange notes you receive in the exchange offer in the ordinary course of your business; § you are not participating in, have no understanding with any person to participate in and do not intend to engage in the distribution of the exchange notes issued to you in the exchange offer; and § you are not an affiliate of ours.
Expiration Date	The expiration date shall be 5:00 p.m., New York City time, on November 7, 2013 unless we extend the exchange offer, in which case the expiration date shall be the latest date to which the exchange offer is extended. It is possible that we will extend the exchange offer until all of the outstanding notes are tendered. You may withdraw the outstanding notes you tendered at any time before 5:00 p.m., New York City time, on the expiration date. See “The Exchange Offer—Expiration Date; Extensions; Amendments.”
Withdrawal Rights	You may withdraw the outstanding notes you tender by furnishing a notice of withdrawal to the exchange agent or by complying with applicable Automated Tender Offer Program, or ATOP, procedures of The Depository Trust Company, or DTC, at any time before 5:00 p.m., New York City time on the expiration date. See “The Exchange Offer—Withdrawal of Tenders.”
Conditions to the Exchange Offer	We will not be required to accept for exchange, or to issue exchange notes for, any outstanding notes if we determine that the exchange offer would violate any applicable law or applicable interpretations of the staff of the SEC. In addition, we will not accept for exchange any outstanding notes tendered, and no exchange notes will be issued in exchange for any such outstanding notes: § at any time when this prospectus needs to be updated through the filing with the SEC of a post-effective amendment to the registration statement, of which this prospectus is a part; § at any time any stop order is threatened or in effect with respect to the registration statement of which this prospectus constitutes a part; or § at any time any stop order is threatened or in effect with respect to the qualification of the indenture governing the notes under the Trust Indenture Act of 1939. See “The Exchange Offer—Conditions.” The exchange offer is not conditioned on a minimum aggregate principal amount of outstanding notes being tendered. We reserve the right to terminate, suspend or amend the exchange offer at any time prior to the applicable expiration date upon the occurrence of any of the foregoing events.



Representations and Warranties	By participating in the exchange offer, you represent to us that, among other things: § you will acquire the exchange notes you receive in the exchange offer in the ordinary course of your business; § you are not participating in, and have no agreement or understanding with any person to participate in, the distribution of the exchange notes issued to you in the exchange offer; § you are not an affiliate of ours or, if you are an affiliate, you will comply with the registration and prospectus delivery requirements of the Securities Act to the extent applicable; § if you are not a broker-dealer, that you are not engaged in and do not intend to engage in the distribution of the exchange notes; and § if you are a broker-dealer that will receive exchange notes for your own account in exchange for outstanding notes that were acquired as a result of market-making or other trading activities, that you will deliver a prospectus, as required by law, in connection with any resale of those exchange notes. We may be unable to provide you with a current prospectus, however. See “Risk Factors-You may be required to deliver a prospectus and comply with other requirements in connection with any resale of the exchange notes. We may be unable to provide a current prospectus, however, due to our inability to incorporate by reference.”
Procedures for Tendering Our Outstanding Notes	To participate in the exchange offer, you must follow the procedures established by DTC for tendering notes held in book-entry form. These procedures require that (i) the exchange agent receive, prior to the expiration date of the exchange offer, a computer generated message known as an “agent’s message” that is transmitted through ATOP; and (ii) DTC confirms that: • DTC has received your instructions to exchange your notes, and • you agree to be bound by the terms of the letter of transmittal. For more information, see “The Exchange Offer—Procedures for Tendering.”
Tenders by Beneficial Owners	If you are a beneficial owner whose outstanding notes are registered in the name of a broker, dealer, commercial bank, trust company or other nominee and wish to tender those outstanding notes in the exchange offer, please contact the registered holder as soon as possible and instruct that holder to tender on your behalf and comply with the instructions in this prospectus.
Acceptance of the Outstanding Notes and Delivery of the Exchange Notes	If the conditions described under “The Exchange Offer—Conditions” are satisfied, we will accept for exchange any and all outstanding notes that are properly tendered before 5:00 p.m., New York City time, on the expiration date.
Effect of Not Tendering	Any of the outstanding notes that are not tendered and any of the outstanding notes that are tendered but not accepted will remain subject to restrictions on transfer. Since the outstanding notes have not been registered under the federal securities laws, their transfer will be restricted absent registration or the availability of an exemption from registration. Upon completion of the exchange offer, we will have no further obligation, except under limited circumstances, to provide for registration of the outstanding notes under the federal securities laws. In addition, upon completion of the exchange offer, there may be no market for the outstanding notes that are not tendered for exchange notes, and you may have difficulty selling them.
Fees and Expenses	We will bear expenses related to the exchange offer. Please refer to the section in this prospectus entitled “Exchange Offer—Fees and Expenses.”



United States Federal Income Tax Considerations	We believe the exchange of outstanding notes for exchange notes will not be a taxable exchange for United States federal income tax purposes. See “Certain Material United States Federal Income Tax Considerations” for a discussion of certain of the material United States federal income tax considerations in connection with the exchange of the outstanding notes for the exchange notes. We urge you to consider before tendering the outstanding notes in the exchange offer.
Exchange Agent	Citibank, N.A. is serving as exchange agent for the exchange offer. The address for the exchange agent is listed under “The Exchange Offer—Exchange Agent.”

The Exchange Notes

The form and terms of the exchange notes to be issued in the exchange offer are the same as the form and terms of the outstanding notes except that the exchange notes will be registered under the Securities Act and, accordingly,


•	will not contain certain restrictions with respect to their transfer;


•	will not be subject to provisions relating to additional interest;


•	will bear a different CUSIP or ISIN number from the outstanding notes; and


•	will not entitle the holders to registration rights.

The exchange notes issued in the exchange offer will evidence the same debt as the outstanding notes, and both the outstanding notes and the exchange notes will be governed by the same indenture. We define certain capitalized terms used in this summary in the “Description of the Exchange Notes—Certain Definitions” section of this prospectus. The summary below describes the principal terms of the exchange notes. Certain of the terms and conditions described below are subject to important limitations and exceptions. The “Description of the Exchange Notes” section of this prospectus contains more detailed descriptions of the terms and conditions of the exchange notes.



Issuer	Magnum Hunter Resources Corporation, a Delaware corporation.
Notes offered	$600,000,000 aggregate principal amount of 9.750% senior notes due 2020.
Interest	9.750% per year (calculated using a 360-day year).
Interest payment dates	Each May 15 and November 15, with the next payment being due on November 15, 2013, for the outstanding notes or the exchange notes, as applicable.
Maturity date	May 15, 2020.
Ranking	The exchange notes will be our general unsecured senior obligations. Accordingly, they will 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, 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.



	As of September 30, 2013, the issuer and the guarantors had approximately $710.0 million of total indebtedness. As of September 30, 2013, we had $90.0 million of borrowings and $7.2 million in letters of credit under the Second Amended and Restated Credit Agreement, dated as of April 13, 2011, among the issuer, the Bank of Montreal, as Administrative Agent, and the various other financial institutions party thereto, as amended or otherwise modified from time to time, which matures on April 13, 2016. We refer to this facility as our MHR Senior Revolving Credit Facility. Our MHR Senior Revolving Credit Facility provides for an asset-based, senior secured revolving credit facility and, consequently, will rank effectively senior to the exchange notes to the extent of the value of the assets securing such indebtedness.
Guarantees	The exchange notes will be jointly and severally guaranteed by all of our existing and future direct or indirect domestic subsidiaries, and under limited circumstances certain foreign subsidiaries, that guarantee obligations under our MHR Senior Revolving Credit Facility. In the future, the guarantees may be released or terminated under certain circumstances. See “Description of the Exchange Notes—Note Guarantees.” Each guarantee will rank: • 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, LLC 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.
Optional redemption	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 notes with the net cash proceeds of certain equity offerings at the redemption price set forth under “Description of the Exchange Notes—Optional Redemption” if at least 65% of the aggregate principal amount of the notes issued under the indenture (excluding exchange 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 set forth under “Description of the Exchange Notes—Optional Redemption.” On and after May 15, 2016 we may redeem the notes, in whole or in part, at the redemption prices set forth under “Description of the Exchange Notes—Optional Redemption.”



Change of Control	If we experience certain change of control events, each holder of our notes may require us to repurchase all or a portion of our notes for cash at a price equal to 101% of the aggregate principal amount of such notes, plus any accrued and unpaid interest up to, but not including, the date of repurchase. See “Description of the Exchange Notes—Repurchase at the Option of the Holders.”
Certain Covenants	The indenture governing the 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 important exceptions and qualifications as described under “Description of the Exchange Notes—Certain Covenants.”
Trustee	Wilmington Trust, National Association
Exchange Agent	Citibank, N.A.
Absence of Established Market for the Exchange Notes	The exchange notes will be new securities for which there is currently no market. Although the initial purchasers have informed us that they intend to make a market in the exchange notes, they are not obligated to do so and may discontinue market-making activities at any time without notice. We do not intend to apply for a listing of the exchange notes on any securities exchange or an automated dealer quotation system. Accordingly, we cannot assure you that a liquid market for the exchange notes will develop or be maintained.
Use of Proceeds	We will not receive any cash proceeds from the exchange offer.
Risk Factors	You should carefully consider all of the information set forth in this prospectus and, in particular, the information under the heading “Risk Factors” beginning on page 8, in evaluating an investment in the exchange notes and participation in the exchange offer.

RISK FACTORS

You should carefully consider the risks described below and all of the information contained in this prospectus before deciding whether to participate in the exchange offer. We believe these are the material risks currently facing our business. Our business, financial condition, results of operations and cash flow could be materially adversely affected by these risks. You should carefully consider the factors described below in addition to the remainder of this prospectus before tendering your outstanding notes.

Risks Related to the Exchange Offer

You may be required to deliver a prospectus and comply with other requirements in connection with any resale of the exchange notes. We may be unable to provide a current prospectus, however, due to our inability to incorporate by reference.

If you tender your outstanding notes for the purpose of participating in a distribution of the exchange notes, you will be required to comply with the registration and prospectus delivery requirements of the Securities Act in connection with any resale of the exchange notes. In addition, if you are a broker-dealer that receives exchange notes for your own account in exchange for outstanding notes that you acquired as a result of market-making activities or any other trading activities, you may be a statutory underwriter and you will be required to acknowledge that you will deliver a prospectus in connection with any resale of such exchange notes.The registration rights agreements relating to our notes require that, for a certain period of time after the completion of the exchange offer, we use commercially reasonable efforts to provide a current prospectus so you can satisfy your prospectus delivery obligation under the Securities Act, if applicable. Until we have timely filed all our required Exchange Act reports with the SEC for a period of twelve months (which period we expect to expire in August 2014), we will be ineligible to use Form S-3. Accordingly, we will be unable to incorporate by reference into the registration statement of which this prospectus is a part until such time. As a result, it is unlikely the Company will be able to provide you with a current prospectus for the full period specified in the registration rights agreements.

If you do not properly tender or you cannot tender your outstanding notes, your ability to transfer the outstanding notes will be adversely affected.

We will issue exchange notes only in exchange for outstanding notes that are timely and properly tendered to the exchange agent. Therefore, you should allow sufficient time to ensure timely delivery of the outstanding notes and you should carefully follow the instructions on how to tender your outstanding notes. Neither we nor the exchange agent is required to tell you of any defects or irregularities with respect to your tender of the outstanding notes. If you do not tender your outstanding notes or if we do not accept your outstanding notes because you did not tender your outstanding notes properly, then, after we consummate the exchange offer, you will continue to hold outstanding notes that are subject to the existing transfer restrictions.

Risks Related to the Exchange Notes and the Related Guarantees

Our substantial indebtedness could have a material adverse effect on our financial condition and prevent us from fulfilling our obligations under the notes.

Our substantial level of indebtedness increases the risk that we may be unable to generate sufficient cash to pay amounts due in respect to our indebtedness. As of September 30, 2013, we had $760 million of total debt outstanding (including the Eureka Pipeline credit facilities (as defined below) and the $600 million of outstanding notes). Subject to the limits contained in our credit facilities and the indenture that governs the notes, we may be able to incur additional debt from time to time to finance working capital, capital expenditures, investments or acquisitions, or for other purposes. If we do so, the risks related to our business associated with our high level of debt could intensify. Specifically, our high level of debt could have important consequences to the holders of the exchange notes, including the following:


•	making it more difficult for us to satisfy our obligations with respect to the exchange notes and our other debt;


•	requiring us to dedicate a substantial portion of our cash flow from operations to debt service payments on our and our subsidiaries’ debt, which reduces the funds available for working capital, capital expenditures, acquisitions and other general corporate purposes;


•	requiring us to comply with restrictive covenants in our credit facilities and the indenture that governs the notes, which limit the manner in which we conduct our business;


•	limiting our flexibility in planning for, or reacting to, changes in the industry in which we operate;


•	placing us at a competitive disadvantage compared to any of our less leveraged competitors;


•	increasing our vulnerability to both general and industry‑specific adverse economic conditions; and


•	limiting our ability to obtain additional debt or equity financing to fund future working capital, capital expenditures, acquisitions or other general corporate requirements and increasing our cost of borrowing.

Our wholly-owned subsidiary, Eureka Pipeline is party to two credit facilities: (i) a revolving credit facility in the aggregate principal amount of up to $100 million secured by a first lien on the assets of Eureka Pipeline with an initial committed amount of $25 million; and (ii) a $50 million term loan secured by a second lien on such assets, of which $50.0 million is currently outstanding. Availability under the revolving credit facility is subject to satisfaction of certain financial covenants that are tested on a quarterly basis. As of September 30, 2013, the revolving credit facility was not available, because of certain financial covenants not yet met. We refer to the revolving credit facility and the term loan as the Eureka Pipeline credit facilities.

We may not be able to generate sufficient cash to service all of our indebtedness, including the exchange notes, and may be forced to take other actions to satisfy our obligations under our indebtedness, which may not be successful.

Our net interest expense for the six months ended June 30, 2013, was approximately $37.6 million. Our ability to make scheduled payments on or to refinance our debt obligations depends on our financial and operating performance, which is subject to prevailing economic and competitive conditions and to certain financial, business and other factors beyond our control. We cannot assure you that we will maintain a level of cash flows from operating activities sufficient to permit us to pay the principal, premium, if any, and interest on our indebtedness.

If our cash flows and capital resources are insufficient to fund our debt service obligations, we may be forced to reduce or delay capital expenditures, sell assets or operations, seek additional capital or restructure or refinance our indebtedness, including the exchange notes. We cannot assure you that we would be able to take any of these actions, that these actions would be successful and permit us to meet our scheduled debt service obligations or that these actions would be permitted under the terms of our existing or future debt agreements, including our MHR Senior Revolving Credit Facility, the Eureka Pipeline credit facilities and the indenture that governs the notes. In the absence of such operating results and resources, we could face substantial liquidity problems and might be required to dispose of material assets or operations to meet our debt service and other obligations. Our credit facilities and the indenture that governs the notes restrict our ability to dispose of assets and use the proceeds from the disposition. We may not be able to consummate those dispositions or to obtain the proceeds which we could realize from them and these proceeds may not be adequate to meet any debt service obligations then due. See “Description of the Exchange Notes.”

If we cannot make scheduled payments on our debt, we will be in default and, as a result:


•	our debt holders could declare all outstanding principal and interest to be due and payable;


•	the lenders under our credit facilities could terminate their commitments to lend us money and foreclose against the assets securing our borrowings from them; and


•	we could be forced into bankruptcy or liquidation, which could result in holders of exchange notes losing their investment in the exchange notes.

Despite our indebtedness levels, we and our subsidiaries may still be able to incur substantially more debt, including secured debt. This could further increase the risks associated with our leverage.

We and our subsidiaries may be able to incur substantial additional indebtedness in the future. The terms of our MHR Senior Revolving Credit Facility, the Eureka Pipeline credit facilities and the indenture that governs the notes do not fully prohibit us or our subsidiaries from doing so. To the extent that we incur additional indebtedness or such other obligations, the risks associated with our substantial indebtedness described above, including our possible inability to service our debt, will increase. As of September 30, 2013, we had approximately $167.8 million available for additional borrowing under our MHR Senior Revolving Credit Facility.

Restrictive covenants under our credit facilities and the indenture that governs the notes may adversely affect our operations and liquidity.

Our MHR Senior Revolving Credit Facility, the Eureka Pipeline credit facilities and the indenture that governs the notes, contain, and any agreements governing any future indebtedness we incur may contain, various covenants that limit our ability to, among other things:


•	incur or guarantee additional debt;


•	incur debt that is junior to senior indebtedness and senior to our existing senior subordinated notes;


•	pay dividends or make distributions to holders of our capital stock or to make certain other restricted payments or investments;


•	repurchase or redeem capital stock;


•	make loans, capital expenditures or investments or acquisitions;


•	incur restrictions on the ability of certain of our subsidiaries to pay dividends or to make other payments to us;


•	enter into transactions with affiliates;


•	create liens;


•	merge or consolidate with other companies or transfer all or substantially all of our assets;


•	transfer or sell assets, including capital stock of subsidiaries; and


•	prepay, redeem or repurchase debt that is junior in right of payment to the exchange notes.

As a result of these covenants, we are limited in the manner in which we conduct our business and we may be unable to engage in favorable business activities or finance future operations or capital needs. Our MHR Senior Revolving Credit Facility also requires us to satisfy certain financial covenants, including maintaining:

(1) a ratio of consolidated current assets to consolidated current liabilities (as defined) of not less than1.0 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 (i) 2.00 to 1.00 for the fiscal quarters ended June 30, 2013 and ending September 30, 2013, (ii) 2.25 to 1.00 for the fiscal quarter ending December 31, 2013 and (iii) 2.50 to 1.00 for the fiscal quarter ending March 31, 2014 and each fiscal quarter ending thereafter;

(3) commencing with the fiscal quarter ending June 30, 2014, a ratio of total debt to EBITDAX of not more than (i) 4.50 to 1.0 for the fiscal quarters ending June 30, 2014 and September 30, 2014 and (ii) 4.25 to 1.00 for the fiscal quarter ending December 31, 2014 and for each fiscal quarter ending thereafter, and

(4) commencing with the fiscal quarter ended June 30, 2013 through and including the fiscal quarter ending March 31, 2014, a ratio of senior debt to EBITDAX not more than 2.00 to 1.00.

A breach of any of these covenants or any of the other restrictive covenants would result in a default under such credit facility. Upon the occurrence of an event of default thereunder, the lenders:


•	will not be required to lend any additional amounts to us;


•	could elect to declare all borrowings outstanding thereunder, together with accrued and unpaid interest and fees, to be due and payable; or


•	could require us to apply all of our available cash to repay these borrowings;

any of which could result in an event of default under the exchange notes.

If we were unable to repay those amounts, the lenders under such credit facility could proceed against the collateral granted to them to secure our borrowings thereunder. Further, any event of default under the MHR Senior Revolving Credit Facility may result in a cross default under the indenture governing the notes. Also, any acceleration of the indebtedness under the MHR Senior Revolving Credit Facility will result in a cross default under the Eureka Pipeline credit facilities and will result in a cross default of the indenture. We have pledged a significant portion of our assets as collateral under our credit facilities. If the lenders under any of our credit facilities accelerate the repayment of borrowings, we cannot assure you that we will have sufficient assets to repay such credit facilities and the notes, or borrow sufficient funds to refinance such indebtedness. Even if we were able to obtain new financing, it may not be on commercially reasonable terms, or terms that are acceptable to us.

Our ability to borrow under our MHR Senior Revolving Credit Facility is limited by a borrowing base. Our borrowing base in effect as of September 30, 2013 was $265.0 million.

The exchange notes will be unsecured and will be effectively subordinated to our and the guarantors’ secured debt and indebtedness of non-guarantor subsidiaries.

Our obligations under the exchange notes and the guarantors’ obligations under the guarantees of the exchange notes will not be secured by any of our or our subsidiaries’ assets. Borrowings under our MHR Senior Revolving Credit Facility are secured by a security interest in certain of our assets and the assets of our restricted subsidiaries and the assets of the guarantors. In addition, the indenture governing the notes permits us and our subsidiaries to incur additional secured debt. As a result, the exchange notes and the related guarantees will be effectively subordinated to all of our and the guarantors’ secured debt and other obligations to the extent of the value of the assets securing such obligations. As of September 30, 2013, we had approximately $167.8 million available for additional borrowing under our MHR Senior Revolving Credit Facility. If we and the guarantors were to become insolvent or otherwise fail to make payments on the notes, holders of our and the guarantors’ secured obligations would be paid first and would receive payments from the assets securing such obligations before the holders of the exchange notes would receive any payments. You may therefore not be fully repaid in the event we become insolvent or otherwise fail to make payments on the exchange notes.

The exchange notes will not be guaranteed by all of our subsidiaries. For example, Eureka Holdings, Eureka Pipeline, TransTex Hunter, our current foreign subsidiaries and certain immaterial subsidiaries are not required to guarantee the exchange notes. Accordingly, claims of holders of the notes are structurally subordinate to the claims of creditors of these non‑guarantor subsidiaries, including trade creditors. All obligations of our non‑guarantor subsidiaries will have to be satisfied before any of the assets of such subsidiaries would be available for distribution, upon a liquidation or otherwise, to us or a guarantor of the exchange notes.

Variable rate indebtedness subjects us to interest rate risk, which could cause our debt service obligations to increase significantly.

Our MHR Senior Revolving Credit Facility is at a variable rate of interest and exposes us to interest rate risk. As of September 30, 2013, we had $90.0 million of variable rate debt outstanding under our MHR Senior Revolving Credit Facility and letters of credit of $7.2 million. If interest rates increase, our debt service obligations on the variable rate indebtedness would increase even though the amount borrowed remained the same, and our net income would decrease.

The exchange notes are structurally subordinated to all indebtedness of our existing or future subsidiaries that are not or do not become guarantors of the exchange notes.

Holders of the exchange notes will not have any claim as a creditor against any of our existing subsidiaries that are not guarantors of the exchange notes or against any of our future subsidiaries that do not become guarantors of the exchange notes. Indebtedness and other liabilities, including trade payables of those subsidiaries will be structurally senior to claims of holders of the exchange notes against those subsidiaries. As of June 30, 2013, our non‑guarantor subsidiaries had approximately $156.1 million of total liabilities, all of which were effectively senior to the exchange notes.

With limited exceptions, the exchange notes are not guaranteed by any of our domestic subsidiaries that are not guarantors under the MHR Senior Revolving Credit Facility. The exchange notes are also not guaranteed by any of our foreign subsidiaries and, with limited exceptions, will not be guaranteed by any future foreign subsidiaries. Our non‑guarantor subsidiaries are separate and distinct legal entities and have no obligation, contingent or otherwise, to pay any amounts due under the exchange notes, or to make any funds available therefor, whether by dividends, loans, distributions or other payments.

In the event of a bankruptcy, liquidation, reorganization or other winding up of these non‑guarantor subsidiaries or any future subsidiary that is not a guarantor of the exchange notes, these non‑guarantor subsidiaries will pay the holders of their debts, holders of preferred equity interests and their trade creditors before they will be able to distribute any of their assets to us (except to the extent we have a claim as a creditor of such non‑guarantor subsidiary). Any right that we or the subsidiary guarantors have to receive any assets of any non-guarantor subsidiaries upon the bankruptcy, liquidation, reorganization or other winding up of those subsidiaries, and the consequent rights of holders of exchange notes to realize proceeds from the sale of any of those subsidiaries’ assets, will be effectively subordinated to the claims of those subsidiaries’ creditors, including trade creditors and holders of preferred equity interests of those subsidiaries.

As of and for the six months ended June 30, 2013, our non-guarantor subsidiaries represented 28.8% of our total assets, and 22.1% of our revenues, respectively.

In addition, the indenture that governs the notes, subject to some limitations, permits these subsidiaries to incur additional indebtedness and does not contain any limitation on the amount of certain other liabilities, such as trade payables, that may be incurred by these subsidiaries.

Our ability to service our debt and meet our cash requirements depends on many factors, some of which are beyond our control.

Our ability to satisfy our obligations and meet our cash requirements for the foreseeable future will depend on our future operating performance and financial results, which will be subject, in part, to factors beyond our control, including interest rates and general economic, financial and business conditions. See “Risks Related to Our Business.” If we are unable to generate sufficient cash flow to service our debt, we may be required to:


•	refinance all or a portion of our debt, including the exchange notes;


•	obtain additional financing;


•	sell some of our assets or operations;


•	reduce or delay capital expenditures and/or acquisitions; or


•	revise or delay our strategic plan.

If we are required to take any of these actions, it could have a material adverse effect on our business, financial condition and results of operations. In addition, we cannot assure you that we would be able to take any of these actions, that these actions would enable us to continue to satisfy our capital requirements or that these actions would be permitted under the terms of our

MHR Senior Revolving Credit Facility, the Eureka Pipeline credit facilities and the indenture that governs the notes. In addition, our credit facilities and the indenture that governs the notes, restrict our ability to sell assets and to use the proceeds from the sales. We may not be able to sell assets quickly enough or for sufficient amounts to enable us to meet our obligations, including our obligations on the exchange notes. Furthermore, the equity sponsors for our Eureka Holdings operations have no obligation to provide us with debt or equity financing. Therefore, it may be difficult for us to make required payments on the exchange notes in the event of an acceleration of the maturity of the exchange notes.

Our ability to make payments on the exchange notes depends on our ability to receive dividends and other distributions from our subsidiaries.

Our principal assets are the equity interests that we hold in our operating subsidiaries. As a result, we are dependent on dividends and other distributions from our subsidiaries to generate the funds necessary to meet our financial obligations, including the payment of principal and interest on our outstanding debt. Our subsidiaries may not generate sufficient cash from operations to enable us to make principal and interest payments on our indebtedness, including the exchange notes. In addition, any payment of dividends, distributions, loans or advances to us by our subsidiaries could be subject to restrictions on dividends or, in the case of foreign subsidiaries, restrictions on repatriation of earnings under applicable local law and monetary transfer restrictions in the jurisdictions in which our subsidiaries operate. In addition, payments to us by our subsidiaries will be contingent upon our subsidiaries’ earnings. Our subsidiaries are permitted under the terms of our indebtedness to incur additional indebtedness that may restrict payments from those subsidiaries to us. We cannot assure you that agreements governing current and future indebtedness of our subsidiaries will permit those subsidiaries to provide us with sufficient cash to fund payments on the exchange notes when due. Eureka Pipeline and its direct and indirect subsidiaries are restricted under the Eureka Pipeline credit facilities (with certain exceptions) from making dividends and distributions to us. In addition, pursuant to the documents governing the investment by Ridgeline Midstream Holdings, LLC, or Ridgeline, an affiliate of ArcLight Capital Partners, LLC, or ArcLight, (discussed below in “Risks Related to Our Business"— 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 and Eureka Pipeline”), in the event of a change of control of Magnum Hunter, subject to certain conditions, Ridgeline has the right to purchase from Eureka Holdings additional preferred units representing, together with all other units then owned by Ridgeline, up to 51% of the then issued and outstanding common units of Eureka Holdings, determined on an as-converted basis.

Our subsidiaries are legally distinct from us and, except for our existing and future subsidiaries that will be guarantors of the exchange notes, have no obligation, contingent or otherwise, to pay amounts due on our debt or to make funds available to us for such payment.

If we default on our obligations to pay our indebtedness, we may not be able to make payments on the exchange notes.

Any default under the agreements governing our indebtedness, including a default under our MHR Senior Revolving Credit Facility that is not waived by the required lenders, and the remedies sought by the holders of such indebtedness, could make us unable to pay principal, premium, if any, and interest on the exchange notes and substantially decrease the value of the exchange notes. If we are unable to generate sufficient cash flow and are otherwise unable to obtain funds necessary to meet required payments of principal, premium, if any, and interest on our indebtedness, or if we otherwise fail to comply with the various covenants, including financial and operating covenants, in the instruments governing our indebtedness (including the indenture that governs the notes), we could be in default under the terms of the agreements governing such indebtedness, including our MHR Senior Revolving Credit Facility and the indenture that governs the notes. In the event of such default, the holders of such indebtedness could elect to declare all the funds borrowed thereunder to be due and payable, together with accrued and unpaid interest, the lenders under our MHR Senior Revolving Credit Facility could elect to terminate their commitments thereunder and cease making further loans and lenders under our credit facilities and holders of our senior secured notes could institute foreclosure proceedings against our assets and we could be forced into bankruptcy or liquidation. If our operating performance declines, we may in the future need to obtain waivers from the required lenders under our MHR Senior Revolving Credit Facility to avoid being in default. If we breach our covenants under our credit facilities and seek a waiver, we may not be able to obtain a waiver from the required lenders. If this occurs, we would be in default, the lenders could exercise their rights, as described above, and we could be forced into bankruptcy or liquidation. See “Description of the Exchange Notes.”

We may be unable to purchase the exchange notes upon a change of control which would result in a default under the indenture that governs the notes and would adversely affect our business.

Upon a change of control, as defined in the indenture that governs the notes, we are required to offer to purchase all of the exchange notes then outstanding for cash at 101% of the principal amount thereof, together with accrued and unpaid interest and additional interest, if any. If a change of control occurs under the indenture that governs the notes, we may not have sufficient funds to pay the change of control purchase price, and we may be required to secure third party financing to do so. We may not be able to obtain this financing on commercially reasonable terms, or on terms acceptable to us, or at all. Further, we may be contractually restricted under the terms of our MHR Senior Revolving Credit Facility from repurchasing all of the

exchange notes tendered by holders of the exchange notes upon a change of control. Accordingly, we may not be able to satisfy our obligations to purchase the exchange notes unless we are able to refinance or obtain waivers under our MHR Senior Revolving Credit Facility. Our failure to repurchase the exchange notes upon a change of control would cause a default under the indenture that governs the notes and a cross‑default under our MHR Senior Revolving Credit Facility. Our MHR Senior Revolving Credit Facility, the Eureka Pipeline credit facilities and the indenture that governs the notes also provide that a change of control, as defined in such agreements, will be a default that permits lenders to accelerate the maturity of borrowings thereunder and, in the case of our MHR Senior Revolving Credit Facility, if such debt is not paid, to enforce security interests in the collateral securing such debt, thereby limiting our ability to raise cash to purchase the exchange notes. In addition, pursuant to the documents governing the Ridgeline investment (discussed below in “Risks Related to Our Business" —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 and Eureka Pipeline”), in the event of a change of control of Magnum Hunter, subject to certain conditions, Ridgeline has the right to purchase from Eureka Holdings additional preferred units representing, together with all other units then owned by Ridgeline, up to 51% of the then issued and outstanding common units of Eureka Holdings, determined on an as-converted basis.

The change of control provisions in the indenture that governs the notes may not protect holders of the exchange notes in the event we consummate a highly leveraged transaction, reorganization, restructuring, merger or other similar transaction, unless such transaction constitutes a change of control under the indenture that governs the notes. Such a transaction may not involve a change in voting power or beneficial ownership or, even if it does, may not involve a change of the magnitude required under the definition of change of control in the indenture that governs the notes to trigger our obligation to repurchase the exchange notes. Except as otherwise described above, the indenture that governs the notes does not contain provisions that permit the holders of the exchange notes to require us to repurchase or redeem the exchange notes in the event of a takeover, recapitalization or similar transaction. If an event occurs that does not constitute a “Change of Control” as defined in the indenture that governs the notes, we will not be required to make an offer to repurchase the exchange notes and holders may be required to continue to hold notes despite the event. See “Description of the Exchange Notes—Repurchase at the Option of Holders.”

Federal and state statutes allow courts, under specific circumstances, to void notes and adversely affect the validity and enforceability of the guarantees and require noteholders to return payments received.

The issuance of, and payments made under, the exchange notes and the guarantees may be subject to review under federal and state fraudulent transfer and conveyance statutes. While the relevant laws may vary from state to state, generally under such laws the incurrence of an obligation (such as under the exchange notes or related guarantees) or the making of a payment or other transfer will be a fraudulent conveyance if (1) we or any of our guarantors, as applicable, incurred such obligation or made such payment with the intent of hindering, delaying or defrauding creditors or (2) we or any of our guarantors, as applicable, received less than reasonably equivalent value or fair consideration in return for incurring such obligation or making such payment and, in the case of (2) only, one of the following is also true:


•	we or the applicable guarantor were insolvent at the time of or rendered insolvent by reason of the incurrence of the obligation or the making of such payment; or


•	the incurrence of the obligation or the making of such payment of the consideration left us or the applicable guarantor with an unreasonably small amount of capital to carry on our or its business; or


•	we or the applicable guarantor intended to, or believed that we or it would, incur debts beyond our or its ability to pay them as they mature.

If a court were to find that the issuance of the exchange notes or related guarantees, or a payment made under the exchange notes or related guarantees, was a fraudulent conveyance, the court could void the payment obligations under the exchange notes or such related guarantees or subordinate the exchange notes or such guarantees to presently existing and future indebtedness of ours or any such guarantor, and require the holders of the exchange notes to repay particular amounts or any amounts received with respect to the exchange notes or such related guarantees. In the event of a finding that a fraudulent conveyance occurred, you may not receive any repayment on the exchange notes. Further, the voiding of the exchange notes or the related guarantees could result in an event of default with respect to our other debt and that of our guarantors that could result in acceleration of such debt.

The measures of insolvency for purposes of these fraudulent transfer laws will vary depending upon the law applied in any proceeding to determine whether a fraudulent transfer has occurred. In general, however, a court would consider an issuer or a guarantor insolvent if:


•	the sum of its debts, including contingent and unliquidated liabilities, was greater than all of its property, at a fair valuation;


•	the present fair saleable value of its assets was less than the amount that would be required to pay its probable liability on its existing debts, including contingent unliquidated liabilities, as they become absolute and matured; or


•	it could not pay its debts as they became due.

We cannot be certain as to the standards a court would use to determine whether or not we or the guarantors were solvent at the relevant time, or regardless of the standard that a court uses, that the exchange notes and the related guarantees would not be subordinated to our or any guarantor’s other debt.

If the guarantees were legally challenged, any guarantee could also be subject to the claim that, since the guarantee was incurred for our benefit, and only indirectly for the benefit of the guarantor, the obligations of the applicable guarantor were incurred for less than reasonably equivalent value or fair consideration. A court could thus void the obligations under the guarantees, subordinate them to the applicable guarantor’s other debt or take other action detrimental to the holders of the exchange notes.

Each guarantee contains a provision intended to limit the guarantor’s liability to the maximum amount that it could incur without causing the incurrence of obligations under its guarantee to be a fraudulent transfer. This provision may not be effective to protect the guarantees from being voided under fraudulent transfer law, or may reduce or eliminate the guarantor’s obligation to an amount that effectively makes the guarantee worthless. Although subsequently overturned on other grounds, a recent Florida bankruptcy court decision found that this kind of provision was ineffective to protect the guarantees.

Any rating downgrade for the notes may cause the price of the notes to fall.

We received credit ratings from certain rating services in connection with the offering of the original notes and the add-on notes in May 2012 and December 2012, respectively. In the event a rating service were to lower its rating on the exchange notes below the rating initially assigned to the notes or otherwise announce its intention to put the notes on credit watch, the price of the notes could decline.

On June 28, 2013, Standard & Poor’s, one of the two rating agencies for the notes, ranked the notes CCC, which rating remained CCC on September 30, 2013.

The trading prices for the exchange notes will be directly affected by many factors, including our credit rating.

Credit rating agencies continually revise their ratings for companies they follow or discontinue rating companies, including us. Any ratings downgrade or decisions by a credit rating agency to discontinue rating us could adversely affect the trading price of the exchange notes, or the trading market for the exchange notes, to the extent a trading market for the exchange notes develops. The condition of the financial and credit markets and prevailing interest rates have fluctuated in the past and are likely to fluctuate in the future and any fluctuation may impact the trading price of the exchange notes.

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 June 30, 2013, we had incurred an accumulated deficit of $213.9 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 required Exchange Act filings with SEC in a timely manner 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 any 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.

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 our capital 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 the "Controls and Procedures" section in this prospectus, 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 Financial 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 within the time frame required by the SEC (i) our annual report on Form 10-K for the year ended December 31, 2012 (our “2012 Form 10-K”), (ii) our quarterly report on Form 10-Q for the quarter ended March 31, 2013 (our “First Quarter 2013 Form 10-Q”) or (iii) certain pro forma financial information regarding our sale of Eagle Ford Hunter, Inc. to Penn Virginia (as part of the Form 8-K we filed with the SEC on April 30, 2013 reporting the sale). 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 became current with our SEC reporting obligations on July 12, 2013, upon the filing of a Form 8-K/A containing the pro forma financial information regarding our sale of Eagle Ford Hunter, Inc. to Penn Virginia. Until twelve months after the date on which we became 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 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 “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 “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 “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.

Due to previously-disclosed delays in connection with the audit of our consolidated financial statements for the fiscal year ended December 31, 2012, we did not complete an exchange offer for the Senior Notes by May 16, 2013. 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 failure to timely file certain reports with the SEC may be construed as a default under the indenture governing our notes and certain other credit and other agreements, which may have a material adverse effect on our business, financial condition and liquidity.

The indenture governing our notes and each of our credit facilities, which include our MHR Senior Revolving Credit Facility and Eureka Pipelines revolver and term loan facilities, require us to file with the SEC and make available to certain parties certain reports and documents under the Exchange Act within specified time periods after their respective SEC filing deadlines. As previously disclosed in our SEC filings, we did not timely file with the SEC (i) our 2012 Form 10-K, (ii) our First Quarter 2013 Form 10-Q or (iii) certain pro forma financial information regarding our sale of Eagle Ford Hunter, Inc. to Penn Virginia as part of the Form 8-K we filed with the SEC on April 30, 2013 reporting the sale. We have made each of these filings and are now current in our SEC reporting obligations.

The failure to timely file certain of these reports with the SEC constituted “defaults” under the Notes indenture, which triggered certain consequences. Since we have now filed such reports with the SEC, we do not believe that there now exists any “default” or “event of default” under the Notes indenture that is now continuing. If we were unable to cure any such default, such default would have constituted an “event of default” under our indenture, which would have entitled the holders of our notes to exercise certain rights and remedies, including accelerating our debt under the outstanding notes. Additionally, under certain circumstances an event of default under our credit facilities would trigger a cross-default under our indenture.

Our First Quarter 2013 Form 10-Q, our 2012 Form 10-K and a Form 8-K/A with certain pro forma financial information regarding our sale of Eagle Ford Hunter were filed within the extended time deadline provided by the lenders under each of our credit facilities. Such lenders also agreed to waive any cross-defaults that might result from any “default” under our indenture due to our failure to file these reports with the SEC in compliance with the requirements under the indenture. However, if we fail to timely file certain reports with the SEC in the future, such failure may 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.

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.

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.

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:


•	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 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.

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 459 full-time employees as of September 30, 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 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 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 September 30, 2013, our total outstanding indebtedness was approximately $760.0 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 prospectus.

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.

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 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 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.

During the six months ended June 30, 2013, the Company recognized $29.5 million in leasehold impairment expense related to leases in the Williston Basin region that are expected to expire during the remainder of 2013 that we do not plan to develop. We also recognized leasehold abandonment expense of $4.7 million in related leases that expired undrilled in the Williston Basin region during the six months ended June 30, 2013. Additionally, we recorded proved impairments of $16.0 million for the six months ended June 30, 2013, due to changes in production estimates and lease operating costs indicating potential impairment of our Williston and Appalachian Basin proved properties, and the resulting provision for reduction to the carrying value of these properties to their estimated fair values.

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.

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 prospectus.

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.

to $200 million of preferred units of Eureka Holdings. As of September 30, 2013, Eureka Holdings had sold preferred units to Ridgeline for an aggregate purchase price of $179.8 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 $8.0 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 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 ($20.0 million of which had been paid as of September 30, 2013) 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, Magnum Hunter Production, Inc., NGAS Hunter, LLC, Williston Hunter Canada, Inc., Williston Hunter, Inc., Williston Hunter ND, LLC, Bakken Hunter, LLC, Shale 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.

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 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.

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.

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.

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 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.

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 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.

THE EXCHANGE OFFER

Purpose and Effect of the Exchange Offer

We issued $600 million aggregate principal amount of the outstanding notes, consisting of (i) $450 million aggregate principal amount of the original notes to the original initial purchasers on May 16, 2012, and (ii) $150 million aggregate principal amount of the add-on notes to the add-on initial purchasers on December 18, 2012, in transactions not registered under the Securities Act in reliance on exemptions from registration. After each issuance, the initial purchasers sold the outstanding notes to qualified institutional buyers and certain non-U.S. investors in reliance on Rule 144A and Regulation S under the Securities Act. Because the outstanding notes were sold pursuant to exemptions from registration, they are subject to transfer restrictions.

In connection with the issuances of the outstanding notes, we agreed with the initial purchasers that we would:


•	file a registration statement for the exchange offer (of which this prospectus is a part) to exchange the outstanding notes for publicly registered notes with identical terms;


•	use our commercially reasonable efforts to cause the registration statement to become effective under the Securities Act;


•	use our commercially reasonable efforts to keep the registration statement effective for 30 days (or longer, if required by applicable law) after the date notice of the exchange offer is mailed to holders of the outstanding notes; and


•	use our commercially reasonable efforts to consummate the exchange offer not later than May 15, 2013.

We have not yet commenced an exchange offer for the outstanding notes. Accordingly, we have been required to pay additional interest on the outstanding notes since May 16, 2013.

Under existing interpretations of the SEC contained in several no-action letters to third parties, the exchange notes and the related guarantees will be freely transferable by holders thereof (other than our affiliates) without further registration under the Securities Act; provided, however, that each holder that wishes to exchange its outstanding notes for exchange notes will be required to represent (i) that any exchange notes to be received by it will be acquired in the ordinary course of its business, (ii) that, at the time of the commencement of the exchange offer it had, and at the time of exchange it had, no arrangement or understanding with any person to participate in the distribution (within the meaning of Securities Act) of the applicable exchange notes in violation of the Securities Act, (iii) that it is not an “affiliate” (as defined in Rule 405 promulgated under Securities Act) of ours, (iv) if such holder is not a broker dealer, that it is not engaged in, and does not intend to engage in, the distribution of exchange notes and (v) if such holder is a broker dealer, which we refer to as participating broker dealer, that will receive exchange notes for its own account in exchange for notes that were acquired as a result of market-making or other trading activities, that it will deliver a prospectus in connection with any resale of such exchange notes. We agreed to use commercially reasonable efforts to make available, during the period required by the Securities Act, a prospectus meeting the requirements of the Securities Act for use by participating broker dealers and other persons, if any, with similar prospectus delivery requirements for use in connection with any resale of exchange notes. Since we are not eligible to use Form S-3, however, and cannot incorporate by reference into the registration statement of which this prospectus is a part, we may be unable to provide a current prospectus. See “Risk Factors-You may be required to deliver a prospectus and comply with other requirements in connection with any resale of the exchange notes. We may be unable to provide a current prospectus, however, due to our inability to incorporate by reference.”

As a result of our failure to commence an exchange offer for the outstanding notes, we have been required to pay additional interest on the outstanding notes since May 16, 2013. From and after the completion of the exchange offer neither the newly-issued exchange notes nor any remaining outstanding notes shall be entitled to additional interest. Following the closing of the exchange offer, holders of the outstanding notes not tendered will not have any further registration rights except in limited circumstances requiring the filing of a shelf registration statement, and the outstanding notes will continue to be subject to restrictions on transfer. Accordingly, the liquidity of the market for the outstanding notes will be adversely affected.

Terms of the Exchange Offer

Upon the terms and subject to the conditions stated in this prospectus and in the letter of transmittal, we will accept all outstanding notes properly tendered and not withdrawn before 5:00 p.m., New York City time, on the expiration date. After authentication of the exchange notes by the authenticating agent, we will issue $1,000 principal amount of the exchange notes in exchange for each $1,000 principal amount of the outstanding notes accepted in the exchange offer (provided, however, that you may tender outstanding notes only in a minimum denomination of $2,000 or an integral multiple of $1,000 in excess thereof).

By tendering the outstanding notes for exchange notes in the exchange offer and signing or agreeing to be bound by the letter of transmittal, you will represent to us that:


•	you will acquire the exchange notes you receive in the exchange offer in the ordinary course of your business;


•	you have no arrangement or understanding with any person to participate in the distribution (within the meaning of Securities Act) of the applicable exchange notes in violation of the Securities Act;


•	you are not an affiliate of ours;


•	if you are not a broker-dealer, that you are not engaged in and do not intend to engage in the distribution of the exchange notes; and


•	if you are a broker-dealer that will receive exchange notes for your own account in exchange for outstanding notes that were acquired as a result of market-making or other trading activities, that you will deliver a prospectus, as required by law, in connection with any resale of those exchange notes.

Broker-dealers that are receiving exchange notes for their own account must have acquired the outstanding notes as a result of market-making or other trading activities in order to participate in the exchange offer. Each broker-dealer that receives exchange notes for its own account under the exchange offer must acknowledge that it will deliver a prospectus in connection with any resale of the exchange notes. The letter of transmittal states that, by so acknowledging and by delivering a prospectus, a broker-dealer will not be admitting that it is an “underwriter” within the meaning of the Securities Act. We will be required to allow broker-dealers to use this prospectus following the exchange offer in connection with the resale of exchange notes received in exchange for outstanding notes acquired by broker-dealers for their own account as a result of market-making or other trading activities. If required by applicable securities laws, we will, upon written request, use commercially reasonable efforts to make this prospectus available to any broker-dealer for use in connection with a resale of exchange notes. Since we are not eligible to use Form S-3 and cannot incorporate by reference into the registration statement of which this prospectus is a part, however, we may be unable to provide a current prospectus. See “Plan of Distribution” and “Risk Factors-You may be required to deliver a prospectus and comply with other requirements in connection with any resale of the exchange notes. We may be unable to provide a current prospectus, however, due to our inability to incorporate by reference.”

The exchange notes will evidence the same debt as the outstanding notes and will be issued under and entitled to the benefits of the same indenture. The form and terms of the exchange notes to be issued in the exchange offer are the same as the form and terms of the outstanding notes except that the exchange notes will be registered under the Securities Act and, accordingly,


•	will not contain certain restrictions with respect to their transfer;


•	will not be subject to provisions relating to additional interest;


•	will bear a different CUSIP or ISIN number from the outstanding notes; and


•	will not entitle the holders to registration rights.

As of the date of this prospectus, $600 million aggregate principal amount of the previously issued 9.750% Senior Notes due 2020 are outstanding. In connection with the issuance of the outstanding notes, we arranged for the outstanding notes to be issued and transferable in book-entry form through the facilities of DTC, acting as depository. The exchange notes will also be issuable and transferable in book-entry form through DTC.

This prospectus, together with the accompanying letter of transmittal, is initially being sent to all registered holders of the outstanding notes as of the close of business on October 7, 2013. We intend to conduct the exchange offer as required by the Exchange Act, and the rules and regulations of the SEC under the Exchange Act, including Rule 14e-1, to the extent applicable.

Rule 14e-1 describes unlawful tender offer practices under the Exchange Act. This rule requires us, among other things:


•	to hold our exchange offer open for 20 business days;


•	to give at least ten business days’ notice of certain changes in the terms of this offer as specified in Rule 14e-1(b); and


•	to issue a press release in the event of an extension of the exchange offer.

The exchange offer is not conditioned upon any minimum aggregate principal amount of the outstanding notes being tendered, and holders of the outstanding notes do not have any appraisal or dissenters’ rights under the Delaware General Corporation Law or under the indenture in connection with the exchange offer. We shall be considered to have accepted the outstanding notes tendered according to the procedures in this prospectus when, as and if we have given written notice of acceptance to the exchange agent. See “—Exchange Agent.” The exchange agent will act as agent for the tendering holders for the purpose of receiving exchange notes from us and delivering exchange notes to those holders.

If any tendered outstanding notes are not accepted for exchange because of an invalid tender or the occurrence of other events described in this prospectus, these unaccepted outstanding notes will be returned, at our cost, into the holder’s account at DTC according to the procedures described below, promptly after the expiration date.

Holders who tender outstanding notes in the exchange offer will not be required to pay brokerage commissions or fees or, subject to the instructions in the letter of transmittal, transfer taxes related to the exchange of the outstanding notes in the exchange offer. We will pay all charges and expenses, other than applicable taxes, in connection with the exchange offer. See “—Fees and Expenses.”

Neither we nor our board of directors makes any recommendation to holders of the outstanding notes as to whether to tender or refrain from tendering all or any portion of their outstanding notes in the exchange offer. Moreover, no one has been authorized to make any such recommendation. Holders of the outstanding notes must make their own decision whether to tender in the exchange offer and, if so, the amount of the outstanding notes to tender after reading this prospectus and the letter of transmittal and consulting with their advisors, if any, based on their own financial position and requirements.

Expiration Date; Extensions; Amendments

The term “expiration date” shall mean 5:00 p.m., New York City time, on November 7, 2013, unless we, in our sole discretion, extend the exchange offer, in which case the term “expiration date” shall mean the latest date to which the exchange offer is extended.

If any of the conditions described below under “—Conditions” has not been satisfied, we reserve the right, in our sole discretion:


•	to extend the exchange offer, or


•	to terminate the exchange offer,

by giving written notice of such extension or termination to the exchange agent, which notice will disclose the number of outstanding notes tendered as of the date of such notice in compliance with Rule 14e-1(d). Subject to the terms of the registration rights agreements, we also reserve the right to amend the terms of the exchange offer in any manner.

Any delay in acceptance, termination, extension or amendment will be followed promptly by written notice to the exchange agent and by making a public announcement. Any public announcement in the case of an extension of the exchange offer will be issued no later than 9:00 a.m., New York City time, on the next business day after the previously scheduled expiration date. If the exchange offer is amended in a manner determined by us to constitute a material change, including the waiver of a material condition, we will promptly disclose the amendment in a manner reasonably calculated to inform the holders of the amendment. We will also extend the exchange offer for a period of at least five business days, as required by applicable law, depending upon the significance of the change and the manner of disclosure to the holders, if the exchange offer would otherwise expire during that extended period.

Without limiting the manner in which we may choose to make public announcements of any delay in acceptance, termination, extension, or amendment of the exchange offer, we shall have no obligation to publish, advise, or otherwise communicate any public announcement, other than by making a timely release to Marketwire.

You are advised that we may extend the exchange offer because some of the holders of the outstanding notes do not tender on a timely basis. In order to give these noteholders the ability to participate in the exchange and to avoid the significant reduction in liquidity associated with holding an unexchanged note, we may elect to extend the exchange offer.

Procedures for Tendering

All of the outstanding notes were issued in book-entry form, and all of the outstanding notes are currently represented by global certificates held for the account of DTC.

We understand that the exchange agent will make a request promptly after the date of the prospectus to establish accounts for the outstanding notes at DTC for the purpose of facilitating the exchange offer, and subject to their establishment, any financial institution that is a participant in DTC may make book-entry delivery of the outstanding notes by causing DTC to transfer the outstanding notes into the exchange agent’s account for the exchange notes using DTC’s procedures for transfer.

In order to transfer outstanding notes held in book-entry form with DTC, the exchange agent must receive, before 5:00 p.m., New York City time, on the expiration date, at its address set forth in this prospectus,


•	a confirmation of book-entry transfer of outstanding notes into the exchange agent’s account at DTC, which is referred to in this prospectus as a “book-entry confirmation,” and:


•	a properly completed and validly executed letter of transmittal, or manually signed facsimile thereof, together with any signature guarantees and other documents required by the instructions in the letter of transmittal; or


•	an agent’s message transmitted pursuant to ATOP.

The exchange agent and DTC have confirmed that the exchange offer is eligible for ATOP. Accordingly, DTC participants may electronically transmit their acceptance of the exchange offer by causing DTC to transfer outstanding notes held in book-entry form to the exchange agent in accordance with DTC’s ATOP procedures for transfer. DTC will then send a book-entry confirmation, including an agent’s message, to the exchange agent.

The term “agent’s message” means a message transmitted by DTC, received by the exchange agent and forming part of the book-entry confirmation, which states that DTC has received an express acknowledgment from the participant in DTC tendering outstanding notes that are the subject of that book-entry confirmation that the participant has received and agrees to be bound by the terms of the letter of transmittal, and that we may enforce such agreement against such participant. If you use ATOP procedures to tender outstanding notes, you will not be required to deliver a letter of transmittal to the exchange agent, but you will be bound by its terms as if you had signed it.

There is no procedure for guaranteed late delivery of the exchange notes.

Each broker-dealer that receives exchange notes for its own account in exchange for outstanding notes, where such outstanding notes were acquired by such broker-dealer as a result of market-making activities or other trading activities, must acknowledge that it will deliver a prospectus in connection with any resale of such exchange notes. Since we are not eligible to use Form S-3 and cannot incorporate by reference into the registration statement of which this prospectus is a part, however, we may be unable to provide a current prospectus. See “Plan of Distribution” and “Risk Factors-You may be required to deliver a prospectus and comply with other requirements in connection with any resale of the exchange notes. We may be unable to provide a current prospectus, however, due to our inability to incorporate by reference.”

Acceptance of Outstanding Notes for Exchange; Issuance of Exchange Notes

Upon the terms and subject to the conditions of the exchange offer, we will accept, promptly after the expiration time, all outstanding notes properly tendered. We will issue the exchange notes promptly after acceptance of the outstanding notes. For purposes of an exchange offer, we will be deemed to have accepted properly tendered outstanding notes for exchange when, as and if we have given written notice to the exchange agent.

For each outstanding note accepted for exchange, the holder will receive an exchange note registered under the Securities Act having a principal amount equal to that of the surrendered outstanding note. As a result, registered holders of exchange notes issued in the exchange offer on the relevant record date for the first interest payment date following the completion of the exchange offer will receive interest accruing from the most recent date to which interest has been paid on the outstanding notes. Outstanding notes that we accept for exchange will cease to accrue interest from and after the date of completion of the exchange offer.

Return of Outstanding Notes Not Accepted or Exchanged

If we do not accept any tendered outstanding notes for exchange or if outstanding notes are submitted for a greater principal amount than the holder desires to exchange, the unaccepted or non-exchanged outstanding notes will be returned without expense to their tendering holder. Such non-exchanged outstanding notes will be credited to an account maintained with DTC. These actions will occur promptly after the expiration or termination of the exchange offer.

Determinations of Validity

All questions as to the validity, form, eligibility, including time of receipt, acceptance and withdrawal of the tendered outstanding notes will be determined by us in our sole discretion. This determination will be final and binding. We reserve the absolute right to reject any and all outstanding notes not properly tendered or any outstanding notes our acceptance of which would, in the opinion of our counsel, be unlawful. We also reserve the absolute right to waive any irregularities or conditions of tender as to particular outstanding notes. Our interpretation of the terms and conditions of the exchange offer, including the instructions in the letter of transmittal, will be final and binding on all parties. Unless waived, any defects or irregularities in connection with tenders of outstanding notes must be cured within the time we shall determine. Although we intend to notify holders of defects or irregularities related to tenders of outstanding notes, neither we, the exchange agent nor any other person shall be under any duty to give notification of defects or irregularities related to tenders of outstanding notes nor shall we or any of them incur liability for failure to give notification. Tenders of outstanding notes will not be considered to have been made until the irregularities have been cured or waived. Any outstanding notes received by the exchange agent that we determine are not properly tendered or the tender of which is otherwise rejected by us and as to which the defects or irregularities have not been cured or waived by us will be returned by the exchange agent to the tendering holder (unless otherwise provided in the letter of transmittal), promptly after the expiration date.

Withdrawal of Tenders

Except as otherwise provided in this prospectus, tenders of outstanding notes may be withdrawn at any time before 5:00 p.m., New York City time, on the expiration date. To withdraw a tender of outstanding notes in the exchange offer:


•	a written or facsimile transmission of a notice of withdrawal must be received by the exchange agent at its address listed below before 5:00 p.m., New York City time, on the expiration date; or


•	you must comply with the appropriate procedures of ATOP.

Any notice of withdrawal must:


•	specify the name of the person having deposited the outstanding notes to be withdrawn;


•	identify the outstanding notes to be withdrawn, including the principal amount of the outstanding notes or, in the case of the outstanding notes transferred by book-entry transfer, the name and number of the account at the depository to be credited;

•

be signed by the same person and in the same manner as the original signature on the letter of transmittal by which the outstanding notes were tendered, including any required signature guarantee, or be accompanied by documents of transfer sufficient to permit the trustee for the outstanding notes to register the transfer of the outstanding notes into the name of the person withdrawing the tender; and


•	specify the name in which any of these outstanding notes are to be registered, if different from that of the person who deposited the outstanding notes to be withdrawn.

All questions as to the validity, form and eligibility, including time of receipt, of the withdrawal notices will be determined by us in our sole discretion, and our determination shall be final and binding on all parties. Any outstanding notes so withdrawn will be judged not to have been tendered according to the procedures in this prospectus for purposes of the exchange offer, and no exchange notes will be issued in exchange for those outstanding notes unless the outstanding notes so withdrawn are validly retendered. Any outstanding notes that have been tendered but are not accepted for exchange will be returned by transfer into the holder’s account at DTC according to the procedures described above. This return or crediting will take place promptly after withdrawal, rejection of tender or termination of the exchange offer. Properly withdrawn outstanding notes may be retendered by following one of the procedures described above under “—Procedures for Tendering” at any time before the expiration date. We may issue a suspension notice to broker-dealers, the initial purchasers and other parties upon the happening of any event that makes any statement in this prospectus untrue in any material respect.

Conditions

We will not be required to accept for exchange, or exchange any exchange notes for, any outstanding notes if the exchange offer, or the making of any exchange by a holder of outstanding notes, would violate applicable law or any applicable interpretation of the staff of the SEC. Similarly, we may terminate the exchange offer as provided in this prospectus before accepting outstanding notes for exchange in the event of such a potential violation. In addition, we may be required to suspend the use of this prospectus if any event occurs that requires us to supplement or amend this prospectus.

In addition, we will not be obligated to accept for exchange the outstanding notes of any holder that has not made to us the representations described under “—Terms of the Exchange Offer” and such other representations as may be reasonably necessary under applicable SEC rules, regulations or interpretations to allow us to use an appropriate form to register the exchange notes under the Securities Act.

We expressly reserve the right to amend or terminate the exchange offer, and to reject for exchange any outstanding notes not previously accepted for exchange, upon the occurrence of any of the conditions to the exchange offer specified above. We will give prompt written notice of any extension, amendment, non-acceptance or termination to the holders of the outstanding notes as promptly as practicable.

These conditions are for our sole benefit, and we may assert them or waive them in whole or in part at any time or at various times in our sole discretion. If we fail at any time to exercise any of these rights, this failure will not mean that we have waived our rights. Each such right will be deemed an ongoing right that we may assert at any time or at various times.

In addition, we will not accept for exchange any outstanding notes tendered, and will not issue exchange notes in exchange for any such outstanding notes, if the registration statement of which this prospectus is a part is required to be updated through a post-effective amendment or if at such time any stop order has been threatened or is in effect with respect to the registration statement of which this prospectus constitutes a part or the qualification of the indenture relating to the exchange notes under the Trust Indenture Act of 1939.

Exchange Agent

Citibank, N.A., the paying agent, registrar and authenticating agent under the indenture, has been appointed as exchange agent for the exchange offer. In this capacity, the exchange agent has no fiduciary duties and will be acting solely on the basis of our directions. Requests for assistance should be directed to the exchange agent by mail addressed as follows:

By Registered or Certified Mail, Hand Delivery or Overnight Courier:

Citibank, N.A.

Agency & Trust

388 Greenwich St., 14^th Floor

New York, NY 10013

Attention: Magnum Hunter Senior Notes due 2020

By Facsimile Transmission: (714) 845-4107 (for eligible institutions only)

To Confirm by Telephone or for Information: (714) 845-4102

Fees and Expenses

We will bear the expenses of soliciting holders of outstanding notes to determine if such holders wish to tender those outstanding notes for exchange notes. The principal solicitation under the exchange offer is being made by mail. Additional solicitations may be made by our officers and regular employees and our affiliates in person, by telegraph, telephone or telecopier.

We have not retained any dealer-manager in connection with the exchange offer and will not make any payments to brokers, dealers or other persons soliciting acceptances of the exchange offer. We, however, will pay the exchange agent reasonable and customary fees for its services and will reimburse the exchange agent for its reasonable out-of-pocket costs and expenses in connection with the exchange offer and will indemnify the exchange agent for all losses and claims incurred by it as a result of the exchange offer. We may also pay brokerage houses and other custodians, nominees and fiduciaries the reasonable out-of-pocket expenses incurred by them in forwarding copies of this prospectus, letters of transmittal and related documents to the beneficial owners of the outstanding notes and in handling or forwarding tenders for exchange.

We will pay the expenses to be incurred in connection with the exchange offer, including fees and expenses of the exchange agent and trustee and accounting and legal fees and printing costs.

You will not be obligated to pay any transfer tax in connection with the exchange, except if you instruct us to register exchange notes in the name of, or request that outstanding notes not tendered or not accepted in the exchange offer be returned to, a person other than you, in which event you will be responsible for the payment of any applicable transfer tax.

Federal Income Tax Consequences

We believe that the exchange of the outstanding notes will not constitute a taxable exchange for United States federal income tax purposes. See “Certain Material United States Federal Income Tax Considerations.”

Accounting Treatment

The exchange notes will be recorded at the same carrying value as the outstanding notes as reflected in our accounting records on the date of the exchange. Accordingly, no gain or loss for accounting purposes will be recognized by us upon the closing of the exchange offer. We will amortize the expenses of the exchange offer over the term of the exchange notes.

Participation in the Exchange Offer; Untendered Outstanding Notes

Participation in the exchange offer is voluntary. Holders of outstanding notes are urged to consult their financial and tax advisors in making their own decisions on what action to take.

As a result of the making of, and upon acceptance for exchange of all of the outstanding notes tendered under the terms of, the exchange offer, we will have fulfilled a covenant contained in the terms of the registration rights agreements. Holders of outstanding notes who do not tender in the exchange offer will continue to hold their outstanding notes and will be entitled to all the rights, and subject to the limitations, applicable to the outstanding notes under the indenture. Holders of outstanding notes will no longer be entitled to any rights under the registration rights agreements that by its terms terminates or ceases to have further effect as a result of the making of this exchange offer. See “Description of the Exchange Notes.” All untendered outstanding notes will continue to be subject to the restrictions on transfer described in the indenture. To the extent the outstanding notes are tendered and accepted, there will be fewer outstanding notes remaining following the exchange, which could significantly reduce the liquidity of the untendered outstanding notes.

We may in the future seek to acquire our untendered outstanding notes in the open market or through privately negotiated transactions, through subsequent exchange offers or otherwise. We intend to make any acquisitions of the outstanding notes following the applicable requirements of the Exchange Act, and the rules and regulations of the SEC under the Exchange Act, including Rule 14e-1, to the extent applicable. We have no present plan to acquire any outstanding notes that are not tendered in the exchange offer or to file a registration statement to permit resales of any outstanding notes that are not tendered in the exchange offer, except in those circumstances in which we may be obligated to file a shelf registration statement.

DESCRIPTION OF THE EXCHANGE NOTES

You can find the definitions of certain terms used in this description under the subheading “—Certain Definitions.” Terms used in this description but not defined below under the subheading “—Certain Definitions” have the meanings assigned to them in the Indenture.

In this description, (i) the term “Issuer” refers only to Magnum Hunter Resources Corporation, a Delaware corporation, and not to any of its Subsidiaries and (ii) the terms “we,” “our” and “us” each refer to the Issuer and its Subsidiaries. The Issuer previously issued $600,000,000 aggregate principal amount of 9.750% Senior Notes due 2020, consisting of (i) $450,000,000 aggregate principal amount of 9.750% Senior Notes due 2020 issued on May 16, 2012, and (ii) $150,000,000 aggregate principal amount of 9.750% Senior Notes due 2020 issued on December 18, 2012. The outstanding notes were issued under an Indenture dated as of May 16, 2012, as supplemented, among the Issuer, the Guarantors and Wilmington Trust, National Association, as trustee. The exchange notes will also be issued under the Indenture. The terms of the exchange notes will be substantially identical to the outstanding notes, except that the exchange notes will be registered under the Securities Act, will not bear restrictive legends restricting their transfer under the Securities Act and will not contain provisions relating to an increase in any interest rate in connection with the outstanding notes under circumstances related to the timing of the exchange offer. Unless expressly stated or the context otherwise requires, references to the “notes” in this “Description of the Exchange Notes” section means the outstanding notes and the exchange notes.

The following description is a summary of the material provisions of the Indenture, as supplemented. It does not restate the Indenture in its entirety. We urge you to read the Indenture because it, and not this description, defines your rights as holders of the notes. A copy of the Indenture, including forms of the notes, is attached as Exhibit 4.1 to the Company’s Current Report on Form 8-K filed with the SEC on May 16, 2012. As of the date hereof, the Indenture has been supplemented by (i) the First Supplemental Indenture, dated October 18, 2012, filed as Exhibit 4.6.1 to our registration statement on Form S-4 filed on January 14, 2013, (ii) the Second Supplemental Indenture, dated December 13, 2012, filed as Exhibit 4.6.2 to our registration statement on Form S-4 filed on January 14, 2013, (iii) the Third Supplemental Indenture, dated as of dated April 24, 2013, filed as Exhibit 4.6.3 to our 2012 Form 10-K and (iv) the Fourth Supplemental Indenture, dated as of July 23, 2013, filed as Exhibit 4.6.4 to our quarterly report on Form 10-Q for the quarter ended June 30, 2013 filed on August 9, 2013.

The registered holder of a note is treated as the owner of it for all purposes. Only registered holders will have rights under the Indenture.

Brief Description of the Notes and the Note Guarantees

The Notes

The notes are:


•	general unsecured obligations of the Issuer;


•	pari passu in right of payment with all existing and future senior Indebtedness of the Issuer, including obligations under the MHR Senior Revolving Credit Facility;


•	effectively subordinated to all existing and future senior secured Indebtedness incurred from time to time by the Issuer, including obligations under the MHR Senior Revolving Credit Facility, to the extent of the value of the assets securing such Indebtedness;


•	senior in right of payment to any subordinated Indebtedness of the Issuer;


•	unconditionally guaranteed by the Guarantors;


•	structurally subordinated to any liabilities of any of the Issuer’s Subsidiaries that do not guarantee the notes; and


•	subject to registration with the SEC pursuant to the Registration Rights Agreements.

The Note Guarantees

The notes are guaranteed by all of the Restricted Subsidiaries (which include all of the Issuer’s Domestic Subsidiaries that are guarantors under a Credit Facility pursuant to clause (1) of the second paragraph of the covenant described under the caption “Certain Covenants—Incurrence of Indebtedness and Issuance of Preferred Stock”).

Each of the Guarantors’ guarantee of the notes is:


•	a general unsecured obligation of such Guarantor;


•	pari passu in right of payment with all existing and future senior Indebtedness of such Guarantor, including its guarantee of the MHR Senior Revolving Credit Facility;


•	effectively subordinated to all existing and future senior secured Indebtedness incurred from time to time by such Guarantor, including its guarantee of the MHR Senior Revolving Credit Facility, to the extent of the value of the assets securing such Indebtedness;


•	structurally subordinated to any liabilities of any of the Issuer’s Subsidiaries’ direct and indirect parents that do not guarantee the notes; and


•	senior in right of payment to any subordinated Indebtedness of such Guarantor.

Not all of the Issuer’s Subsidiaries are Guarantors. Any Guarantor may be released from time to time from its Note Guarantees in the circumstances described under “—Note Guarantees.” In addition, under the circumstances described below under the caption “—Certain Covenants—Designation of Restricted and Unrestricted Subsidiaries,” the Issuer is permitted to designate certain of its Subsidiaries as “Unrestricted Subsidiaries.” The Issuer’s Unrestricted Subsidiaries are not subject to any of the restrictive covenants in the Indenture and do not guarantee the notes. Eureka Holdings, Eureka Pipeline, Eureka Hunter Land, LLC, Energy Hunter Securities, Inc., Magnum Hunter Midstream, LLC, Magnum Hunter Services, LLC, MHR Callco Corporation, MHR Exchangeco Corporation, Triad Hunter Gathering, LLC, TransTex Hunter, Sentra Corporation, Williston Hunter Canada, Inc. (formerly known as Nuloch Resources Inc.) and 54NG, LLC are Unrestricted Subsidiaries as of the date hereof. In the event of a bankruptcy, liquidation or reorganization of any of our non-guaranteeing Subsidiaries, such Subsidiaries will pay the holders of their debt and their trade creditors before they will be able to distribute any of their assets to us.

For the six months ended June 30, 2013, the non-guarantor Subsidiaries of the Issuer generated 22.1% of the Issuer’s consolidated net revenue and 31.8% of the Issuer’s consolidated loss from continued operations. In addition, at June 30, 2013, the non-guarantor Subsidiaries of the Issuer held 28.8% of the Issuer’s consolidated assets and 14.3% of the Issuer’s consolidated liabilities.

Ranking

The notes are effectively subordinated to all existing and future senior secured Indebtedness incurred from time to time by the Issuer and the Guarantors, to the extent of the value of the assets securing such Indebtedness, and structurally subordinated to all indebtedness and other liabilities of all of its Subsidiaries that do not guarantee the notes. As of September 30, 2013, the Issuer and the Guarantors had remaining capacity to incur an additional $167.8 million under the MHR Senior Revolving Credit Facility, all of which would have been Secured Indebtedness. Borrowings under the MHR Senior Revolving Credit Facility are secured by substantially all of the Issuer’s and the Guarantors’ assets and, consequently, will rank effectively senior to the notes to the extent of the value of the assets securing such Indebtedness. See “Risks Related to the Exchange Offer, the Exchange Notes and the Exchange Guarantees—The exchange notes will be unsecured and will be effectively subordinated to our and guarantors’ secured debt and indebtedness of non-guarantor subsidiaries.”

Principal, Maturity and Interest

The Issuer is offering up to $600 million in aggregate principal amount of exchange notes in this exchange offer. The Issuer may issue additional notes under the Indenture from time to time, although the MHR Senior Revolving Credit Facility limits the aggregate amount of notes to $600 million. Any issuance of additional notes is subject to all of the covenants in the Indenture, including the covenant described below under the caption “—Certain Covenants—Incurrence of Indebtedness and Issuance of Preferred Stock.” Any further additional notes subsequently issued under the Indenture will be treated as a single class with the outstanding notes and the exchange notes for all purposes under the Indenture, including, without limitation, waivers, amendments, redemptions and offers to purchase, and will be fungible with the original notes to the extent set forth in the applicable supplemental indenture. The Issuer will issue notes in denominations of $2,000 and integral multiples of $1,000 in excess of $2,000. The notes will mature on May 15, 2020.

Interest on the notes accrues at the rate of 9.750% per annum and is payable semi-annually in arrears on May 15 and November 15, with the next payment being due on November 15, 2013. Interest on overdue principal and interest, if any, accrues at a rate that is 1% higher than the then applicable interest rate on the notes. The Issuer will make each interest payment to the holders of record on the immediately preceding May 1 and November 1 of each year.

Interest on the notes accrues from the date of original issuance thereof or, if interest has already been paid, from the date it was most recently paid. Interest is computed on the basis of a 360-day year comprised of twelve 30-day months.

Paying Agent and Registrar for the Notes

Citibank, N.A. is paying agent and registrar. The Issuer may change the paying agent or registrar without prior notice to the holders of the notes, and the Issuer or any of the Guarantors may act as paying agent or registrar.

Transfer and Exchange

A holder may transfer or exchange notes in accordance with the provisions of the Indenture. The registrar and the trustee may require a holder, among other things, to furnish appropriate endorsements and transfer documents in connection with a transfer of notes. Holders will be required to pay all taxes due on transfer or exchange. The Issuer will not be required to transfer or exchange

any note selected for redemption. Also, the Issuer will not be required to transfer or exchange any note for a period of 15 days before a selection of notes to be redeemed or between a record date and the next succeeding interest payment date.

Note Guarantees

The notes are guaranteed by all of the domestic Restricted Subsidiaries that guarantee the Issuer’s obligations under the MHR Senior Revolving Credit Facility (collectively, the “Guarantors”). In the future, all Domestic Subsidiaries of the Issuer that guarantee the Issuer’s obligations under any Credit Facility incurred pursuant to clause (1) of the second paragraph of the covenant described below under the caption “—Certain Covenants—Incurrence of Indebtedness and Issuance of Preferred Stock,” including the MHR Senior Revolving Credit Facility or other capital markets Indebtedness, will be required to guarantee the notes under the circumstances described under “—Certain Covenants—Additional Note Guarantees,” unless the Issuer designates any such subsidiary to be an Unrestricted Subsidiary in accordance with the terms of the Indenture. These Note Guarantees will be joint and several obligations of the Guarantors. The obligations of each Guarantor under its Note Guarantee will be limited as necessary to prevent that Note Guarantee from constituting a fraudulent conveyance under applicable law, although this limitation may not be effective to prevent the Note Guarantees from being voided in bankruptcy. See “Risks Related to the Exchange Offer, the Exchange Notes and the Exchange Guarantees—Federal and state statutes allow courts, under specific circumstances to void notes and adversely affect the validity and enforceability of the guarantees and require noteholders to return payments received.”

The Note Guarantee of a Guarantor will be released without the consent of any noteholders:

(1) in connection with any sale or other disposition of all or substantially all of the properties or assets of that Guarantor, by way of merger, consolidation or otherwise, to a Person that is not (either before or after giving effect to such transaction) the Issuer or any Restricted Subsidiary, if the sale or other disposition does not violate the “Asset Sale” provisions of the Indenture;

(2) in connection with any sale or other disposition of the Capital Stock of that Guarantor to a Person that is not (either before or after giving effect to such transaction) the Issuer or any Restricted Subsidiary, if the sale or other disposition does not violate the “Asset Sale” provisions of the Indenture and the Guarantor ceases to be a Restricted Subsidiary as a result of the sale or other disposition;

(3) if the Issuer designates any Restricted Subsidiary that is a Guarantor to be an Unrestricted Subsidiary in accordance with the applicable provisions of the Indenture;

(4) if the Indebtedness which resulted in the obligations to Guarantee the notes pursuant to the covenant described under “Certain Covenants—Additional Note Guarantees” is repaid;

(5) upon the liquidation or dissolution of any Guarantor that does not constitute a Default or Event of Default;

(6) in the case of any Restricted Subsidiary which after the date of the Indenture is required to guarantee the notes pursuant to the covenant described under the caption “Certain Covenants—Additional Note Guarantees,” the release or discharge of the guarantee by such Restricted Subsidiary of all of the Indebtedness of the Issuer or any Guarantor or the repayment of all of the Indebtedness which resulted in the obligation to guarantee the notes; or

(7) upon legal defeasance, covenant defeasance or satisfaction and discharge of the Indenture as provided below under the captions “—Legal Defeasance and Covenant Defeasance” and “—Satisfaction and Discharge.”

See “—Repurchase at the Option of Holders—Asset Sales.”

Optional Redemption

At any time prior to May 15, 2015, the Issuer may on any one or more occasions redeem up to 35% of the aggregate principal amount of notes issued (including the outstanding notes, the exchange notes and any additional notes) under the Indenture upon notice as provided in the Indenture at a redemption price equal to 109.750% of the principal amount of the notes redeemed, plus accrued and unpaid interest and Additional Interest, if any, to the date of redemption (subject to the rights of holders of notes on the relevant record date to receive interest on the relevant interest payment date), with the net cash proceeds of an Equity Offering by the Issuer; provided that:

(1) at least 65% of the aggregate principal amount of notes originally issued under the Indenture (excluding notes held by the Issuer and its Subsidiaries) remains outstanding immediately after the occurrence of such redemption; and

(2) the redemption occurs within 180 days of the date of the closing of such Equity Offering.

At any time prior to May 15, 2016, the Issuer may on any one or more occasions redeem all or a part of the notes, upon notice as provided in the Indenture, at a redemption price equal to 100% of the principal amount of the notes redeemed, plus the Applicable Premium as of, and accrued and unpaid interest, if any, to the date of redemption, subject to the rights of holders of notes on the relevant record date to receive interest due on the relevant interest payment date.

Except pursuant to the preceding paragraphs and the final paragraph under “—Repurchase at the Option of Holders—Change of Control,” the notes are not redeemable at the Issuer’s option prior to May 15, 2016.

On or after May 15, 2016, the Issuer may on any one or more occasions redeem all or a part of the notes, upon notice as provided in the Indenture, at the redemption prices (expressed as percentages of principal amount) set forth below, plus accrued and unpaid interest, if any, on the notes redeemed, to the applicable date of redemption, if redeemed during the twelve‑month period beginning on May 15 of the years indicated below, subject to the rights of holders of notes on the relevant record date to receive interest on the relevant interest payment date:



Year	Percentage
2016	104.875	%
2017	102.438	%
2018 and thereafter	100.000	%

Unless the Issuer defaults in the payment of the redemption price, interest will cease to accrue on the notes or portions thereof called for redemption on the applicable redemption date.

Mandatory Redemption

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

Repurchase at the Option of Holders

Change of Control

If a Change of Control occurs, unless the Issuer at such time has given notice of redemption under “—Optional Redemption” with respect to all notes then outstanding, each holder of notes will have the right to require the Issuer to repurchase all or any part (equal to $2,000 or an integral multiple of $1,000 in excess thereof) of that holder’s notes pursuant to a Change of Control Offer on the terms set forth in the Indenture. In the Change of Control Offer, the Issuer will offer a payment in cash, which we refer to as a Change of Control Payment, equal to 101% of the aggregate principal amount of notes repurchased, plus accrued and unpaid interest, if any, on the notes repurchased to the date of purchase (the “Change of Control Purchase Date”), subject to the rights of holders of notes on the relevant record date to receive interest due on the relevant interest payment date. Within 30 days following any Change of Control, unless the Issuer at such time has given notice of redemption under “—Optional Redemption” with respect to all notes then outstanding, or, at the Issuer’s option and as set forth below, in advance of a Change of Control, the Issuer will mail a notice to each holder describing the transaction or transactions that constitute the Change of Control and offering to repurchase notes properly tendered prior to the expiration date specified in the notice, which date will be no earlier than 30 days and no later than 60 days from the date such notice is mailed, pursuant to the procedures required by the Indenture and described in such notice. The Issuer will comply with the requirements of Rule 14e-1 under the Exchange Act and any other securities laws and regulations thereunder to the extent those laws and regulations are applicable in connection with the repurchase of the notes as a result of a Change of Control. To the extent that the provisions of any securities laws or regulations conflict with the Change of Control provisions of the Indenture, the Issuer will comply with the applicable securities laws and regulations and will not be deemed to have breached its obligations under the Change of Control provisions of the Indenture by virtue of such compliance.

Promptly following the expiration of the Change of Control Offer, the Issuer will, to the extent lawful, accept all notes or portions of notes properly tendered pursuant to the Change of Control Offer. Promptly after such acceptance, the Issuer will, on the Change of Control Purchase Date:

(1) deposit with the paying agent an amount equal to the Change of Control Payment in respect of all notes or portions of notes properly tendered; and

(2) deliver or cause to be delivered to the trustee the notes properly tendered and accepted together with an officers’ certificate stating the aggregate principal amount of notes or portions of notes being purchased by the Issuer pursuant to the Change of Control Offer.

The paying agent will promptly mail or wire transfer to each holder of notes properly tendered the Change of Control Payment for such notes (or, if all the notes are then in global form, make such payment through the facilities of DTC, and the trustee will promptly authenticate and mail (or cause to be transferred by book entry) to each such holder a new exchange note equal in principal amount to any unpurchased portion of the notes surrendered, if any. The Issuer will publicly announce the results of the Change of Control Offer on or as soon as practicable after the Change of Control Purchase Date.

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

The Issuer will not be required to make a Change of Control Offer upon a Change of Control if (1) a third party makes the Change of Control Offer in the manner, at the time and otherwise in compliance with the requirements set forth in the Indenture applicable to a Change of Control Offer made by the Issuer and purchases all notes properly tendered and not withdrawn under the Change of Control Offer, or (2) notice of redemption has been given pursuant to the Indenture as described above under the caption “—Optional Redemption,” unless and until there is a default in payment of the applicable redemption price. Notwithstanding anything to the contrary contained herein, a Change of Control Offer may be made in advance of a Change of Control, conditioned upon the consummation of such Change of Control, if a definitive agreement is in place for the Change of Control at the time the Change of Control Offer is made.

Notes repurchased by the Issuer pursuant to a Change of Control Offer will have the status of notes issued but not outstanding or will be retired and cancelled, at the option of the Issuer. Notes purchased by a third party pursuant to clause (1) of the preceding paragraph will have the status of notes issued and outstanding.

The definition of Change of Control includes a phrase relating to the direct or indirect sale, lease, transfer, conveyance or other disposition of “all or substantially all” of the properties or assets of the Issuer and its Subsidiaries taken as a whole. Although there is a limited body of case law interpreting the phrase “substantially all,” there is no precise established definition of the phrase under applicable law. Accordingly, the ability of a holder of notes to require the Issuer to repurchase its notes as a result of a sale, lease, transfer, conveyance or other disposition of less than all of the assets of the Issuer and the Restricted Subsidiaries taken as a whole to another Person or group may be uncertain.

The MHR Senior Revolving Credit Facility contains certain prohibitions on the Issuer and its Restricted Subsidiaries purchasing notes, and also provides that the occurrence of certain change of control events with respect to the Issuer would constitute a default thereunder. Prior to complying with any of the provisions of this “Change of Control” covenant under the Indenture governing the notes, but in any event within 90 days following a Change of Control, to the extent required to permit the Issuer to comply with this covenant, the Issuer will need to either repay all outstanding Indebtedness under the MHR Senior Revolving Credit Facility or other Indebtedness ranking pari passu with the notes or obtain the requisite consents, if any, under all agreements governing such outstanding Indebtedness. If the Issuer does not repay such Indebtedness or obtain such consents, the Issuer will remain prohibited from purchasing notes in a Change of Control, which after appropriate notice and lapse of time would result in an Event of Default under the Indenture, which would in turn constitute a default under the MHR Senior Revolving Credit Facility.

Future Indebtedness that the Issuer or its Restricted Subsidiaries may incur may contain prohibitions on the occurrence of certain events that would constitute a Change of Control or require the repurchase of such Indebtedness upon a Change of Control. Moreover, the exercise by the holders of the notes of their right to require the Issuer to repurchase their notes could cause a default under such Indebtedness, even if the Change of Control itself does not, due to the financial effect of such repurchase on the Issuer or its Restricted Subsidiaries. Finally, the Issuer’s ability to pay cash to the holders of notes following the occurrence of a Change of Control may be limited by its then existing financial resources. There can be no assurance that sufficient funds will be available when necessary to make any required repurchases. See “Risks Related to the Exchange Offer, the Exchange Notes and the Related Guarantees—We may be unable to purchase the exchange notes upon a change of control which would result in a default under the Indenture that governs the notes and would adversely affect our business.”

The Change of Control purchase feature of the notes may in certain circumstances make more difficult or discourage a sale or takeover of the Issuer or its Restricted Subsidiaries and, thus, the removal of incumbent management. The Issuer has no present intention to engage in a transaction involving a Change of Control, although it is possible that the Issuer could decide to do so in the future. Subject to the limitations discussed below, the Issuer or its Restricted Subsidiaries could, in the future, enter into certain transactions, including acquisitions, refinancings or other recapitalizations, that would not constitute a Change of Control under the Indenture, but that could increase the amount of Indebtedness outstanding at such time or otherwise affect the capital structure of the Issuer or its credit ratings. Restrictions on the ability of the Issuer and its Restricted Subsidiaries to incur additional Indebtedness are contained in the covenant described under the caption “—Certain Covenants—Incurrence of Indebtedness and Issuance of Preferred Stock.” Such restrictions can only be waived with the consent of the holders of a majority in principal amount of the notes then outstanding. Except for the limitations contained in such covenant, however, the Indenture does not contain any covenants or provisions that may afford holders of the notes protection in the event of a highly leveraged transaction.

In the event that holders of not less than 90% in aggregate principal amount of the notes then outstanding accept a Change of Control Offer and the Issuer (or any third party making such Change of Control Offer in lieu of the Issuer as described above) purchases all of the notes held by such holders, the Issuer will have the right, upon not less than 30 nor more than 60 days prior notice, given not more than 30 days following the purchase pursuant to the Change of Control Offer described above, to redeem all of the notes that remain outstanding following such purchase at a redemption price equal to the Change of Control Payment plus, to the extent not included in the Change of Control Payment, accrued and unpaid interest, if any, on the notes that remain outstanding, to the date of redemption (subject to the right of holders of record on the relevant record date to receive interest due on an interest payment date that is on or prior to the redemption date).

Asset Sales

The Issuer will not, and will not permit any Restricted Subsidiary to, consummate an Asset Sale unless:

(1) the Issuer (or a Restricted Subsidiary, as the case may be) receives consideration at the time of the Asset Sale at least equal to the Fair Market Value (measured as of the date of the definitive agreement with respect to such Asset Sale) of the assets or Equity Interests issued or sold or otherwise disposed of; and

(2) at least 75% of the aggregate consideration received in the Asset Sale by the Issuer or a Restricted Subsidiary and all other Asset Sales since the date of the Indenture is in the form of cash or Cash Equivalents. For purposes of this provision, each of the following will be deemed to be cash:

(a) any liabilities, as shown on the Issuer’s most recent consolidated balance sheet, of the Issuer or any Restricted Subsidiary (other than contingent liabilities and liabilities that are by their terms subordinated to the notes or any Note Guarantee) that are assumed by the transferee of any such assets pursuant to a customary novation or indemnity agreement that releases the Issuer or such Restricted Subsidiary from or indemnifies against further liability;

(b) any securities, notes or other obligations received by the Issuer or any Restricted Subsidiary from such transferee that are, within 180 days of the Asset Sale, converted by the Issuer or such Restricted Subsidiary into cash, to the extent of the cash received in that conversion;

(c) accounts receivable of a business retained by the Issuer or any of its Restricted Subsidiaries, as the case may be, following the sale of such business; provided that such accounts receivable (i) are not past due more than 90 days and (ii) do not have a payment date greater than 120 days from the date of the invoices creating such accounts receivable;

(d) any Capital Stock or assets of the kind referred to in clause (2) or (4) of the next paragraph of this covenant; and

(e) all other assets (except cash, Cash Equivalents and the liabilities and properties to the extent specified in the preceding clauses (a) through (d)) received for all Asset Sales since the date of the Indenture to the extent that the Fair Market Value of all such other assets does not exceed in the aggregate 10% of the Issuer’s Adjusted Consolidated Net Tangible Assets at the time of determination;

provided that in the case of any Asset Sale pursuant to a condemnation, appropriation or similar taking, including by deed in lieu of condemnation, such Asset Sale shall not be required to satisfy the requirements of items (1) and (2) above. Notwithstanding the preceding, the 75% limitation referred to above shall be deemed satisfied with respect to any Asset Sale in which the cash or Cash Equivalents portion of the consideration received therefrom, determined in accordance with the preceding provision on an after-tax basis, is equal to or greater than what the after-tax proceeds would have been had such Asset Sale complied with the aforementioned 75% limitation.

Within 365 days after the receipt of any Net Proceeds from an Asset Sale, the Issuer (or any Restricted Subsidiary) may apply such Net Proceeds:

(1) to prepay, repay, purchase, repurchase, redeem, reduce, defease or acquire or retire (i) Obligations under Secured Indebtedness of the Issuer or any Restricted Subsidiary, (ii) Obligations under Indebtedness of a Restricted Subsidiary that is not a Guarantor (other than Indebtedness owed to the Issuer or another Restricted Subsidiary) or (iii) Obligations under Senior Indebtedness (provided that if the Issuer or any Guarantor shall so reduce Obligations under unsecured Senior Indebtedness, the Issuer will equally and ratably reduce Obligations under the notes as provided under “—Optional Redemption,” through open market purchases (provided that such purchases are at or above 100% of the principal amount thereof) or by making an offer (in accordance with the procedures set forth below for an Asset Sale Offer) to all holders of the notes to purchase at a purchase price equal to 100% of the principal amount thereof, plus accrued and unpaid interest and Additional Interest, if any, the pro rata principal amount of notes), in each case other than Indebtedness owed to the Issuer or any Restricted Subsidiary;

(2) to acquire all or substantially all of the assets of, or any Capital Stock of, one or more other Persons primarily engaged in the Oil and Gas Business, if, after giving effect to any such acquisition of Capital Stock, such Person becomes a Restricted Subsidiary;

(3) to make capital expenditures in respect of the Issuer’s or any Restricted Subsidiaries’ Oil and Gas Business; or

(4) to acquire other assets (other than Capital Stock) that are not classified as current assets under GAAP and that are used or useful in the Oil and Gas Business.

The requirement of clauses (2) through (4) of the preceding paragraph shall be deemed to be satisfied if a bona fide binding contract committing to make the investment, acquisition or expenditure referred to therein is entered into by the Issuer or any Restricted Subsidiary, as the case may be, with a Person other than an Affiliate of the Issuer within the time period specified in the preceding

paragraph and such Net Proceeds are subsequently applied in accordance with such contract within six months following the date such agreement is entered into.

Pending the final application of any Net Proceeds, the Issuer or any Restricted Subsidiary may reduce revolving credit borrowings or invest the Net Proceeds in any manner that is not prohibited by the Indenture.

Any Net Proceeds from Asset Sales that are not applied or invested as provided in the second paragraph of this covenant will constitute “Excess Proceeds.” When the aggregate amount of Excess Proceeds exceeds $25.0 million, within ten business days thereof, the Issuer will make an offer (an “Asset Sale Offer”) to all holders of notes and all holders of other Indebtedness that is pari passu with the notes containing provisions similar to those set forth in the Indenture with respect to offers to purchase, prepay or redeem with the proceeds of sales of assets to purchase, prepay or redeem, on a pro rata basis, the maximum principal amount of notes and such other pari passu Indebtedness (plus all accrued interest on the Indebtedness and the amount of all fees and expenses, including premiums, incurred in connection therewith) that may be purchased, prepaid or redeemed out of the Excess Proceeds. The offer price in any Asset Sale Offer will be equal to 100% of the principal amount, plus accrued and unpaid interest, if any, to the date of purchase, prepayment or redemption, subject to the rights of holders of notes on the relevant record date to receive interest due on the relevant interest payment date, and will be payable in cash. If any Excess Proceeds remain after consummation of an Asset Sale Offer, the Issuer or any Restricted Subsidiary may use those Excess Proceeds for any purpose not otherwise prohibited by the Indenture. If the aggregate principal amount of notes tendered in such Asset Sale Offer exceeds the amount of Excess Proceeds allocated to the purchase of notes, the trustee will select the notes to be purchased on a pro rata basis (except that any notes represented by a note in global form will be selected as discussed under “—Procedures for Tendering” based on a method as DTC may require), based on the amounts tendered (with such adjustments as may be deemed appropriate by the Issuer so that only notes in denominations of $2,000, or an integral multiple of $1,000 in excess thereof, will be purchased). Upon completion of each Asset Sale Offer, the amount of Excess Proceeds will be reset at zero.

Notwithstanding the foregoing, the sale, conveyance or other disposition of all or substantially all of the properties and assets of the Issuer and the Restricted Subsidiaries, taken as a whole, will be governed by the “Change of Control” provisions of the Indenture and/or the “Merger, Consolidation or Sale of All or Substantially All Assets” provisions of the Indenture and not by the “Asset Sale” provisions of the Indenture.

The Issuer will comply with the requirements of Rule 14e-1 under the Exchange Act and any other securities laws and regulations thereunder to the extent those laws and regulations are applicable in connection with each repurchase of notes pursuant to an Asset Sale Offer. To the extent that the provisions of any securities laws or regulations conflict with the “Asset Sale” provisions of the Indenture or compliance with the “Asset Sale” provisions of the Indenture would constitute a violation of any such laws or regulations, the Issuer will comply with the applicable securities laws and regulations and will not be deemed to have breached its obligations under the “Asset Sale” provisions of the Indenture by virtue of such compliance.

The MHR Senior Revolving Credit Facility contains, and future agreements, including Credit Facilities, may contain prohibitions of certain events, including events that would constitute a Change of Control or an Asset Sale. The exercise by the holders of notes of their right to require the Issuer to repurchase the notes upon a Change of Control or an Asset Sale could cause a default under these other agreements, even if the Change of Control or Asset Sale itself does not, due to the financial effect of such repurchases on the Issuer or otherwise. In the event a Change of Control or Asset Sale occurs at a time when the Issuer is prohibited from purchasing notes, the Issuer could seek the consent of its senior lenders to the purchase of notes or could attempt to refinance the borrowings that contain such prohibition. If the Issuer does not obtain a consent or repay those borrowings, the Issuer will remain prohibited from purchasing notes. In that case, the Issuer’s failure to purchase tendered notes would constitute an Event of Default under the Indenture, which could, in turn, constitute a default under the other indebtedness. Finally, the Issuer’s ability to pay cash to the holders of notes upon a repurchase may be limited by the Issuer’s then existing financial resources. See “Risks Related to the Exchange Notes and the Related Guarantees—We may be able to purchase the Exchange Offer, the exchange notes upon a change of control which would result in a default under the indenture that governs the notes and would adversely affect our business.”

Selection and Notice

If less than all of the notes are to be redeemed at any time, the trustee will select notes for redemption on a pro rata basis (or, in the case of notes issued in global form as discussed under “—Procedures for Tendering,” based on a method as DTC may require) unless otherwise required by law or applicable stock exchange or depository requirements.

No notes of $2,000 or less can be redeemed in part. Notices of redemption will be mailed by first class mail at least 30 but not more than 60 days before the redemption date to each holder of notes to be redeemed at its registered address, except that (i) redemption notices may be mailed more than 60 days prior to a redemption date if the notice is issued in connection with a defeasance of the notes or a satisfaction and discharge of the Indenture. Notices of redemption may not be conditional, except that any redemption pursuant to the first paragraph under the “—Optional Redemption” section, may, at the Issuer’s discretion, be subject to completion of the related Equity Offering and (ii) as described under “—Change of Control”.

If any note is to be redeemed in part only, the notice of redemption that relates to that note will state the portion of the principal amount of that note that is to be redeemed. A new note in principal amount equal to the unredeemed portion of the original

note will be issued in the name of the holder of notes upon cancellation of the original note. Notes called for redemption become due on the date fixed for redemption. On and after the redemption date, interest ceases to accrue on notes or portions of notes called for redemption.

Certain Covenants

Changes in Covenants when Notes Rated Investment Grade

If on any date following the date of the Indenture:

(1) the notes are rated by both of the Rating Agencies as having an Investment Grade Rating; and

(2) no Default or Event of Default shall have occurred and be continuing, then, upon the Issuer’s delivery of notice of such events to the trustee, the covenants specifically listed under the following captions in this prospectus will be suspended:

(a) “—Repurchase at the Option of Holders—Asset Sales”;

(b) “—Certain Covenants—Restricted Payments”;

(d) “—Certain Covenants—Dividend and Other Payment Restrictions Affecting Restricted Subsidiaries”;

(e) “—Certain Covenants—Designation of Restricted and Unrestricted Subsidiaries”;

(f) “—Certain Covenants—Transactions with Affiliates”;

(g) Clause (a)(4) of the covenant described below under the caption “—Certain Covenants—Merger, Consolidation or Sale of Assets”; and

(h) “—Certain Covenants—Additional Note Guarantees.”

During any period that the foregoing covenants have been suspended, the Issuer’s Board of Directors may not designate any of its Subsidiaries as Unrestricted Subsidiaries pursuant to the covenant described below under the caption “—Certain Covenants—Designation of Restricted and Unrestricted Subsidiaries.”

Notwithstanding the foregoing, if the rating assigned by either such Rating Agency should subsequently decline to below Investment Grade Rating, the foregoing covenants will be reinstituted as of and from the date of such rating decline (the “Reversion Date”). In the event of any such reinstatement, no Default or Event of Default will be deemed to have occurred as a result of a failure to comply with the suspended covenants during a suspension period (or on the Reversion Date or after the suspension period based solely on events that occurred during the suspension period).

On each Reversion Date, all Indebtedness incurred during the Suspension Period prior to such Reversion Date will be deemed to be Permitted Indebtedness under clause (3) of paragraph (b) of “—Certain Covenants—Incurrence of Indebtedness and Issuance of Preferred Stock.” Calculations under the reinstated “Restricted Payments” covenant will be made as if the “Restricted Payments” covenant had been in effect since the date of the Indenture except that no Default will be deemed to have occurred solely by reason of a Restricted Payment made while that covenant was suspended. In addition, for the purposes of the covenants described under “—Transactions with Affiliates” and “—Dividend and Other Payment Restrictions Affecting Restricted Subsidiaries,” all agreements and arrangements entered into during the period in which such covenants are suspended shall be deemed to have been entered into and existing prior to the date of the Indenture. For purposes of the “Repurchase at the Option of Holders—Asset Sales” covenant, on the Reversion Date, the unutilized Excess Proceeds amount will be reset to zero.

There can be no assurance that the notes will ever achieve an Investment Grade Rating or that any such rating will be maintained.

Restricted Payments

The Issuer will not, and will not permit any Restricted Subsidiary to, directly or indirectly:

(1) declare or pay any dividend or make any other payment or distribution on account of the Issuer’s or any Restricted Subsidiary’s Equity Interests (including, without limitation, any payment in connection with any merger or consolidation involving the Issuer or any Restricted Subsidiary) or to the direct or indirect holders of the Issuer’s or any Restricted Subsidiary’s Equity Interests in their capacity as such (other than (i) dividends or distributions payable in Equity Interests (other than Disqualified Stock) of the Issuer, (ii) dividends or distributions payable to the Issuer or any Restricted Subsidiary or (iii) in the case of any dividend or distribution payable on or in respect of any class or series of Equity Interests issued by a Restricted Subsidiary other than a wholly owned Subsidiary, pro rata dividends or distributions to minority stockholders of such Restricted Subsidiary (or owners of an equivalent interest in the case of a Subsidiary that is an entity

other than a corporation), provided that the Issuer or one of its Restricted Subsidiaries receives at least its pro rata share of such dividend or distribution in accordance with its Equity Interests in such class or series of securities));

(2) repurchase, redeem or otherwise acquire or retire for value (including, without limitation, in connection with any merger or consolidation) any Equity Interests of the Issuer or any direct or indirect parent of the Issuer;

(3) make any payment on or with respect to, or repurchase, redeem, defease or otherwise acquire or retire for value any Indebtedness of the Issuer or any Guarantor that is contractually subordinated to the notes or to any Note Guarantee (excluding any Indebtedness permitted under clause (6) of the second paragraph of the covenant described under the caption “—Certain Covenants—Incurrence of Indebtedness and Issuance of Preferred Stock”), except a payment of interest or payment of principal at or within one year prior to the Stated Maturity thereof; or

(4) make any Restricted Investment (all such payments and other actions set forth in clauses (1) through (4) above being collectively referred to as “Restricted Payments”), unless, at the time of and after giving effect to such Restricted Payment:

(a) no Default or Event of Default has occurred and is continuing or would occur as a consequence of such Restricted Payment;

(b) the Issuer or such Restricted Subsidiary, as applicable, would, at the time of such Restricted Payment and after giving pro forma effect thereto as if such Restricted Payment had been made at the beginning of the applicable four-quarter period, have been permitted to incur at least $1.00 of additional Indebtedness pursuant to the Fixed Charge Coverage Ratio test set forth in the first paragraph of the covenant described below under the caption “—Certain Covenants—Incurrence of Indebtedness and Issuance of Preferred Stock”; and

(c) such Restricted Payment, together with the aggregate amount of all other Restricted Payments made by the Issuer and all Restricted Subsidiaries since the date of the Indenture (excluding Restricted Payments permitted by clauses (2), (3), (4), (5), (6), (7), (8) and (10) of the next succeeding paragraph), is less than the sum, without duplication, of:

(i) 50% of the Consolidated Net Income for the period (taken as one accounting period) from April 1, 2012 to the end of the Issuer’s most recently ended fiscal quarter for which internal financial statements are available at the time of such Restricted Payment (or, if such Consolidated Net Income for such period is a deficit, less 100% of such deficit); plus

(ii) 100% of the aggregate net cash proceeds and the Fair Market Value of property or securities other than cash (including Capital Stock of Persons engaged primarily in the Oil and Gas Business or assets used in the Oil and Gas Business), in each case received by the Issuer or any Restricted Subsidiary (other than from the Issuer or any Restricted Subsidiary) after the date of the Indenture (A) as a contribution to its common equity capital, (B) from the issue or sale of Equity Interests of the Issuer (other than Disqualified Stock and other than net cash proceeds received from an issuance or sale of such Equity Interests to a Subsidiary of the Issuer or an employee stock ownership plan, option plan or similar trust to the extent such sale to an employee stock ownership plan, option plan or similar trust is financed by loans from or Guaranteed by the Issuer or any Restricted Subsidiary (unless such loans have been repaid with cash on or prior to the date of determination)) or (C) upon the exercise after the Issue Date of any options, warrants or rights to purchase common stock of the Issuer; plus

(iii) to the extent not already included in Consolidated Net Income for such period or included in clause (v) below, if any Restricted Investment that was made by the Issuer or any Restricted Subsidiaries after the date of the Indenture is sold for cash (other than to the Issuer or any of its Restricted Subsidiaries) or otherwise cancelled, liquidated or repaid for cash, the cash return of capital with respect to such Restricted Investment resulting from such sale, liquidation or repayment (less any out-of-pocket costs incurred in connection with any such sale); plus

(iv) the amount by which Indebtedness or Disqualified Stock of the Issuer or the Restricted Subsidiaries incurred after the date of the Indenture is reduced on the Issuer’s consolidated balance sheet upon the conversion or exchange (other than by the Issuer or any Restricted Subsidiary) of any such Indebtedness or Disqualified Stock of the Issuer or the Restricted Subsidiaries convertible or exchangeable for Equity Interests (other than Disqualified Stock) of the Issuer (less the amount of any cash, or the Fair Market Value of any other property (other than such Equity Interests), distributed by the Issuer upon such conversion or exchange and excluding the net cash proceeds from the conversion or exchange financed, directly or indirectly, using funds borrowed from the Issuer or any Subsidiary), together with the net proceeds, if any, received by the Issuer or any Restricted Subsidiaries upon such conversion or exchange; plus

(v) to the extent that any Unrestricted Subsidiary designated as such after the date of the Indenture is redesignated as a Restricted Subsidiary pursuant to the terms of the Indenture or is merged or consolidated with or into, or transfers or otherwise disposes of all of substantially all of its properties or assets to or is liquidated into, the Issuer or a Restricted Subsidiary after the date of the Indenture, the lesser of, as of the date of such redesignation, merger, consolidation, transfer, disposition or liquidation, (A) the Fair Market Value of the Issuer’s (or any Restricted Subsidiary’s) Restricted Investment in such Subsidiary (or of the properties or assets disposed of, as applicable) as of the date of such redesignation, merger, consolidation, transfer, disposition or liquidation and (B) such Fair Market Value as of the date on which such Subsidiary was originally designated as an Unrestricted Subsidiary after the date of the Indenture.

The preceding provisions do not prohibit:

(1) the payment of any dividend within 60 days after the date of declaration of the dividend, if at the date of declaration or notice, the dividend would have complied with the provisions of the Indenture;

(2) the making of any Restricted Payment in exchange for, or out of or with the net cash proceeds of the substantially concurrent sale (other than to a Subsidiary of the Issuer) of, Equity Interests of the Issuer (other than Disqualified Stock), with a sale being deemed substantially concurrent if such Restricted Payment occurs not more than 180 days after such sale, or from the substantially concurrent contribution of common equity capital to the Issuer; provided that the amount of any such net cash proceeds that are utilized for any such Restricted Payment will not be considered to be net proceeds of Equity Interests for purposes of clause (c)(ii) of the preceding paragraph and will not be considered to be net cash proceeds from an Equity Offering for purposes of the “Optional Redemption” provisions of the Indenture;

(3) the repurchase, redemption, defeasance or other acquisition or retirement for value of any Existing Preferred Stock or Disqualified Stock with the net cash proceeds from a substantially concurrent incurrence of Permitted Refinancing Indebtedness or Indebtedness incurred pursuant to the first paragraph of the covenant described below under the caption “—Certain Covenants—Incurrence of Indebtedness and Issuance of Preferred Stock,” with a sale being deemed substantially concurrent if such repurchase, redemption, defeasance or other acquisition or retirement for value occurs not more than 35 days after such sale;

(4) the repurchase, redemption, defeasance or other acquisition or retirement for value of Indebtedness of the Issuer or any Guarantor that is contractually subordinated to the notes or to any Note Guarantee with the net cash proceeds from a substantially concurrent incurrence of Permitted Refinancing Indebtedness;

(5) so long as no Default or Event of Default has occurred and is continuing, the repurchase, redemption or other acquisition or retirement for value of any Equity Interests of the Issuer or any Restricted Subsidiary, whether upon the exercise or conversion of stock appreciation rights, restricted stock, unit options, restricted units, phantom units, warrants, incentives, rights to acquire Equity Interests or other derivative securities of such Equity Interests or otherwise, held by any current or former officer, director, member of management, consultant or employee (or their transferees, estates or beneficiaries under their estates) of the Issuer or any Restricted Subsidiary pursuant to any equity subscription agreement, stock option agreement, shareholders’ agreement, employment agreement or similar agreement; provided that the aggregate price paid for all such repurchased, redeemed, acquired or retired Equity Interests may not exceed $4.0 million in any consecutive twelve‑month period, plus, to the extent not previously applied or included,

(a) the cash proceeds received by the Issuer or any of its Restricted Subsidiaries from sales of Equity Interests of the Issuer to officers, directors, members of management, consultants or employees of the Issuer or its Affiliates that occur after the date of the Indenture (to the extent the cash proceeds from the sale of such Equity Interests have not otherwise been applied to make Restricted Payments by virtue of clause (c)(2) of the first paragraph of this covenant); and

(b) the cash proceeds of key man life insurance policies received by the Issuer or any of its Restricted Subsidiaries after the date of the Indenture;

(6) the repurchase of Equity Interests deemed to occur upon the exercise or conversion of stock appreciation rights, restricted stock, unit options, restricted units, phantom units, warrants, incentives, rights to acquire Equity Interests or other derivative securities of such Equity Interests to the extent such Equity Interests represent a portion of the exercise price thereof and any repurchase or other acquisition of any of the foregoing made in lieu of withholding taxes in connection therewith;

(7) so long as no Default or Event of Default has occurred and is continuing or would be caused thereby, the declaration and payment of regularly scheduled or accrued dividends to holders of any class or series of Disqualified Stock of the Issuer or any Preferred Stock of the Issuer or any Restricted Subsidiary (a) issued prior to the date of the Indenture, (b) issued on or after the date of the Indenture and (c) (i) with respect to Series D Capital Stock, in an aggregate amount not to exceed the maximum amount thereof permitted to be issued in accordance with the certificate of designation with

respect thereto in effect on the date of the Indenture and (ii) otherwise in accordance with the covenant described below under the caption “—Certain Covenants—Incurrence of Indebtedness and Issuance of Preferred Stock”;

(8) payments of cash, dividends, distributions, advances or other Restricted Payments by the Issuer or any Restricted Subsidiary to allow the payment of cash in lieu of the issuance of fractional shares upon (a) the exercise of options or warrants or (b) the conversion or exchange of Capital Stock of any such Person;

(9) the repayment, redemption, repurchase, defeasance or other acquisition or retirement for value of any subordinated Indebtedness, Preferred Stock or Disqualified Stock at a purchase price not greater than (a) 101% of the principal amount thereof or liquidation preference in the event of a change of control pursuant to a provision no more favorable to the holders than “Repurchase at the Option of the Holders—Change of Control” or (b) 100% of the principal amount thereof or liquidation preference in the event of an Asset Sale, in each case plus accrued and unpaid interest thereon, in connection with any change of control offer or asset sale offer required by the terms of such Indebtedness, Preferred Stock or Disqualified Stock, but only if:

(i) in the case of a Change of Control, the Issuer has complied with and satisfied its obligations as described under “—Repurchase at the Option of the Holders—Change of Control”; provided that, prior to the making of any such Restricted Payment pursuant to clause (9)(a), the Issuer shall have made a Change of Control Offer and repurchased all notes issued under the Indenture that were properly tendered for payment in connection with such offer to purchase; and

(ii) in the case of an Asset Sale, the Issuer has complied with and satisfied its obligations as described under “—Repurchase at the option of the holders—Asset Sales”;

(10) so long as no Default or Event of Default has occurred and is continuing or would be caused thereby, the declaration or payment of any dividends or other distributions of Equity Interests of Eureka Pipeline in an aggregate amount not to exceed $50.0 million; or

(11) so long as no Default or Event of Default has occurred and is continuing or would be caused thereby, other Restricted Payments in an aggregate amount not to exceed $30.0 million since the date of the Indenture.

The amount of all Restricted Payments (other than cash) will be the Fair Market Value on the date of the Restricted Payment (or, in the case of a dividend, on the date of declaration) of the asset(s) or securities proposed to be transferred or issued by the Issuer or such Restricted Subsidiary, as the case may be, pursuant to the Restricted Payment. The Fair Market Value of any assets or securities that are required to be valued by this covenant will be determined, in the case of amounts under $25.0 million, by an officer of the Issuer and, in the case of amounts of $25.0 million or more, by the Board of Directors of the Issuer whose resolution with respect thereto will be delivered to the trustee.

For purposes of determining compliance with the “Restricted Payments” covenant, in the event that a Restricted Payment meets the criteria of more than one of the categories of Restricted Payments described in the preceding clauses (1) through (11) or as a Permitted Investment, the Issuer will be permitted to classify (or later reclassify in its sole discretion) such Restricted Payment or Permitted Investment in any manner that complies with this covenant and such Restricted Payment or Permitted Investment shall be treated as having been made pursuant to only one of such clauses of this covenant or of the definition of “Permitted Investment.”

Incurrence of Indebtedness and Issuance of Preferred Stock

The Issuer will not, and will not permit any Restricted Subsidiary to, directly or indirectly, create, incur, issue, assume, Guarantee or otherwise become directly or indirectly liable, contingently or otherwise, with respect to (collectively, “incur”) any Indebtedness (including Acquired Debt), and the Issuer will not issue any Disqualified Stock and the Issuer will not, and will not permit any Restricted Subsidiary to issue any Preferred Stock; provided, however, that the Issuer may incur Indebtedness (including Acquired Debt) or issue Disqualified Stock, and the Issuer and the Guarantors may incur Indebtedness (including Acquired Debt) or issue Preferred Stock, if the Fixed Charge Coverage Ratio for the Issuer’s most recently ended four full fiscal quarters for which internal financial statements are available immediately preceding the date on which such additional Indebtedness is incurred or such Disqualified Stock or such Preferred Stock is issued, as the case may be, would have been at least 2.25 to 1.0, determined on a pro forma basis (including a pro forma application of the net proceeds therefrom), as if the additional Indebtedness had been incurred or the Disqualified Stock or the Preferred Stock had been issued, as the case may be, at the beginning of such four-quarter period.

The first paragraph of this covenant does not prohibit the incurrence of any of the following items of Indebtedness or issuances of Disqualified Stock or Preferred Stock, as applicable (collectively, “Permitted Debt”):

(1) the incurrence by the Issuer and any Guarantor of additional Indebtedness and letters of credit under Credit Facilities in an aggregate principal amount at any one time outstanding under this clause (1) (with letters of credit being deemed to have a principal amount equal to the maximum potential liability of the Issuer and any Guarantor thereunder) not to exceed (i) the greater of (A) $300.0 million and (B) 25% of the Issuer’s Adjusted Consolidated Net Tangible Assets determined on the date of such incurrence;

(2) the incurrence by the Issuer or its Restricted Subsidiaries of the Existing Indebtedness (other than as described in clause (1) or (3));

(3) the incurrence by the Issuer and the Guarantors of Indebtedness represented by (a) the notes and the related Note Guarantees issued on or after the date of the Indenture and (b) any Exchange Notes issued in exchange for such notes (including any Guarantee thereof);

(4) the incurrence by the Issuer or any Restricted Subsidiary of Indebtedness represented by Capital Lease Obligations, mortgage financings or purchase money obligations, in each case, incurred for the purpose of financing all or any part of the purchase price or cost of design, construction, installation, repair or improvement of property, plant or equipment used in the business of the Issuer or any Restricted Subsidiary and related financing costs, and Attributable Debt in respect of sale and leaseback transactions, in an aggregate principal amount, including all Permitted Refinancing Indebtedness incurred to renew, refund, refinance, replace, defease or discharge any Indebtedness incurred pursuant to this clause (4), not to exceed at any time outstanding the greater of (A) $25.0 million and (B) 2.0% of Adjusted Consolidated Net Tangible Assets;

(5) the incurrence by the Issuer or any Restricted Subsidiary of Permitted Refinancing Indebtedness in exchange for, or the net proceeds of which are used to renew, refund, refinance, replace, defease or discharge any Indebtedness (other than intercompany Indebtedness) or Disqualified Stock that was permitted by the Indenture to be incurred under the first paragraph of this covenant or clause (2), (3), (4), (5) or (17) of this paragraph;

(6) the incurrence by the Issuer or any Restricted Subsidiary of intercompany Indebtedness between or among the Issuer and any Restricted Subsidiary; provided, however, that:

(a) if the Issuer or any Guarantor is the obligor on such Indebtedness and the payee is not the Issuer or a Guarantor, such Indebtedness must be unsecured and expressly subordinated to the prior payment in full in cash of all Obligations then due with respect to the notes, in the case of the Issuer, or the Note Guarantee, in the case of a Guarantor; and

(b) (i) any subsequent issuance or transfer of Equity Interests that results in any such Indebtedness being held by a Person other than the Issuer or any Restricted Subsidiary and (ii) any sale or other transfer of any such Indebtedness to a Person that is not either the Issuer or any Restricted Subsidiary, will be deemed, in each case, to constitute an incurrence of such Indebtedness by the Issuer or such Restricted Subsidiary, as the case may be, that was not permitted at the time of such sale or transfer by this clause (6);

(7) the issuance by any Restricted Subsidiary to the Issuer or to any Restricted Subsidiary of any Preferred Stock; provided, however, that:

(a) any subsequent issuance or transfer of Equity Interests that results in any such Preferred Stock being held by a Person other than the Issuer or any Restricted Subsidiary; and

(b) any sale or other transfer of any such Preferred Stock to a Person that is not the Issuer or any Restricted Subsidiary, will be deemed, in each case, to constitute an issuance of such Preferred Stock by such Restricted Subsidiary that was not permitted at the time of such sale or transfer by this clause (7);

(8) the incurrence by the Issuer or any Restricted Subsidiary of Hedging Obligations in the ordinary course of business or customary in the Oil and Gas Business;

(9) the Guarantee by the Issuer or any Restricted Subsidiary of Indebtedness of the Issuer or any Restricted Subsidiary to the extent that the guaranteed Indebtedness was permitted to be incurred by another provision of this covenant; provided that if the Indebtedness being guaranteed is subordinated to or pari passu with the notes, then the Guarantee must be subordinated or pari passu, as applicable, to the same extent as the Indebtedness guaranteed;

(10) the incurrence by the Issuer or any Restricted Subsidiary of Indebtedness in respect of self-insurance obligations or the financing of insurance premiums, or bid, plugging and abandonment, appeal, reimbursement, performance, surety and similar bonds and completion guarantees provided by the Issuer or a Restricted Subsidiary in the ordinary course of business or customary in the Oil and Gas Business and any Guarantees or letters of credit functioning as or supporting any of the foregoing bonds or obligations and workers’ compensation claims in the ordinary course of business;

(11) the incurrence by the Issuer or any Restricted Subsidiary of Indebtedness arising from the honoring by a bank or other financial institution of a check, draft or similar instrument inadvertently drawn against insufficient funds, so long as such Indebtedness is covered within five business days;

(12) the incurrence by the Issuer or any Restricted Subsidiary of Permitted Acquisition Indebtedness;

(13) the incurrence by the Issuer or any Restricted Subsidiary of take or pay agreements or in-kind obligations relating to net oil or natural gas balancing positions arising in the ordinary course of business or customary in the Oil and Gas Business;

(14) any obligation arising from agreements of the Issuer or any Restricted Subsidiary providing for indemnification, adjustment of purchase price, earn outs, or similar obligations, in each case, incurred or assumed in connection with the disposition of any business, assets or Capital Stock of a Restricted Subsidiary in a transaction permitted by the Indenture, provided the maximum assumable liability in respect of all such Indebtedness shall at no time exceed the gross proceeds, including non-cash proceeds (the fair market value of such non-cash proceeds being measured at the time received and without giving effect to any subsequent changes in value), actually received by the Issuer and any Restricted Subsidiaries in connection with such disposition;

(15) the incurrence by the Issuer or any of its Restricted Subsidiaries of Indebtedness constituting reimbursement obligations with respect to letters of credit; provided that, upon the drawing of such letters of credit, such obligations are reimbursed within 5 business days of such drawing;

(16) the incurrence by any Foreign Subsidiary of Indebtedness that, in the aggregate together with all other Indebtedness of all Foreign Subsidiaries, including all Permitted Refinancing Indebtedness incurred to extend, renew, refund, refinance, replace, defease, discharge or otherwise retire for value any Indebtedness incurred pursuant to this clause (16), does not exceed the greater of (a) $25.0 million and (b) 15% of the Adjusted Consolidated Net Tangible Assets of all Foreign Subsidiaries, considered as a consolidated enterprise, determined as of the date of the incurrence of such Indebtedness after giving pro forma effect to such incurrence and the application of the proceeds therefrom; and

(17) the incurrence by the Issuer or any Guarantor of additional Indebtedness or the issuance by the Issuer of any Disqualified Stock or Preferred Stock in an aggregate principal amount (or accreted value, as applicable), including all Permitted Refinancing Indebtedness incurred to renew, refund, refinance, replace, defease or discharge any Indebtedness incurred or Disqualified Stock or Preferred Stock issued pursuant to this clause (17), not to exceed at any time outstanding the greater of (i) $35.0 million and (ii) 2.0% of Adjusted Consolidated Net Tangible Assets determined as of the date of such incurrence or issuance.

The Issuer will not, and will not permit any Guarantor to, incur any Indebtedness (including Permitted Debt) that is contractually subordinated in right of payment to any other Indebtedness of the Issuer or such Guarantor unless such Indebtedness is also contractually subordinated in right of payment to the notes or the applicable Note Guarantee on substantially identical terms; provided, however, that no Indebtedness will be deemed to be contractually subordinated in right of payment to any other Indebtedness of the Issuer or any Guarantor solely by virtue of being unsecured or by virtue of being secured on a junior priority basis.

For purposes of determining compliance with this “Incurrence of Indebtedness and Issuance of Preferred Stock” covenant, in the event that an item of Indebtedness meets the criteria of more than one of the categories of Permitted Debt described in clauses (1) through (17) above, or is entitled to be incurred pursuant to the first paragraph of this covenant, the Issuer will be permitted to divide, classify and reclassify such item of Indebtedness on the date of its incurrence, or later redivide or reclassify all or a portion of such item of Indebtedness, in any manner that complies with this covenant. Indebtedness under Credit Facilities outstanding on the date on which notes were first issued and authenticated under the Indenture is deemed to have been incurred on such date in reliance on the exception provided by clause (1) of the definition of Permitted Debt. The accrual of interest or Preferred Stock dividends, the accretion or amortization of original issue discount, the payment of interest on any Indebtedness not secured by a Lien in the form of additional Indebtedness with the same terms, the reclassification of Preferred Stock as Indebtedness due to a change in accounting principles, and the payment of dividends on Preferred Stock or Disqualified Stock in the form of additional securities of the same class of Preferred Stock or Disqualified Stock will not be deemed to be an incurrence of Indebtedness or an issuance of Preferred Stock or Disqualified Stock for purposes of this covenant; provided that the amount thereof is included in Fixed Charges as accrued to the extent required by the definition of such term.

The amount of any Indebtedness outstanding as of any date will be:

(1) the accreted value of the Indebtedness, in the case of any Indebtedness issued with original issue discount;

(2) the principal amount of the Indebtedness, in the case of any other Indebtedness; and

(3) in respect of Indebtedness of another Person secured by a Lien on the assets of the specified Person, the lesser of:

(a) the Fair Market Value of such assets at the date of determination; and

(b) the amount of the related Indebtedness of the other Person.

Liens

The Issuer will not, and will not permit any Restricted Subsidiary to, create, incur, assume or otherwise cause or permit to exist or become effective any Lien of any kind (other than Permitted Liens) securing Indebtedness (including Attributable Debt)

upon any of their property or assets, now owned or hereafter acquired, unless all payments due to the holders under the Indenture and the notes are secured on an equal and ratable basis with the obligations so secured until such time as such obligations are no longer secured by a Lien.

Any Lien on any assets of the Issuer or any Restricted Subsidiary created for the benefit of the holders of the notes pursuant to the preceding paragraph shall provide by its terms that such Lien shall be automatically and unconditionally released and discharged at such time as there are no other Liens of any kind (other than Permitted Liens) on such assets securing Indebtedness.

Dividend and Other Payment Restrictions Affecting Restricted Subsidiaries

The Issuer will not, and will not permit any Restricted Subsidiary to, directly or indirectly, create or permit to exist or become effective any consensual encumbrance or restriction on the ability of any Restricted Subsidiary to:

(1) pay dividends or make any other distributions on its Capital Stock to the Issuer or any Restricted Subsidiary, or with respect to any other interest or participation in, or measured by, its profits, or pay any indebtedness owed to the Issuer or any Restricted Subsidiary; provided that the priority that any series of Preferred Stock of a Restricted Subsidiary has in receiving dividends or liquidating distributions before dividends or liquidating distributions are paid in respect of common stock of such Restricted Subsidiary shall not constitute a restriction on the ability to make dividends or distributions on Capital Stock for purposes of this covenant;

(2) make loans or advances to the Issuer, or any Restricted Subsidiary; or

(3) sell, lease or transfer any of its properties or assets to the Issuer or any Restricted Subsidiary.

However, the preceding restrictions do not apply to encumbrances or restrictions existing under or by reason of:

(1) agreements governing Existing Indebtedness as in effect on the date of the Indenture and any amendments, restatements, modifications, renewals, supplements, refundings, replacements or refinancings of those agreements; provided that the amendments, restatements, modifications, renewals, supplements, refundings, replacements or refinancings are not materially more restrictive, taken as a whole, with respect to such dividend and other payment restrictions than those contained in those agreements on the date of the Indenture, as determined in good faith by the Issuer;

(2) the Indenture, the notes, the Note Guarantees, the Exchange Notes and any Guarantees thereof, or any other indentures governing debt securities issued by the Issuer or any Guarantor that are not materially more restrictive, taken as a whole, with respect to dividend, distribution or other payment restrictions and loan or investment restrictions than those contained in the Indenture, notes and the Guarantors’ Note Guarantees as in effect on the date of the Indenture as determined in good faith by the Issuer;

(3) agreements governing other Indebtedness permitted to be incurred under the provisions of the covenant described above under the caption “—Certain Covenants—Incurrence of Indebtedness and Issuance of Preferred Stock” and any amendments, restatements, modifications, renewals, supplements, refundings, replacements or refinancings of those agreements; provided that the restrictions therein are not materially more restrictive, taken as a whole, than those contained in the Indenture, the notes and the Note Guarantees or the MHR Senior Revolving Credit Facility as in effect on the date of the Indenture, as determined in good faith by the Issuer;

(4) applicable law, rule, regulation, order, approval, governmental license, permit or similar restriction;

(5) any instrument governing Indebtedness or Capital Stock of a Person acquired by the Issuer or any Restricted Subsidiary as in effect at the time of such acquisition (except to the extent such Indebtedness or Capital Stock was incurred in connection with or in contemplation of such acquisition), which encumbrance or restriction is not applicable to any Person, or the properties or assets of any Person, other than the Person, or the property or assets of the Person, so acquired; provided that, in the case of Indebtedness, such Indebtedness was permitted by the terms of the Indenture to be incurred;

(6) customary non-assignment provisions in Hydrocarbon purchase and sale or exchange agreements, joint operating agreements or similar operational agreements or contracts or in licenses, easements or leases, in each case, entered into in the ordinary course of business or customary in the Oil and Gas Business;

(7) mortgage financings and purchase money obligations for property acquired in the ordinary course of business or customary in the Oil and Gas Business and Capital Lease Obligations that impose restrictions on the property purchased or leased of the nature described in clause (3) of the preceding paragraph;

(8) any agreement for the sale or other disposition of a Restricted Subsidiary that restricts distributions by that Restricted Subsidiary or sales of such Restricted Subsidiary’s assets pending its sale or other disposition;

(9) Permitted Refinancing Indebtedness; provided that the restrictions contained in the agreements governing such Permitted Refinancing Indebtedness are not materially more restrictive, taken as a whole, than those contained in the agreements governing the Indebtedness being refinanced, as determined in good faith by the Issuer;

(10) Liens permitted to be incurred under the provisions of the covenant described above under the caption “—Certain Covenants—Liens” that limit the right of the debtor to dispose of the assets subject to such Liens;

(11) provisions limiting the disposition, leasing, subleasing or distribution of assets or property in joint venture agreements, asset sale agreements, sale-leaseback agreements, stock sale agreements, farm-in and farm-out agreements and other similar agreements (including agreements entered into in connection with a Restricted Investment) entered into (a) in the ordinary course of business or customary in the Oil and Gas Business or (b) with the approval of the Issuer’s Board of Directors, in each case, which limitation is applicable only to the assets that are the subject of such agreements;

(12) encumbrances or restrictions on cash, Cash Equivalents or other deposits or net worth imposed by customers under contracts entered into in the ordinary course of business or customary in the Oil and Gas Business;

(13) encumbrances or restrictions of the nature described in clause (3) of the preceding paragraph contained in agreements or instruments described in the definition of “Permitted Business Investments” or governing any Permitted Acquisition Indebtedness, so long as such agreement or instrument (a) was not entered into in contemplation of the acquisition, merger or consolidation transaction related thereto and (b) is not applicable to any Person, or the assets of any Person, other than the Person, or the assets or Subsidiaries of the Person, subject to such acquisition, merger or consolidation, so long as the agreement containing such restriction does not violate any other provisions of the Indenture;

(14) any agreement or instrument relating to any property or assets acquired after the date of the Indenture, so long as such encumbrance or restriction relates only to the property or assets so acquired and is not and was not created in anticipation of such acquisitions; and

(15) Hedging Obligations incurred from time to time.

Merger, Consolidation or Sale of All or Substantially All Assets

(a) The Issuer may not, directly or indirectly, (1) consolidate or merge with or into another Person (whether or not the Issuer is the survivor), or (2) sell, assign, transfer, convey, lease or otherwise dispose of all or substantially all of its properties or assets, in one or more related transactions, to another Person, unless:

(1) either: (a) the Issuer is the surviving Person; or (b) the Person formed by or surviving any such consolidation or merger (if other than the Issuer) or to which such sale, assignment, transfer, lease, conveyance or other disposition has been made is an entity organized or existing under the laws of the United States, any state of the United States or the District of Columbia;

(2) the Person formed by or surviving any such consolidation or merger (if other than the Issuer) or the Person to which such sale, assignment, transfer, lease, conveyance or other disposition has been made assumes all the obligations of the Issuer under the notes, the Indenture and the Registration Rights Agreements pursuant to agreements reasonably satisfactory to the trustee;

(3) immediately after such transaction, no Default or Event of Default exists;

(4) except in the case of a consolidation or merger of the Issuer with or into a Guarantor, or a sale, assignment, transfer, conveyance, lease or other disposal to a Guarantor, immediately after giving effect to such transaction and any related financing transaction on a pro forma basis as if the same had occurred at the beginning of the applicable four-quarter period, either:

(a) the Issuer would be permitted to incur at least $1.00 of additional Indebtedness pursuant to the Fixed Charge Coverage Ratio test set forth in the first paragraph of the covenant described above under the caption “—Certain Covenants—Incurrence of Indebtedness and Issuance of Preferred Stock”; or

(b) the Fixed Charge Coverage Ratio of the Issuer is equal to or greater than the Fixed Charge Coverage Ratio of the Issuer immediately prior to such transaction; and

(5) the Issuer has delivered to the trustee an officers’ certificate and an opinion of counsel, each stating that such consolidation, merger or disposition and such supplemental indenture, if any, comply with the Indenture.

The above do not apply to any sale, assignment, transfer, conveyance, lease or other disposition of assets by any Restricted Subsidiary to the Issuer. Clauses (3) and (4) above do not apply to (1) any merger or consolidation of any Restricted Subsidiary into the Issuer or (2) any merger or consolidation of the Issuer with or into an Affiliate solely for the purpose of reorganizing the Issuer in another jurisdiction.

(b) A Guarantor may not sell or otherwise dispose of, in one or more related transactions, all or substantially all of its properties or assets to, or consolidate with or merge with or into (whether or not such Guarantor is the surviving Person) another Person, other than the Issuer or another Guarantor, unless:

(1) immediately after giving effect to such transaction or series of transactions, no Default or Event of Default exists; and

(2) either:

(a) (i) in the case of a consolidation or merger, the Guarantor is the surviving Person or

(ii) the Person acquiring the properties or assets in any such sale or other disposition or the Person formed by or surviving any such consolidation or merger (if other than the Guarantor) unconditionally assumes all the obligations of that Guarantor under its Note Guarantee and the Indenture pursuant to a supplemental indenture in form reasonably satisfactory to the trustee; or

(b) such transaction or series of transactions does not violate the “Asset Sale” provisions of the Indenture.

Notwithstanding the foregoing, any Guarantor may (A) consolidate with, merge into or sell, assign, transfer, convey, lease or otherwise dispose of all or part of its properties and assets to the Issuer or to another Guarantor or (B) dissolve, liquidate or windup its affairs if at that time it does not hold any material assets.

Transactions with Affiliates

The Issuer will not, and will not permit any Restricted Subsidiary to, make any payment to, or sell, lease, transfer or otherwise dispose of any of its properties or assets to, or purchase any property or assets from, or enter into or make or amend any transaction, contract, agreement, understanding, loan, advance or guarantee with, or for the benefit of, any Affiliate of the Issuer (each, an “Affiliate Transaction”), unless:

(1) the Affiliate Transaction is on terms that are no less favorable to the Issuer or the relevant Restricted Subsidiary (as applicable) than those that would have been obtained in a comparable transaction by the Issuer or such Restricted Subsidiary with an unrelated Person; and

(2) the Issuer delivers to the trustee:

(a) with respect to any Affiliate Transaction or series of related Affiliate Transactions involving aggregate consideration in excess of $20.0 million, a resolution of the Board of Directors of the Issuer set forth in an officers’ certificate certifying that such Affiliate Transaction or series of related Affiliated Transactions complies with this covenant and that such Affiliate Transaction or series of related Affiliate Transactions has been approved by a majority of the disinterested members of the Board of Directors of the Issuer, if any; and

(b) with respect to any Affiliate Transaction or series of related Affiliate Transactions involving aggregate consideration in excess of $35.0 million, an opinion as to the fairness to the Issuer or such Restricted Subsidiary of such Affiliate Transaction or series of related Affiliate Transactions from a financial point of view issued by an accounting, appraisal or investment banking firm of national standing.

The following items are not deemed to be Affiliate Transactions and, therefore, are not subject to the provisions of the prior paragraph:

(1) any employment or consulting agreement, employee benefit plan, stock ownership or stock option plan, officer or director indemnification, compensation or severance agreement or any similar arrangement existing on the date of the Indenture and any entered into thereafter by the Issuer or any Restricted Subsidiary in the ordinary course of business or customary in the Oil and Gas Business and payments, awards, grants or issuances pursuant thereto;

(2) loans or advances to employees of the Issuer or any Restricted Subsidiary made in the ordinary course of business in an aggregate principal amount not to exceed $2.0 million at any one time outstanding;

(3) transactions between or among the Issuer and one or more Restricted Subsidiaries (or any entity that becomes a Restricted Subsidiary as a result of such transaction);

(4) transactions with a Person (other than an Unrestricted Subsidiary of the Issuer) that is an Affiliate of the Issuer solely because the Issuer owns, directly or indirectly, an Equity Interest in, or otherwise controls, such Person;

(5) payment of customary fees and reimbursements of expenses and other benefits (pursuant to indemnity arrangements or otherwise) of officers, directors, employees or consultants of the Issuer, any Restricted Subsidiary or an Affiliate of the Issuer, including provisions of officers’ and directors’ liability insurance;

(6) any issuance of Equity Interests (other than Disqualified Stock) of the Issuer to, or receipt of capital contributions from, Affiliates of the Issuer;

(7) Permitted Investments or Restricted Payments that do not violate the provisions of the Indenture described above under the caption “—Certain Covenants—Restricted Payments,” including any transaction that would constitute a Restricted Payment but for the exclusions from the definition thereof;

(8) any transaction between the Issuer or any of its Restricted Subsidiaries and any Person that would not otherwise constitute an Affiliate Transaction except for the fact that one director of such other Person is also a director of the Issuer or such Restricted Subsidiary, as applicable; provided that such director abstains from voting as a director of the Issuer or such Restricted Subsidiary, as applicable, on any matter involving such other Person;

(9) pledges by the Issuer or any Restricted Subsidiary of the Issuer of Equity Interests in Unrestricted Subsidiaries for the benefit of lenders or other creditors of the Issuer’s Unrestricted Subsidiaries;

(10) transactions effected, and payments made, in accordance with the terms of the agreements as such agreements are in effect on the date of the Indenture and, except in the case of agreements entered into during any time that this covenant is suspended in accordance with the terms of the Indenture, described in the Issuer’s Annual Report on Form 10-K for the fiscal year ended December 31, 2011, as amended, under the caption “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Related Party Transactions” and, in each case, any amendment or replacement of any of such agreements so long as such amendment or replacement agreement is not materially more disadvantageous, taken as a whole, to the holders of the notes than the agreement so amended or replaced, as determined in good faith by the Board of Directors of the Issuer;

(11) transactions with Unrestricted Subsidiaries, customers, clients, suppliers or purchasers or sellers of goods or services, or lessors or lessees of property, in each case in the ordinary course of business and otherwise in compliance with the terms of the Indenture (a) which are, in the aggregate (taking into account all the costs and benefits associated with such transactions), not materially less favorable to the Issuer and its Restricted Subsidiaries than those that would have been obtained in a comparable transaction by the Issuer or such Restricted Subsidiary with a Person that is not an Affiliate, in the reasonable determination of the Board of Directors of the Issuer or the senior management thereof, or are on terms at least as favorable as might reasonably have been obtained at such time from a Person that is not an Affiliate and (b) with respect to which the Issuer has complied with clause (2)(a) or (2)(b) of the prior paragraph; and

(12) in the case of contracts for exploring for, producing, marketing, storing, treating or otherwise handling, gathering, processing or transporting Hydrocarbons, or activities or services reasonably related or ancillary thereto, or other operational contracts, any such contracts entered into in the ordinary course of business or customary in the Oil and Gas Business and otherwise in compliance with the terms of the Indenture (a) which are fair to the Issuer or any Restricted Subsidiary, in the reasonable determination of the Board of Directors of the Issuer or the senior management thereof, or are on terms at least as favorable as might reasonably have been obtained at such time from a Person that is not an Affiliate and (b) with respect to which the Issuer has complied with clause (2)(a) or (2)(b) of the prior paragraph.

Additional Note Guarantees

The Issuer will not permit any of its Restricted Subsidiaries that are not then Guarantors to either (a) guarantee the payment of any Indebtedness of the Issuer or any other Guarantor or (b) incur any Indebtedness, in each case, under any Credit Facility pursuant to clause (1) of the second paragraph under the covenant described under the caption “Certain Covenants—Incurrence of Indebtedness and Issuance of Preferred Stock,” in each case, unless such Subsidiary becomes a Guarantor by executing a supplemental indenture and a joinder or supplement to the Registration Rights Agreements and delivering an opinion of counsel reasonably satisfactory to the trustee within 30 business days after the date that Subsidiary was acquired or created or on which it guaranteed such Indebtedness; provided, however that this covenant does not apply with respect to any Restricted Subsidiary that, on the date of the Indenture, was a Foreign Subsidiary that guarantees the payment of any Indebtedness of the Issuer under any Credit Facility pursuant to clause (1) of the second paragraph under the covenant described under the caption “Certain Covenants—Incurrence of Indebtedness and Issuance of Preferred Stock.” The Issuer may elect, in its sole discretion, to cause any Subsidiary that is not otherwise required to be a Guarantor to become a Guarantor.

Designation of Restricted and Unrestricted Subsidiaries

On the date hereof, Eureka Holdings, Eureka Pipeline, Eureka Hunter Land, LLC, Energy Hunter Securities, Inc., Magnum Hunter Midstream, LLC, Magnum Hunter Services, LLC, MHR Callco Corporation, MHR Exchangeco Corporation, Triad Hunter Gathering, LLC, TransTex Hunter, Sentra Corporation, Williston Hunter Canada, Inc. (formerly known as Nuloch Resources, Inc.) and 54NG, LLC are Unrestricted Subsidiaries. The Board of Directors of the Issuer may designate any Restricted Subsidiary to be an Unrestricted Subsidiary if that designation would not cause a Default. If a Restricted Subsidiary is designated as an Unrestricted Subsidiary, the aggregate Fair Market Value of all outstanding Investments owned by the Issuer or the Restricted Subsidiaries in the Subsidiary designated as an Unrestricted Subsidiary will be deemed to be either an Investment made as of the time of the designation that will reduce the amount available for Restricted Payments under the covenant described above under the caption “—Certain Covenants—Restricted Payments” or represent a Permitted Investment under one or more clauses of the definition of Permitted

Investments, as determined by the Issuer. That designation will only be permitted if the Investment would be permitted at that time and if the Restricted Subsidiary otherwise meets the definition of an Unrestricted Subsidiary.

Any designation of a Subsidiary of the Issuer as an Unrestricted Subsidiary will be evidenced to the trustee by filing with the trustee a certified copy of a resolution of the Board of Directors giving effect to such designation and an officers’ certificate certifying that such designation complied with the preceding conditions and was permitted by the covenant described above under the caption “—Certain Covenants—Restricted Payments.” If, at any time, any Unrestricted Subsidiary would fail to meet the preceding requirements as an Unrestricted Subsidiary, it will thereafter cease to be an Unrestricted Subsidiary for purposes of the Indenture and any Indebtedness of such Subsidiary will be deemed to be incurred by a Restricted Subsidiary as of such date and, if such Indebtedness is not permitted to be incurred as of such date under the covenant described under the caption “—Certain Covenants—Incurrence of Indebtedness and Issuance of Preferred Stock,” the Issuer will be in default of such covenant.

The Board of Directors of the Issuer may at any time designate any Unrestricted Subsidiary to be a Restricted Subsidiary; provided that such designation will be deemed to be an incurrence of Indebtedness by a Restricted Subsidiary of any outstanding Indebtedness of such Unrestricted Subsidiary, and such designation will only be permitted if (1) such Indebtedness is permitted under the covenant described under the caption “—Certain Covenants—Incurrence of Indebtedness and Issuance of Preferred Stock,” calculated on a pro forma basis as if such designation had occurred at the beginning of the applicable reference period; and (2) no Default or Event of Default would be in existence following such designation.

Reports

The Indenture provides that, whether or not the Issuer is subject to the reporting requirements of Section 13 or Section 15(d) of the Exchange Act, to the extent not prohibited by the Exchange Act, the Issuer will file with the SEC, and make available to the trustee and the holders of the notes without cost to any holder, the annual reports and the information, documents and other reports (or copies of such portions of any of the foregoing as the SEC may by rules and regulations prescribe) that are specified in Sections 13 and 15(d) of the Exchange Act and applicable to a U.S. corporation within five business days following the time periods specified therein. In the event that the Issuer is not permitted to file such reports, documents and information with the SEC pursuant to the Exchange Act, the Issuer will nevertheless make available such Exchange Act information to the trustee and the holders of the notes without cost to any holder as if the Issuer were subject to the reporting requirements of Section 13 or 15(d) of the Exchange Act within the time periods specified therein with respect to a non-accelerated filer by posting such information on a freely accessible page of its website.

The Issuer will be deemed to have furnished such reports and other information to the trustee and the holders of notes if it has filed such reports and other information with the SEC using the EDGAR filing system (or any successor filing system) or, if such system is not available to the Issuer, if it has filed such reports and other information on a freely accessible page of its website, and in each case, such reports and other information are publicly available thereon.

In addition, to the extent not satisfied by the foregoing, the Issuer agrees that, for so long as any notes are outstanding, it will furnish to holders of the notes and to securities analysts and prospective investors, upon their request, the information required to be delivered pursuant to Rule 144A(d)(4) under the Securities Act.

If at any time the Issuer is not subject to the reporting requirements of Section 13 or Section 15(d) of the Exchange Act, then the Issuer shall hold quarterly conference calls that are publicly accessible within 5 business days after the Issuer’s earnings for the prior fiscal period have been made available to its stockholders, beginning when earnings for the quarter ended June 30, 2012 have been made available pursuant to this covenant. To the extent applicable, no fewer than three business days prior to the date of each such conference call, the Issuer shall issue a press release to an appropriate U.S. wire service announcing the time, the date of and access information related to such conference call. The trustee shall have no responsibility for determining whether or not such conference calls have been held.

Events of Default and Remedies

Each of the following is an “Event of Default”:

(1) default for 30 days in the payment when due of interest and Additional Interest, if any, on the notes;

(2) default in the payment when due (at stated maturity, upon redemption or otherwise) of the principal of, or premium, if any, on, the notes;

(3) failure by the Issuer to comply with the provisions described under the captions “—Repurchase at the Option of Holders—Change of Control” or “—Certain Covenants—Merger, Consolidation or Sale of Assets”;

(4) failure by the Issuer or any Restricted Subsidiary for 60 days after notice to the Issuer by the trustee or the holders of at least 25% in aggregate principal amount of the notes then outstanding to comply with any of the other agreements in the Indenture;

(5) default under any mortgage, indenture or instrument under which there may be issued or by which there may be secured or evidenced any Indebtedness for money borrowed by the Issuer or any Restricted Subsidiary (or the

payment of which is guaranteed by the Issuer or any Restricted Subsidiary), whether such Indebtedness or Guarantee now exists, or is created after the date of the Indenture, if that default:

(a) is caused by a failure to pay principal of, premium on, if any, or interest, if any, on, such Indebtedness when due after giving effect to any grace period provided in such Indebtedness (a “Payment Default”); or

(b) results in the acceleration of such Indebtedness prior to its express maturity, and, in each case, the principal amount of any such Indebtedness, together with the principal amount of any other such Indebtedness under which there has been a Payment Default or the maturity of which has been so accelerated, aggregates $20.0 million or more; provided, however, if, prior to any acceleration of the notes, (i) any such Payment Default is cured or waived, (ii) any such acceleration is rescinded, or (iii) such Indebtedness is repaid during the 10 business day period commencing upon the end of any applicable grace period for such Payment Default or the occurrence of such acceleration, as the case may be, any Default or Event of Default (but not any acceleration of the notes) caused by such Payment Default or acceleration shall be automatically rescinded, so long as such rescission does not conflict with any judgment, decree or applicable law;

(6) failure by the Issuer or any Restricted Subsidiary to pay final judgments entered by a court or courts of competent jurisdiction aggregating in excess of $20.0 million (to the extent not covered by insurance by a reputable and creditworthy insurer as to which the insurer has not disclaimed coverage), which judgments are not paid, discharged or stayed, for a period of 60 days;

(7) except as permitted by the Indenture, any Note Guarantee is held in any judicial proceeding to be unenforceable or invalid or ceases for any reason to be in full force and effect, or any Guarantor denies or disaffirms its obligations under its Note Guarantee; and

(8) certain events of bankruptcy or insolvency described in the Indenture with respect to the Issuer or any Restricted Subsidiary that is a Significant Subsidiary or any group of Restricted Subsidiaries that, taken together, would constitute a Significant Subsidiary.

In the case of an Event of Default arising from certain events of bankruptcy or insolvency, with respect to the Issuer, any Restricted Subsidiary that is a Significant Subsidiary or any group of Restricted Subsidiaries that, taken together, would constitute a Significant Subsidiary, all notes then outstanding will become due and payable immediately without further action or notice. If any other Event of Default occurs and is continuing, the trustee or the holders of at least 25% in aggregate principal amount of the notes then outstanding may declare all the notes to be due and payable immediately.

Subject to certain limitations, holders of a majority in aggregate principal amount of the notes then outstanding may direct the trustee in its exercise of any trust or power. The trustee may withhold from holders of the notes notice of any continuing Default or Event of Default if it determines that withholding notice is in their interest, except a Default or Event of Default relating to the payment of principal of, premium on, if any, and interest and Additional Interest, if any, on, the notes.

Subject to the provisions of the Indenture relating to the duties of the trustee, in case an Event of Default occurs and is continuing, the trustee is under no obligation to exercise any of the rights or powers under the Indenture at the request or direction of any holders of notes unless such holders have offered to the trustee indemnity or security satisfactory to it against any loss, liability or expense. Except to enforce the right to receive payment of principal, premium, if any, or interest or Additional Interest, if any, when due, no holder of a note may pursue any remedy with respect to the Indenture or the notes unless:

(1) such holder has previously given the trustee written notice that an Event of Default is continuing;

(2) holders of at least 25% in aggregate principal amount of the notes then outstanding make a written request to the trustee to pursue the remedy;

(3) such holder or holders offer and, if requested, provide to the trustee security or indemnity satisfactory to the trustee against any loss, liability or expense;

(4) the trustee does not comply with such request within 60 days after receipt of the request and the offer of security or indemnity; and

(5) during such 60-day period, holders of a majority in aggregate principal amount of the notes then outstanding do not give the trustee a direction inconsistent with such request.

The holders of a majority in aggregate principal amount of the notes then outstanding by written notice to the trustee may, on behalf of the holders of all of the notes, rescind an acceleration or waive any existing Default or Event of Default and its consequences under the Indenture, if the rescission would not conflict with any judgment or decree, except a continuing Default or Event of Default in the payment of principal of, premium on, if any, or interest or Additional Interest, if any, on, the notes.

The Issuer is required to deliver to the trustee annually a statement regarding compliance with the Indenture. Upon any officer of the Issuer becoming aware of any Default or Event of Default, the Issuer is required to deliver to the trustee a statement specifying such Default or Event of Default.

No Personal Liability of Directors, Officers, Employees and Stockholders

No director, officer, employee, member, partner, incorporator or stockholder of the Issuer or any Restricted Subsidiary, as such, will have any liability for any obligations of the Issuer or the Guarantors under the notes, the Indenture, the Note Guarantees or for any claim based on, in respect of, or by reason of, such obligations or their creation or the transactions contemplated thereby. Each holder of notes by accepting a note waives and releases all such liability. The waiver and release are part of the consideration for issuance of the notes. The waiver may not be effective to waive liabilities under the federal securities laws.

Legal Defeasance and Covenant Defeasance

The Issuer may at any time, at the option of its Board of Directors evidenced by a resolution set forth in an officers’ certificate, elect to have all of its obligations discharged with respect to the notes then outstanding and all obligations of the Guarantors discharged with respect to their Note Guarantees, which we refer to as Legal Defeasance, except for:

(1) the rights of holders of notes then outstanding to receive payments in respect of the principal of, premium on, if any, or interest, if any, on, such notes when such payments are due from the trust referred to below;

(2) the Issuer’s obligations with respect to the notes concerning issuing temporary notes, registration of notes, mutilated, destroyed, lost or stolen notes and the maintenance of an office or agency for payment and money for security payments held in trust;

(3) the rights, powers, trusts, duties and immunities of the trustee under the Indenture, and the Issuer’s and the Guarantors’ obligations in connection therewith; and

(4) the Legal Defeasance provisions of the Indenture.

In addition, the Issuer may, at its option and at any time, elect to have its obligations and the obligations of the Guarantors released with respect to certain covenants (including its obligation to make Change of Control Offers and Asset Sale Offers) that are described in the Indenture, which we refer to as Covenant Defeasance, and thereafter any omission to comply with those covenants will not constitute a Default or Event of Default with respect to the notes. In the event Covenant Defeasance occurs, all Events of Default described under ��—Events of Default and Remedies” (except those relating to payments on the notes or bankruptcy or insolvency events) will no longer constitute an Event of Default with respect to the notes.

In order to exercise either Legal Defeasance or Covenant Defeasance:

(1) the Issuer must irrevocably deposit with the trustee, in trust, for the benefit of the holders of the notes, cash in U.S. dollars, non-callable Government Securities, or a combination thereof, in amounts as will be sufficient, in the opinion of a nationally recognized investment bank, appraisal firm or firm of independent public accountants, to pay the principal of, premium on, if any, and interest, if any, on, the notes then outstanding on the stated date for payment thereof or on the applicable redemption date, as the case may be, and the Issuer must specify whether the notes are being defeased to such stated date for payment or to a particular redemption date;

(2) in the case of Legal Defeasance, the Issuer must deliver to the trustee an opinion of counsel reasonably acceptable to the trustee confirming that (a) the Issuer has received from, or there has been published by, the Internal Revenue Service a ruling or (b) since the date of the Indenture, there has been a change in the applicable federal income tax law, in either case to the effect that, and based thereon such opinion of counsel will confirm that, the holders of the notes then outstanding will not recognize income, gain or loss for federal income tax purposes as a result of such Legal Defeasance and will be subject to federal income tax on the same amounts, in the same manner and at the same times as would have been the case if such Legal Defeasance had not occurred;

(3) in the case of Covenant Defeasance, the Issuer must deliver to the trustee an opinion of counsel reasonably acceptable to the trustee confirming that the holders of the notes then outstanding will not recognize income, gain or loss for federal income tax purposes as a result of such Covenant Defeasance and will be subject to federal income tax on the same amounts, in the same manner and at the same times as would have been the case if such Covenant Defeasance had not occurred;

(4) no Default or Event of Default has occurred and is continuing on the date of such deposit (other than a Default or Event of Default resulting from the borrowing of funds to be applied to such deposit (and any similar concurrent deposit relating to other Indebtedness), and the granting of Liens to secure such borrowings);

(5) such Legal Defeasance or Covenant Defeasance will not result in a breach or violation of, or constitute a default under, any material agreement or instrument (other than the Indenture and the agreements governing any other

Indebtedness being defeased, discharged or replaced) to which the Issuer or any of its Subsidiaries is a party or by which the Issuer or any of its Subsidiaries is bound;

(6) the Issuer must deliver to the trustee an officers’ certificate stating that the deposit was not made by the Issuer with the intent of preferring the holders of notes over the other creditors of the Issuer with the intent of defeating, hindering, delaying or defrauding any creditors of the Issuer or others; and

(7) the Issuer must deliver to the trustee an officers’ certificate and an opinion of counsel, reasonably acceptable to the trustee, each stating that all conditions precedent relating to the Legal Defeasance or the Covenant Defeasance have been complied with.

Amendment, Supplement and Waiver

Except as provided in the next two succeeding paragraphs, the Indenture, the notes or the Note Guarantees may be amended or supplemented with the consent of the holders of a majority in aggregate principal amount of the notes then outstanding (including, without limitation, additional notes, if any) voting as a single class (including, without limitation, consents obtained in connection with a tender offer or exchange offer for, or purchase of, the notes), and any existing Default or Event of Default or compliance with any provision of the Indenture, the notes or the Note Guarantees may be waived with the consent of the holders of a majority in aggregate principal amount of the notes then outstanding (including, without limitation, additional notes, if any) voting as a single class (including, without limitation, consents obtained in connection with a purchase of, or tender offer or exchange offer for, notes).

Without the consent of each holder of notes affected, an amendment, supplement or waiver may not (with respect to any notes held by a non-consenting holder):

(1) reduce the principal amount of notes whose holders must consent to an amendment, supplement or waiver;

(2) reduce the principal of or change the fixed maturity of any note or alter or waive any of the provisions with respect to the redemption or repurchase of the notes (except those provisions relating to the covenants described above under the caption “—Repurchase at the Option of Holders”);

(3) reduce the rate of or change the time for payment of interest, including default interest, on any note;

(4) waive a Default or Event of Default in the payment of principal of, premium on, if any, or interest, if any, on, the notes (except a rescission of acceleration of the notes by the holders of a majority in aggregate principal amount of the notes then outstanding and a waiver of the payment default that resulted from such acceleration);

(5) make any note payable in money other than that stated in the notes;

(6) make any change in the provisions of the Indenture relating to waivers of past Defaults or the rights of holders of notes to receive payments of principal of, premium on, if any, or interest, if any, on, the notes (other than as permitted by clause (7) below);

(7) waive a redemption or repurchase payment with respect to any note (other than a payment required by one of the covenants described above under the caption “—Repurchase at the Option of Holders”);

(8) release any Guarantor from any of its obligations under its Note Guarantee or the Indenture, except in accordance with the terms of the Indenture;

(9) make any change in the preceding amendment, supplement and waiver provisions; or

(10) make any change to or modify the ranking of the notes.

Notwithstanding the preceding, without the consent of any holder of notes, the Issuer, the Guarantors and the trustee may amend or supplement the Indenture, the notes or the Note Guarantees:

(1) to cure any ambiguity, omission, defect or inconsistency;

(2) to provide for uncertificated notes in addition to or in place of certificated notes;

(3) to provide for the assumption of the Issuer’s or a Guarantor’s obligations to holders of notes and Note Guarantees in the case of a merger or consolidation or sale of all or substantially all of the Issuer’s or such Guarantor’s assets, as applicable, including the addition of any required co-issuer of the notes;

(4) to make any change that would provide any additional rights or benefits to the holders of notes or that does not adversely affect the legal rights under the Indenture of any holder of the notes in any material respect;

(5) to conform the text of the Indenture, the notes or the Note Guarantees to any provision of this “Description of the Exchange Notes”;

(6) to provide for the issuance of the Exchange Notes and related Note Guarantees or additional notes and related Note Guarantees in accordance with the provisions set forth in the Indenture;

(7) to secure the notes or the Note Guarantees pursuant to the requirements of the covenant described above under the subheading “—Certain Covenants—Liens”;

(8) to add any additional Guarantor or to evidence the release of any Guarantor from its Note Guarantee, in each case as provided in the Indenture;

(9) to evidence or provide for the acceptance of appointment under the Indenture of a successor trustee;

(10) to comply with any requirements to effect or maintain the qualification of the Indenture under the Trust Indenture Act; or

(11) to comply with the rules of any applicable securities depository.

Satisfaction and Discharge

The Indenture will be discharged and will cease to be of further effect as to all notes issued thereunder (except as to surviving rights of registration of transfer or exchange of the notes and as otherwise specified in the Indenture), when:

(1) either:

(a) all notes that have been authenticated, except lost, stolen or destroyed notes that have been replaced or paid and notes for whose payment money has been deposited in trust and thereafter repaid to the Issuer, have been delivered to the trustee for cancellation; or

(b) all notes that have not been delivered to the trustee for cancellation have become due and payable by reason of the mailing of a notice of redemption or otherwise or will become due and payable within one year and the Issuer or any Guarantor has irrevocably deposited or caused to be deposited with the trustee as trust funds in trust solely for the benefit of the holders, cash in U.S. dollars, non-callable Government Securities, or a combination thereof, in such amounts as will be sufficient, without consideration of any reinvestment of interest, to pay and discharge the entire Indebtedness on the notes not delivered to the trustee for cancellation for principal of, premium on, if any, or interest, if any, on, the notes to the date of stated maturity or redemption;

(2) in respect of clause (1)(b), no Default or Event of Default has occurred and is continuing on the date of the deposit (other than a Default or Event of Default resulting from the borrowing of funds to be applied to such deposit and any similar deposit relating to other Indebtedness and, in each case, the granting of Liens to secure such borrowings);

(3) the Issuer has paid or caused to be paid all sums payable by the Issuer under the Indenture; and

(4) the Issuer has delivered irrevocable instructions to the trustee to apply the deposited money toward the payment of the notes at stated maturity or on the redemption date, as the case may be.

In addition, the Issuer must deliver an officers’ certificate and an opinion of counsel to the trustee stating that all conditions precedent to satisfaction and discharge have been satisfied.

Concerning the Trustee

If the trustee becomes a creditor of the Issuer or any Guarantor, the Indenture limits the right of the trustee to obtain payment of claims in certain cases, or to realize on certain property received in respect of any such claim as security or otherwise. The trustee will be permitted to engage in other transactions; however, if it acquires any conflicting interest after a Default has occurred and is continuing it must eliminate such conflict within 90 days or resign.

The holders of a majority in aggregate principal amount of the notes then outstanding have the right to direct the time, method and place of conducting any proceeding for exercising any remedy available to the trustee, subject to certain exceptions. In case an Event of Default has occurred and is continuing, the trustee will be required, in the exercise of its powers, to use the degree of care of a prudent Person in the conduct of his or her own affairs. Subject to such provisions, the trustee is under no obligation to exercise any of its rights or powers under the Indenture at the request of any holder of notes, unless such holder has offered to the trustee indemnity or security satisfactory to it against any loss, liability or expense.

Governing Law

The Indenture, the notes and the Note Guarantees are governed by, and will be construed in accordance with, the laws of the State of New York.

Certain Definitions

Set forth below are certain defined terms used in the Indenture. Reference is made to the Indenture for a full disclosure of all defined terms used therein, as well as any other capitalized terms used herein for which no definition is provided.

“Acquired Debt” means, with respect to any specified Person:

(1) Indebtedness of any other Person existing at the time such other Person is merged with or into or became a Subsidiary of such specified Person, whether or not such Indebtedness is incurred in connection with, or in contemplation of, such other Person merging with or into, or becoming a Restricted Subsidiary of, such specified Person; and

(2) Indebtedness secured by a Lien encumbering any asset acquired by such specified Person.

“Add-On Initial Purchasers” means Citigroup Global Markets Inc., BMO Capital Markets Corp., Deutsche Bank Securities Inc., Goldman, Sachs & Co., Capital One Southcoast, Inc., RBC Capital Markets, LLC, Merrill Lynch Pierce, Fenner & Smith Incorporated, Credit Suisse Securities (USA) LLC, UBS Securities LLC, ABN AMRO Securities (USA) LLC, KeyBanc Capital Markets Inc. and SunTrust Robinson Humphrey, Inc.

“Additional Interest” means all additional interest then owing pursuant to the Registration Rights Agreements.

“Adjusted Consolidated Net Tangible Assets” means (without duplication), as of the date of determination,

(1) the sum of:

(a) the discounted future net revenues from proved oil and natural gas reserves of the Issuer and all Restricted Subsidiaries calculated in accordance with SEC guidelines before any state or federal income taxes, as estimated in a Reserve Report prepared as of the end of the Issuer’s most recently completed fiscal year, which Reserve Report is prepared or reviewed by independent petroleum engineers as to proved reserves accounting for at least 80% of all such discounted future net revenues and by the Issuer’s petroleum engineers with respect to any other Proved Reserves covered by such report, as increased by, as of the date of determination, the estimated discounted future net revenues from:

(i) estimated proved oil and natural gas reserves of the Issuer and all Restricted Subsidiaries acquired since the date of such year-end Reserve Report, and

(ii) estimated proved oil and natural gas reserves of the Issuer and all Restricted Subsidiaries attributable to extensions, discoveries and other additions and upward revisions of estimates of proved oil and natural gas reserves (including previously estimated development costs incurred during the period and the accretion of discount since the prior period end) since the date of such year-end Reserve Report due to exploration, development or exploitation, production or other activities which would, in accordance with standard industry practice, cause such revisions,

and decreased by, as of the date of determination, the discounted future net revenue attributable to:

(iii) estimated proved oil and natural gas reserves of the Issuer and all Restricted Subsidiaries reflected in such Reserve Report produced or disposed of since the date of such year-end Reserve Report, and

(iv) reductions in estimated proved oil and natural gas reserves of the Issuer and all Restricted Subsidiaries reflected in such Reserve Report attributable to downward revisions of estimates of proved oil and natural gas reserves since such year-end due to changes in geological conditions or other factors which would, in accordance with standard industry practice, cause such revisions, in each case calculated on a pre-tax basis;

in the case of the preceding clauses (i) through (iv), calculated in accordance with SEC guidelines (utilizing the prices utilized in such Person’s year-end reserve report) and estimated by the Issuer’s petroleum engineers or any independent petroleum engineers engaged by the Issuer for that purpose;

(b) the capitalized costs that are attributable to Oil and Gas Properties of the Issuer and all Restricted Subsidiaries to which no proved oil and natural gas reserves are attributable, based on the Issuer’s books and records as of a date no earlier than the last day of the Issuer’s most recent quarterly or annual period for which internal financial statements are available;

(c) the Consolidated Net Working Capital of the Issuer and all Restricted Subsidiaries as of a date no earlier than the last day of the Issuer’s most recent quarterly or annual period for which internal financial statements are available; and

(d) the greater of:

(i) the net book value and

(ii) the appraised value, as estimated by independent appraisers, of other tangible assets

in each case, of the Issuer and all Restricted Subsidiaries as of a date no earlier than the last day of the date of the Issuer’s most recent quarterly or annual period for which internal financial statements are available; provided that if no such appraisal has been performed, no Person shall not be required to obtain such an appraisal and only

clause (d)(i) of this definition shall apply, minus to the extent not otherwise taken into account in the immediately preceding clause (1), (2) the sum of:

(a) minority interests,

(b) to the extent not otherwise taken into account in Consolidated Net Working Capital, any net gas balancing liabilities of the Issuer and all Restricted Subsidiaries as of the last day of the Issuer’s most recent annual or quarterly period for which internal financial statements are available;

(c) to the extent included in clause (1)(a) above, the discounted future net revenues, calculated in accordance with SEC guidelines (utilizing the prices utilized in the Issuer’s year-end reserve report), attributable to reserves that are required to be delivered to third parties to fully satisfy the obligations of the Issuer and all Restricted Subsidiaries with respect to Volumetric Production Payments on the schedules specified with respect thereto, and

(d) the discounted future net revenues, calculated in accordance with SEC guidelines, attributable to reserves subject to Dollar‑Denominated Production Payments that, based on the estimates of production and price assumptions included in determining the discounted future net revenues specified in (1)(a) above, would be necessary to fully satisfy the payment obligations of the Issuer and all Restricted Subsidiaries with respect to Dollar‑Denominated Production Payments on the schedules specified with respect thereto.

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

“Affiliate” of any specified Person means any other Person directly or indirectly controlling or controlled by or under direct or indirect common control with such specified Person. For purposes of this definition, “control,” as used with respect to any Person, means the possession, directly or indirectly, of the power to direct or cause the direction of the management or policies of such Person, whether through the ownership of voting securities, by agreement or otherwise. For purposes of this definition, the terms “controlling,” “controlled by” and “under common control with” have correlative meanings.

“Applicable Premium” means, with respect to any note on any redemption date, 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 (such redemption price being set forth in the table appearing above under the caption “—Optional Redemption”) 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 (assuming a 360-day year consisting of twelve 30-day months), over

(b) the principal amount of the note.

“Asset Sale” means:

(1) the sale, lease, conveyance or other disposition of any assets or rights by the Issuer or any of its Restricted Subsidiaries; provided that the sale, lease, conveyance or other disposition of all or substantially all of the properties or assets of the Issuer and its Subsidiaries taken as a whole will not be an “Asset Sale,” but will be governed by the provisions of the Indenture described above under the caption “—Repurchase at the Option of Holders—Change of Control” and/or the provisions described above under the caption “—Certain Covenants—Merger, Consolidation or Sale of Assets” and not by the provisions described under the caption “—Repurchase at the Option of Holders—Asset Sales”; and

(2) the issuance of Equity Interests by any Restricted Subsidiaries or the sale by the Issuer or any of its Restricted Subsidiaries of Equity Interests in any of the Issuer’s Subsidiaries (other than (a) directors’ qualifying shares required by applicable law to be held by a Person other than the Issuer or any Restricted Subsidiary and (b) the issuance of Preferred Stock to the extent permitted by the covenant described under the caption “—Certain Covenants—Incurrence of Indebtedness and Issuance of Preferred Stock”).

Notwithstanding the preceding, none of the following items will be deemed to be an Asset Sale:

(1) any single transaction or series of related transactions that involves assets having a Fair Market Value of less than $10.0 million;

(2) a transfer of assets between or among the Issuer and the Restricted Subsidiaries;

(3) an issuance or sale of Equity Interests by a Restricted Subsidiary to the Issuer or to any other Restricted Subsidiary;

(4) the sale, assignment, lease, license, abandonment, transfer or other disposition of (a) products, services or accounts receivable in the ordinary course of business or customary in the Oil and Gas Business, (b) damaged, worn-out, unserviceable or obsolete or excess assets and (c) other assets no longer necessary or useful in the conduct of the business of the Issuer and the Restricted Subsidiaries taken as whole);

(5) licenses and sublicenses by the Issuer or any Restricted Subsidiary of software or intellectual property in the ordinary course of business or customary in the Oil and Gas Business;

(6) any surrender or waiver of contract rights or settlement, release, recovery on or surrender of contract, tort or other claims in the ordinary course of business;

(7) the creation or perfections of a Lien not prohibited by the covenant described above under the caption “—Certain Covenants—Liens”;

(8) the sale or other disposition of cash or Cash Equivalents, Hedging Obligations permitted to be incurred pursuant to the covenant described under “Certain Covenants—Incurrence of Indebtedness and Issuance of Preferred Stock” or other financial assets;

(9) a Restricted Payment that does not violate the covenant described above under the caption “—Certain Covenants—Restricted Payments” (or a disposition that would constitute a Restricted Payment but for the exclusion from the definition thereof) or a Permitted Investment;

(10) sale or transfer of Hydrocarbons or other mineral products in the ordinary course of business;

(11) an Asset Swap;

(12) expiration or lapse of exploration tenement licenses and sublicenses of the Issuer or any of its Subsidiaries in the ordinary course of business;

(13) the dilution or forfeiture of working interests of the Issuer or any of its Subsidiaries pursuant to the operating agreements or other instruments or agreements in the ordinary course of business;

(14) farm-outs, leases or subleases of undeveloped Oil and Gas Properties, deemed transfers of working interests under any joint operating agreement as the result of electing (or being deemed to have elected) not to participate in the drilling operations for a new well and assignments and under pooling or unitization agreements or other similar contracts that are usual and customary in the Oil and Gas Business;

(15) dispositions of crude oil and natural gas properties, provided that at the time of any such disposition such properties do not have associated with them any proved reserves; and

(16) any Production Payments and Reserve Sales; provided that any such Production Payments and Reserve Sales, other than incentive compensation programs on terms that are reasonably customary in the Oil and Gas Business for geologists, geophysicists and other providers of technical services to the Issuer or a Restricted Subsidiary, shall have been created, incurred, issued, assumed or Guaranteed in connection with the financing of, and within 60 days after the acquisition of, the property that is subject thereto.

“Asset Sale Offer” has the meaning assigned to that term in “Repurchase at the Option of Holders—Asset Sales.”

“Asset Swap” means any substantially contemporaneous (and in any event occurring within 180 days of each other) purchase and sale or exchange of any assets (including leases) or properties used or useful in the Oil and Gas Business (excluding Capital Stock) between or among the Issuer or any Restricted Subsidiary and one or more other Persons; provided that the Fair Market Value of the properties or assets traded or exchanged by the Issuer or such Restricted Subsidiary (together with any cash and Cash Equivalents) is reasonably equivalent to the Fair Market Value of the properties or assets (together with any cash and Cash Equivalents) to be received by the Issuer or such Restricted Subsidiary, and provided further that any net cash received must be applied in accordance with the provisions described above under the caption “—Repurchase at the Option of Holders—Asset Sales” if then in effect.

“Attributable Debt” in respect of a sale and leaseback transaction means, at the time of determination, the present value of the obligation of the lessee for net rental payments during the remaining term of the lease included in such sale and leaseback transaction including any period for which such lease has been extended or may, at the option of the lessor, be extended. Such present value shall be calculated using a discount rate equal to the rate of interest implicit in such transaction, determined in accordance with GAAP; provided, however, that if such sale and leaseback transaction results in a Capital Lease Obligation, the amount of Indebtedness represented thereby will be determined in accordance with the definition of “Capital Lease Obligation.”

“Beneficial Owner” has the meaning assigned to such term in Rule 13d-3 and Rule 13d-5 under the Exchange Act, except that in calculating the beneficial ownership of any particular “person” (as that term is used in Section 13(d)(3) of the Exchange Act),

such “person” will be deemed to have beneficial ownership of all securities that such “person” has the right to acquire by conversion or exercise of other securities, whether such right is currently exercisable or is exercisable only after the passage of time. The terms “Beneficially Owns” and “Beneficially Owned” have a corresponding meaning.

“Board of Directors” means:

(1) with respect to a corporation, the board of directors of the corporation or any committee thereof duly authorized to act on behalf of such board;

(2) with respect to a partnership, the Board of Directors of the general partner of the partnership;

(3) with respect to a limited liability company, the managing member or members or any controlling committee of managing members thereof; and

(4) with respect to any other Person, the board or committee of such Person serving a similar function.

“Capital Lease Obligation” means, at the time any determination is to be made, the amount of the liability in respect of a capital lease that would at that time be required to be capitalized on a balance sheet prepared in accordance with GAAP, and the Stated Maturity thereof shall be the date of the last payment of rent or any other amount due under such lease prior to the first date upon which such lease may be prepaid by the lessee without payment of a penalty.

“Capital Stock” means:

(1) in the case of a corporation, corporate stock;

(2) in the case of an association or business entity, any and all shares, interests, participations, rights or other equivalents (however designated) of corporate stock;

(3) in the case of a partnership or limited liability company, partnership interests (whether general or limited) or membership interests; and

(4) any other interest or participation that confers on a Person the right to receive a share of the profits and losses of, or distributions of assets of, the issuing Person, but excluding from all of the foregoing any debt securities convertible into Capital Stock, whether or not such debt securities include any right of participation with Capital Stock.

“Cash Equivalents” means:

(1) United States dollars;

(2) securities issued or directly and fully guaranteed or insured by the United States government or any agency or instrumentality of the United States government (provided that the full faith and credit of the United States is pledged in support of those securities) having maturities of not more than one year from the date of acquisition;

(3) marketable general obligations issued by any state of the United States of America or any political subdivision of any such state or any public instrumentality thereof maturing within one year from the date of acquisition thereof and, at the time of acquisition thereof, having a credit rating of “A” or better from either S&P or Moody’s;

(4) certificates of deposit and eurodollar time deposits with maturities of six months or less from the date of acquisition, bankers’ acceptances with maturities not exceeding one year and overnight bank deposits, in each case, with any U.S. commercial bank having capital and surplus in excess of $500.0 million;

(5) repurchase obligations with a term of not more than seven days for underlying securities of the types described in clauses (2), (3) and (4) above entered into with any financial institution meeting the qualifications specified in clause (4) above;

(6) commercial paper having one of the two highest ratings obtainable from Moody’s or S&P and, in each case, maturing within one year after the date of acquisition; and

(7) money market funds at least 95% of the assets of which constitute Cash Equivalents of the kinds described in clauses (1) through (6) of this definition.

“Change of Control” means the occurrence of any of the following:

(1) the direct or indirect sale, lease, transfer, conveyance or other disposition (other than by way of merger or consolidation), in one or a series of related transactions, of all or substantially all of the properties or assets of the Issuer and the Restricted Subsidiaries taken as a whole to any Person (including any “person” (as that term is used in Section 13(d)(3) of the Exchange Act));

(2) the adoption of a plan relating to the liquidation or dissolution of the Issuer;

(3) the consummation of any transaction (including, without limitation, any merger or consolidation), the result of which is that any Person (including any “person” (as defined above) becomes the Beneficial Owner, directly or indirectly, of more than 50% of the Voting Stock of the Issuer, measured by voting power rather than number of shares; or

(4) the first day on which a majority of the members of the Board of Directors of the Issuer are not Continuing Directors.

Notwithstanding the preceding, a conversion of the Issuer or any Restricted Subsidiary from a limited partnership, corporation, limited liability company or other form of entity to a limited liability company, corporation, limited partnership or other form of entity or an exchange of all of the outstanding Equity Interests in one form of entity for Equity Interests in another form of entity shall not constitute a Change of Control, so long as following such conversion or exchange the “persons” (as that term is used in Section 13(d)(3) of the Exchange Act) who Beneficially Owned the Capital Stock of the Issuer immediately prior to such transactions continue to Beneficially Own in the aggregate more than 50% of the Voting Stock of such entity, or continue to Beneficially Own sufficient Equity Interests in such entity to elect a majority of its directors, managers, trustees or other persons serving in a similar capacity for such entity or its general partner, as applicable, and, in either case no “person” Beneficially Owns more than 50% of the Voting Stock of such entity or its general partner, as applicable.

“Change of Control Offer” has the meaning assigned to that term under “Repurchase at the Option of Holders—Change of Control.”

“Consolidated Cash Flow” means, with respect to any period, the Consolidated Net Income for such period plus, without duplication:

(1) provision for taxes based on income or profits of the Issuer and all Restricted Subsidiaries for such period, to the extent that such provision for taxes was deducted in computing Consolidated Net Income; plus

(2) the Fixed Charges of the Issuer and all of its Restricted Subsidiaries for such period, to the extent that such Fixed Charges were deducted in computing Consolidated Net Income; plus

(3) depreciation, depletion, amortization (including amortization of intangibles but excluding amortization of prepaid cash expenses that were paid in a prior period), impairment and other non‑cash charges and expenses (excluding any such non-cash charge or expense to the extent that it represents an accrual of or reserve for cash charges or expenses in any future period or amortization of a prepaid cash charge or expense that was paid in a prior period) of the Issuer and all Restricted Subsidiaries for such period to the extent that such depreciation, depletion, amortization, impairment and other non-cash charges or expenses were deducted in computing such Consolidated Net Income; plus

(4) any non-recurring fees, expense or charges related to any public offering of Equity Interests, Permitted Investments, acquisitions or Indebtedness permitted to be incurred by the Indenture (in each case, whether or not successful), to the extent that such fees, expenses and charges were deducted in computing Consolidated Net Income; plus

(5) all non-recurring financing costs (whether paid, payable, added to principal or amortized) incurred by the Issuer and all Restricted Subsidiaries in connection with the Credit Facilities and the offering of the notes and any refinancing of any part or the whole of the Credit Facilities or the notes to the extent that such one-off financing costs were deducted in computing Consolidated Net Income; plus

(6) to the extent the Issuer adopts the full cost method, consolidated exploration expense of the Issuer and all Restricted Subsidiaries to the extent that such expenses were deducted in computing Consolidated Net Income; minus

(7) non-cash items increasing such Consolidated Net Income for such period, other than the accrual of revenue and other items in the ordinary course of business; and minus

(8) to the extent increasing such Consolidated Net Income for such period, the sum of (a) the amount of deferred revenues that are amortized during such period and are attributable to reserves that are subject to Volumetric Production Payments and (b) amounts recorded in accordance with GAAP as repayments of principal and interest pursuant to Dollar‑Denominated Production Payments, in each case, on a consolidated basis and determined in accordance with GAAP.

“Consolidated Net Income” means, with respect to any period, the aggregate of the net income (loss) attributable to the Issuer and its Subsidiaries for such period, on a consolidated basis determined in accordance with GAAP and without any reduction in respect of preferred stock dividends; provided that:

(1) all extraordinary gains or losses and all gains or losses realized in connection with any Asset Sale that is not sold or otherwise disposed of in the ordinary course of business or the disposition of securities or the early extinguishment of Indebtedness, together with any related provision for taxes on any such gain, will be excluded;

(2) the net income (but not loss) of any Person that is not a Restricted Subsidiary or that is accounted for by the equity method of accounting will be included only to the extent of the amount of dividends or similar distributions paid in cash to the Issuer or all Restricted Subsidiaries;

(3) the net income (but not loss) of any Restricted Subsidiary will be excluded to the extent that the declaration or payment of dividends or similar distributions by that Restricted Subsidiary of that net income is not at the date of determination permitted without any prior governmental approval (that has not been obtained) or, directly or indirectly, by operation of the terms of its charter or any judgment, decree, order, statute, rule or governmental regulation applicable to that Restricted Subsidiary or its stockholders, partners or members (with respect to which the requisite consents have not been obtained or the relevant requirements waived);

(4) the cumulative effect of a change in accounting principles will be excluded;

(5) unrealized losses and gains under derivative instruments included in the determination of Consolidated Net Income, including, without limitation those resulting from the application of Financial Accounting Standards Board Accounting Standards Codification 815, or FASB ASC 815, will be excluded;

(6) any asset impairment write-downs on Oil and Gas Properties under GAAP or SEC guidelines will be excluded;

(7) any non-cash compensation charges shall be excluded, including, but not limited to, (a) any income or charge attributable to a stock‑based post-employment benefit program other than the current service costs and any past service costs and curtailments and settlements attributable to such program and (b) any expense referable to equity‑settled share‑based compensation of employees; and

(8) any extraordinary gain or loss or any gain or loss of a unusual or non-recurring nature, calculated in accordance with GAAP, together with any related provision for taxes (any determination of whether any expense or charge is non-recurring or unusual shall be made by the Issuer’s chief financial officer (or such person acting in a similar capacity) pursuant to such officer’s good faith judgment) will be excluded.

“Consolidated Net Working Capital” means (a) all current assets of the Issuer and all of its Restricted Subsidiaries except current assets from Oil and Natural Gas Hedging Contracts, less (b) all current liabilities of the Issuer and all of its Restricted Subsidiaries, except (i) current liabilities included in Indebtedness and (ii) any current liabilities from Oil and Natural Gas Hedging Contracts, in each case as set forth in the consolidated financial statements of the Issuer prepared in accordance with GAAP (excluding any adjustments made pursuant to FASB ASC 815).

“continuing” means, with respect to any Default or Event of Default, that such Default or Event of Default has not been cured or waived.

“Continuing Directors” means, as of any date of determination, any member of the Board of Directors of the Issuer who:

(1) was a member of such Board of Directors on the date of the Indenture; or

(2) was nominated for election or elected to such Board of Directors whose election to such Board of Directors or whose nomination for election by the stockholders of the Issuer was approved or consented to by a majority of the Continuing Directors who were members of such Board of Directors at the time of such nomination or election.

“Credit Facilities” means one or more debt facilities (including the MHR Senior Revolving Credit Facility) or commercial paper facilities, in each case, between the Issuer or any of the Restricted Subsidiaries with banks or other institutional lenders providing for revolving credit loans, term loans or receivables financing (including through the sale of receivables or inventory to such lenders or to special purpose entities formed to borrow from such lenders against such receivables) or letters of credit, in each case, as amended, restated, modified, renewed, refunded, increased, replaced in any manner (whether upon or after termination or otherwise) or refinanced (including refinancing with any capital markets transaction) in whole or in part from time to time (and whether or not with the original trustee, holders, purchasers, administrative agent and lenders or another administrative agent or agents or other lenders and whether provided under the original Credit Facility or any other credit or other agreement or indenture).

“Default” means any event that is, or with the passage of time or the giving of notice or both would be, an Event of Default.

“Disqualified Stock” means any Capital Stock that, by its terms (or by the terms of any security into which it is convertible, or for which it is exchangeable, in each case, at the option of the holder of the Capital Stock), or upon the happening of any event, matures or is mandatorily redeemable, pursuant to a sinking fund obligation or otherwise, or redeemable at the option of the holder of the Capital Stock, in whole or in part, on or prior to the date that is 91 days after the date on which the notes mature. Notwithstanding the preceding sentence, any Capital Stock that would constitute Disqualified Stock solely because the holders of the Capital Stock have the right to require the Issuer to repurchase or redeem such Capital Stock upon the occurrence of a change of control or an asset sale will not constitute Disqualified Stock if the terms of such Capital Stock provide that the Issuer may not repurchase or redeem any such Capital Stock pursuant to such provisions unless such repurchase or redemption complies with the covenant described above under the caption “—Certain Covenants—Restricted Payments.” The amount of Disqualified Stock deemed to be outstanding

at any time for purposes of the Indenture is the maximum amount that the Issuer and the Restricted Subsidiaries may become obligated to pay upon the maturity of, or pursuant to any mandatory redemption provisions of, such Disqualified Stock, exclusive of accrued dividends.

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

“Domestic Subsidiary” means any Subsidiary of the Issuer that was formed under the laws of the United States or any state of the United States or the District of Columbia or that Guarantees or otherwise provides direct credit support for any Indebtedness of the Issuer (other than a Foreign Subsidiary).

“Equity Interests” of any Person means (1) any and all Capital Stock of such Person and (2) all rights to purchase, warrants or options (whether or not currently exercisable), participations or other equivalents of or interests in (however designated) such Capital Stock of such Person, but excluding from all of the foregoing any debt securities convertible into Equity Interests, regardless of whether such debt securities include any right of participation with Equity Interests.

“Equity Offering” means a sale of Equity Interests of the Issuer (other than Disqualified Stock and other than to a Subsidiary of the Issuer) made for cash on a primary basis by the Issuer after the date of the Indenture.

“Exchange Notes” means any notes issued in exchange for notes then outstanding pursuant to a Registration Rights Agreement.

“Existing Indebtedness” means all Indebtedness or Disqualified Stock of the Issuer and its Subsidiaries in existence on the date of the Indenture after giving effect to the Transactions, until such amounts are repaid.

“Existing Preferred Stock” means the Series C Capital Stock and the Series D Capital Stock.

“Fair Market Value” means the value that would be paid by a willing buyer to an unaffiliated willing seller in a transaction not involving distress or necessity of either party, determined in good faith by the Board of Directors of the Issuer in the case of amounts of $25.0 million or more and otherwise by an officer of the Issuer (unless otherwise provided in the Indenture).

“Fixed Charge Coverage Ratio” means with respect any period, the ratio of the Consolidated Cash Flow for such period to the Fixed Charges for such period. In the event that the Issuer or any Restricted Subsidiary incurs, assumes, Guarantees, repays, repurchases, redeems, defeases or otherwise discharges any Indebtedness (other than ordinary working capital borrowings) or issues, repurchases or redeems Preferred Stock subsequent to the commencement of the period for which the Fixed Charge Coverage Ratio is being calculated and on or prior to the date on which the event for which the calculation of the Fixed Charge Coverage Ratio is made (the “Calculation Date”), then the Fixed Charge Coverage Ratio will be calculated giving pro forma effect to such incurrence, assumption, Guarantee, repayment, repurchase, redemption, defeasance or other discharge of Indebtedness, or such issuance, repurchase or redemption of Preferred Stock, and the use of the proceeds therefrom, as if the same had occurred at the beginning of the applicable four-quarter reference period.

In addition, for purposes of calculating the Fixed Charge Coverage Ratio:

(1) acquisitions (including, without limitation, a single asset, a division or segment or an entire company) that have been made by the Issuer or any Restricted Subsidiary, including through mergers or consolidations, or any Person acquired by the Issuer or any Restricted Subsidiary, and including all related financing transactions and including increases in ownership of the Issuer or any Restricted Subsidiary, during the four-quarter reference period or subsequent to such reference period and on or prior to the Calculation Date, or that are to be made on the Calculation Date, will be given pro forma effect as if they had occurred on the first day of the four-quarter reference period, including any pro forma expense, cost reductions, synergies and other operating improvements (regardless of whether those expenses, cost reductions, synergies or improvements could then be reflected in pro forma financial statements in accordance with Regulation S-X under the Securities Act or any other regulation or policy of the United States Securities and Exchange Commission related thereto) that have occurred or is, in the reasonable judgment of the chief financial or accounting officer, reasonably likely to occur within one year of the Calculation Date;

(2) the Consolidated Cash Flow attributable to discontinued operations, as determined in accordance with GAAP, and operations or businesses (and ownership interests therein) disposed of prior to the Calculation Date, will be excluded;

(3) the Fixed Charges attributable to discontinued operations, as determined in accordance with GAAP, and operations or businesses (and ownership interests therein) disposed of prior to the Calculation Date, will be excluded, but only to the extent that the obligations giving rise to such Fixed Charges will not be obligations of the Issuer or any Restricted Subsidiary following the Calculation Date;

(4) any Person that is a Restricted Subsidiary on the Calculation Date will be deemed to have been a Restricted Subsidiary at all times during such four-quarter period;

(5) any Person that is not a Restricted Subsidiary on the Calculation Date will be deemed not to have been a Restricted Subsidiary at any time during such four-quarter period; and

(6) if any Indebtedness bears an interest rate at the option of the Issuer or any Subsidiary, the interest rate shall be calculated by applying such option rate chosen by such Person; provided, however, that interest on Indebtedness that may optionally be determined at an interest rate based upon a factor of a prime or similar rate, a Eurocurrency interbank offered rate or other rate shall be deemed to have been based upon the rate actually chosen or, if none, then based upon such optional rate chosen as such Person may designate; provided further that if any Indebtedness bears a floating rate of interest, the interest expense on such Indebtedness will be calculated as if the average rate in effect from the beginning of such period to the Calculation Date had been the applicable rate for the entire period (taking into account any Hedging Obligation applicable to such Indebtedness; provided that Hedging Obligations with a remaining term of less than 12 months will be taken into account for the number of months remaining).

For purposes of this definition, whenever pro forma effect is to be given to a transaction, the pro forma calculations shall be made in good faith by the chief financial or chief accounting officer of the Issuer; provided that (x) such cost savings are reasonably identifiable, factually supportable, reasonably attributable to the action specified and reasonably anticipated to result from such actions and (y) such actions have been taken or initiated and the benefits resulting therefrom are anticipated by the Issuer to be realized within twelve (12) months, in each case, as certified in such officer’s certificate delivered to the trustee. For purposes of making the computation referred to above, interest on any Indebtedness under a revolving credit facility, including, without limitation, the MHR Senior Revolving Credit Facility, computed with a pro forma basis shall be computed based upon the average daily balance of such Indebtedness during the applicable period.

“Fixed Charges” means the sum, without duplication, of:

(1) the consolidated interest expense of the Issuer or any Restricted Subsidiary for such period, whether paid or accrued (excluding (i) any interest attributable to Dollar‑Denominated Production Payments, (ii) write-off of deferred financing costs and (iii) accretion of interest charges on future plugging and abandonment obligations, future retirement benefits and other obligations that do not constitute Indebtedness, but including, without limitation, amortization of debt issuance costs and original issue discount, non-cash interest payments, the interest component of all payments associated with Capital Lease Obligations, imputed interest with respect to Attributable Debt, commissions, discounts and other fees and charges incurred in respect of letter of credit or bankers’ acceptance financings), and net of the effect of all payments made or received pursuant to Hedging Obligations in respect of interest rates; plus

(2) the consolidated interest expense of the Issuer or any Restricted Subsidiary that was capitalized during such period; plus

(3) interest on Indebtedness of another Person that is Guaranteed by the Issuer or any Restricted Subsidiary or secured by a Lien (other than a Lien of the type described in clause (13) of the definition of “Permitted Liens”) on assets of the Issuer or any Restricted Subsidiary, whether or not such Guarantee or Lien is called upon; plus

(4) all dividends, whether paid or accrued and whether or not in cash, on any series of Disqualified Stock of or any series of Preferred Stock of any Restricted Subsidiary, other than dividends on Equity Interests payable solely in Equity Interests of the Issuer (other than Disqualified Stock) or to the Issuer or any Restricted Subsidiary, in each case, on a consolidated basis and determined in accordance with GAAP.

“Foreign Subsidiary” means a Subsidiary other than a Domestic Subsidiary.

“GAAP” means generally accepted accounting principles in the United States, which are in effect on the date of the Indenture.

“Government Securities” means direct obligations of, or obligations guaranteed by, the United States of America for the payment of which guarantee or obligations the full faith and credit of the United States is pledged.

“Guarantee” means a guarantee other than by endorsement of negotiable instruments for collection in the ordinary course of business, direct or indirect, in any manner including, without limitation, by way of a pledge of assets or through letters of credit or reimbursement agreements in respect thereof, of all or any part of any Indebtedness (whether arising by virtue of partnership arrangements, or by agreements to keep-well, to purchase assets, goods, securities or services, to take or pay or to maintain financial statement conditions or otherwise). When used as a verb, “Guarantee” has a correlative meaning.

“Guarantors” means each Restricted Subsidiary that executes a Note Guarantee in accordance with the provisions of the Indenture, and their respective successors and assigns, in each case, until the Note Guarantee of such Person has been released in accordance with the provisions of the Indenture.

“Hedging Obligations” means, with respect to any specified Person, the obligations of such Person under any (i) Interest Rate Agreement and (ii) Oil and Gas Hedging Contract.

“Hydrocarbons” means oil, natural gas, casing head gas, drip gasoline, natural gasoline, condensate, distillate, liquid hydrocarbons, gaseous hydrocarbons and all constituents, elements or compounds thereof and products refined or processed therefrom.

“Indebtedness” means, with respect to any specified Person, any indebtedness of such Person (excluding accrued expenses and trade payables), whether or not contingent:

(1) in respect of borrowed money;

(2) evidenced by bonds, notes, debentures or similar instruments or letters of credit (or reimbursement agreements in respect thereof);

(3) in respect of bankers’ acceptances;

(4) representing Capital Lease Obligations or Attributable Debt in respect of sale and leaseback transactions;

(5) representing the balance deferred and unpaid of the purchase price of any property or services due more than six months after such property is acquired or such services are completed, except any such balance that constitutes an accrued expense or trade payable; or

(6) representing any Hedging Obligations,

if and to the extent any of the preceding items (other than letters of credit and Attributable Debt) would appear as a liability upon a balance sheet of the specified Person prepared in accordance with GAAP. In addition, the term “Indebtedness” includes all Indebtedness of others secured by a Lien on any asset of the specified Person (whether or not such Indebtedness is assumed by the specified Person; provided that the amount of such Indebtedness will be the lesser of (a) the Fair Market Value of such asset at such date of determination and (b) the amount of such Indebtedness of such other Person) and, to the extent not otherwise included, the Guarantee by the specified Person of any Indebtedness of any other Person (including, with respect to any Production Payment, any warranties or guarantees of production or payment by such Person with respect to such Production Payment, but excluding other contractual obligations of such Person with respect to such Production Payment). Subject to the preceding sentence, neither Dollar‑Denominated Production Payments nor Volumetric Production Payments shall be deemed to be Indebtedness.

Notwithstanding the foregoing, “Indebtedness” shall not include (i) accrued expenses and royalties arising in the ordinary course of business, (ii) obligations to satisfy customer prepayment arrangements arising in the ordinary course of business, (iii) asset retirement obligations, (iv) obligations in respect of environmental reclamation or site rehabilitation, (v) obligations under farm-in and farm-out agreements or operating agreements, (vi) workers compensation obligations (including superannuation, pensions and retiree medical care) that are not overdue by more than 90 days, (vii) any indebtedness which has been defeased in accordance with GAAP or defeased pursuant to the deposit of cash or Cash Equivalents (in an amount sufficient to satisfy all such indebtedness obligations at maturity or redemption, as applicable, and all payments of interest and premium, if any) in a trust or account created or pledged for the sole benefit of the holders of such indebtedness, and subject to no other Liens, and the other applicable terms of the instrument governing such indebtedness, (viii) any Disqualified Stock and (ix) indebtedness secured by any Lien of the type described in clause (13) of the definition of “Permitted Liens.”

“Initial Purchasers” means the Original Initial Purchasers and the Add-On Initial Purchasers.

“Initial Reserve Report” means (i) that certain reserve report prepared by Cawley, Gillespie & Associates, dated January 17, 2012, evaluating certain Oil and Gas Properties of the Issuer and its Subsidiaries prepared as of December 31, 2011 and (ii) that certain reserve report prepared by AJM Deloitte, dated January 19, 2012, evaluating certain Oil and Gas Properties of the Issuer and its Subsidiaries prepared as of December 31, 2011.

“Interest Rate Agreement” means any interest rate swap agreement (whether from fixed to floating or from floating to fixed), interest rate cap agreement, interest rate collar agreement or other similar agreement or arrangement designed to protect the Issuer or any Restricted Subsidiary against fluctuations in interest rates and is not for speculative purposes.

“Investments” means, with respect to any Person, all direct or indirect investments by such Person in other Persons (including Affiliates) in the forms of loans (including Guarantees or other obligations), advances or capital contributions (excluding commission, travel and similar advances to officers and employees made in the ordinary course of business), purchases or other acquisitions for consideration of Indebtedness, Equity Interests or other securities, together with all items that are or would be classified as investments on a balance sheet prepared in accordance with GAAP. If the Issuer or any Restricted Subsidiary sells or otherwise disposes of any Equity Interests of any direct or indirect Restricted Subsidiary such that, after giving effect to any such sale or disposition, such Person is no longer a Restricted Subsidiary, the Person disposing of such Equity Interests will be deemed to have made an Investment on the date of any such sale or disposition equal to the Fair Market Value of the Issuer and all Restricted Subsidiaries’ Investments in such Subsidiary that were not sold or disposed of in an amount determined as provided in the final paragraph of the covenant described above under the caption “—Certain Covenants—Restricted Payments.” The acquisition by the Issuer or any Restricted Subsidiary of a Person that holds an Investment in a third Person will be deemed to be an Investment by the Issuer or such Restricted Subsidiary in such third Person in an amount equal to the Fair Market Value of the Investments held by the acquired Person in such third Person in an amount determined as provided in the final paragraph of the covenant described above under the caption “—Certain Covenants—Restricted Payments.” Except as otherwise provided in the Indenture, the amount of an Investment will be determined at the time the Investment is made and without giving effect to subsequent changes in value.

“Investment Grade Rating” means a rating equal to or higher than (i) in the case of Moody’s, Baa3, (ii) in the case of S&P, BBB- and (iii) in the case of any other Rating Agency described in clause (2) of the definition thereof, an equivalent or higher rating.

“Lien” means, with respect to any asset, any mortgage, lien, pledge, charge, security interest or encumbrance of any kind in respect of such asset, whether or not filed, recorded or otherwise perfected under applicable law, including any conditional sale or other title retention agreement, any lease in the nature thereof, any option or other agreement to sell or give a security interest in such asset.

“MHR Senior Revolving Credit Facility” means the Second Amended and Restated Credit Agreement, dated as of April 13, 2011, among the Issuer, the Bank of Montreal, as Administrative Agent and the various other financial institutions party thereto, as amended, amended and restated, supplemented or otherwise modified from time to time.

“Moody’s” means Moody’s Investors Service, Inc., and any successor to the ratings business thereof.

“Net Proceeds” means the aggregate cash proceeds received by the Issuer or any Restricted Subsidiary in respect of any Asset Sale (including, without limitation, any cash received upon the sale or other disposition of any non-cash consideration received in any Asset Sale) net of:

(a) payments to holders of minority interests in any assets sold as a result of such Asset Sale;

(b) the direct costs relating to such Asset Sale and any sale of such non-cash consideration, including, without limitation, legal, accounting and investment banking fees, title and recording expenses and sales commissions, and any relocation expenses incurred as a result of such Asset Sale;

(c) taxes paid or payable, or required to be accrued as a liability under GAAP, as a result of such Asset Sale, in each case, after taking into account any available tax credits or deductions and any tax sharing arrangements;

(d) amounts (i) required to be applied to the repayment of Indebtedness secured by a Lien on the asset or assets that were the subject of such Asset Sale, or (ii) which must by its terms, or in order to obtain a necessary consent to such Asset Sale or by applicable law, be repaid out of the proceeds from such Asset Sale (other than Indebtedness incurred pursuant to clause (1) of the second paragraph of the covenant described above under the caption “—Certain Covenants—Incurrence of Indebtedness and Issuance of Preferred Stock”); and

(e) any reserve for adjustment or indemnification obligations in respect of the sale price of such asset or assets established in accordance with GAAP.

“Non-Recourse Debt” means Indebtedness:

(1) as to which neither the Issuer nor any Restricted Subsidiary (a) provides credit support of any kind (including any undertaking, agreement or instrument that would constitute Indebtedness) or (b) is directly or indirectly liable as a guarantor or otherwise; and

(2) as to which the lenders have been notified in writing that they will not have any recourse to the Capital Stock or assets of the Issuer or any Restricted Subsidiary (other than the Equity Interests of an Unrestricted Subsidiary).

“Note Guarantee” means the Guarantee by each Guarantor of the Issuer’s obligations under the Indenture and the notes, as provided in the Indenture.

“Obligations” means any principal, interest, penalties, fees, indemnifications, reimbursements, damages and other liabilities payable under the documentation governing any Indebtedness.

“Oil and Gas Business” means (i) the acquisition, exploration, development, production, operation and disposition of interests in oil, gas and other Hydrocarbon properties, (ii) the gathering, marketing, treating, processing (but not refining), storage, selling and transporting of any production from such interests or properties, (iii) any business relating to exploration for or development, production, treatment, processing (but not refining), storage, transportation or marketing of oil, gas and other minerals and products produced in association therewith and (iv) any activity that is ancillary to or necessary or appropriate for the activities described in clauses (i) through (iii) of this definition.

“Oil and Gas Hedging Contracts” means any puts, cap transactions, floor transactions, collar transactions, forward contract, commodity swap agreement, commodity option agreement or other similar agreement or arrangement in respect of Hydrocarbons to be used, produced, processed or sold by the Issuer or any Restricted Subsidiary that are customary in the Oil and Gas Business designed to protect such Person against fluctuation in Hydrocarbons prices and not for speculative purposes; provided that at all times the aggregate monthly production covered by all such contracts for any single month does not in the aggregate exceed 100% of the Issuer’s and the Restricted Subsidiaries’ Projected Production (at the time such Hedging Contract is entered into) to be sold in the ordinary course of businesses for such month.

“Oil and Gas Properties” means all properties, including equity or other ownership interest therein, which contain or are believed to contain oil and gas reserves.

“Original Initial Purchasers” means Citigroup Global Markets Inc., Credit Suisse Securities (USA) LLC, BMO Capital Markets Corp., Capital One Southcoast, Inc., Deutsche Bank Securities Inc., Goldman, Sachs & Co., RBC Capital Markets, LLC, UBS Securities LLC, ABN AMRO Securities (USA) LLC, KeyBanc Capital Markets Inc., SunTrust Robinson Humphrey, Inc., Canaccord Genuity Inc., MLV & Co., Simmons & Company International, Stephens Inc., and Wunderlich Securities, Inc.

“Outstanding Notes” means the previously issued 9.750% Senior Notes due 2020.

“Permitted Acquisition Indebtedness” means Indebtedness or Disqualified Stock of the Issuer or any of its Restricted Subsidiaries to the extent such Indebtedness or Disqualified Stock was Indebtedness or Disqualified Stock of any other Person existing at the time (a) such Person became a Restricted Subsidiary of the Issuer, (b) such Person was merged or consolidated with or into the Issuer or any of its Restricted Subsidiaries, or (c) assets of such Person were acquired by the Issuer or any of its Restricted Subsidiaries and such Indebtedness was assumed in connection therewith (excluding any such Indebtedness that is repaid contemporaneously with such event), provided that on the date such Person became a Restricted Subsidiary of the Issuer or the date such Person was merged or consolidated with or into the Issuer or any of its Restricted Subsidiaries, or on the date of such asset acquisition, as applicable, either:

(1) immediately after giving effect to such transaction on a pro forma basis as if the same had occurred at the beginning of the applicable four-quarter period, the Issuer or such Restricted Subsidiary, as applicable, would be permitted to incur at least $1.00 of additional Indebtedness pursuant to the Fixed Charge Coverage Ratio test set forth in the first paragraph of the covenant described above under the caption “—Certain Covenants—Incurrence of Indebtedness and Issuance of Preferred Stock,” or

(2) immediately after giving effect to such transaction on a pro forma basis as if the same had occurred at the beginning of the applicable four-quarter period, the Fixed Charge Coverage Ratio of the Issuer would be equal to or greater than the Fixed Charge Coverage Ratio of the Issuer immediately prior to such transaction.

“Permitted Business Investments” means Investments made in the ordinary course of, and of a nature that is or shall have become customary in, the Oil and Gas Business as a means of actively exploiting, exploring for, acquiring, developing, processing, treating, gathering, marketing or transporting oil and gas through agreements, transactions, interests or arrangements which permit one to share risks or costs, comply with regulatory requirements regarding local ownership or satisfy other objectives customarily achieved through the conduct of Oil and Gas Business jointly with third parties, including, without limitation, (i) ownership interests in oil, natural gas, other Hydrocarbon properties or any interest therein or gathering, transportation, processing, storage or related systems, (ii) Investments in the form of or pursuant to operating agreements, processing agreements, farm-in agreements, farm-out agreements, developments agreements, area of mutual interest agreements, unitization agreements, pooling agreements, joint bidding agreements, service contracts, joint venture agreements, partnership agreements (whether general or limited), subscription agreements, stock purchase agreements and other similar agreements with third parties, and (iii) direct or indirect ownership interests in drilling rigs, fracturing units and other related equipment.

“Permitted Investments” means:

(1) any Investment in the Issuer or in any Restricted Subsidiary;

(2) any Investment in cash or Cash Equivalents;

(3) any Investment by the Issuer or any Restricted Subsidiary in a Person, if as a result of such Investment:

(a) such Person becomes a Restricted Subsidiary; or

(b) such Person is merged, consolidated or amalgamated with or into, or transfers or conveys substantially all of its assets to, or is liquidated into, the Issuer or any Restricted Subsidiary;

(4) any Investment made as a result of the receipt of non-cash consideration from an Asset Sale that was made pursuant to and in compliance with the covenant described above under the caption “—Repurchase at the Option of Holders—Asset Sales,” including pursuant to an Asset Swap;

(5) any acquisition of assets or Capital Stock solely in exchange for the issuance of Equity Interests (other than Disqualified Stock) of the Issuer;

(6) any Investments received in compromise or resolution of, or upon satisfaction of judgments with respect to, (a) obligations of trade creditors or customers that were incurred in the ordinary course of business of the Issuer or any Restricted Subsidiary, including pursuant to any plan of reorganization or similar arrangement upon the bankruptcy or insolvency of any trade creditor or customer or (b) litigation, arbitration or other disputes;

(7) Investments represented by Hedging Obligations;

(8) loans or advances to employees made in the ordinary course of business of the Issuer or any Restricted Subsidiary in an aggregate principal amount not to exceed $2.0 million at any one time outstanding;

(9) repurchases of the notes and any Exchange Notes;

(10) any Guarantee of Indebtedness permitted to be incurred by the covenant entitled “—Certain Covenants—Incurrence of Indebtedness and Issuance of Preferred Stock” other than a Guarantee of Indebtedness of an Affiliate of the Issuer that is not the Issuer or a Restricted Subsidiary;

(11) any Guarantee of operating leases (other than Capital Lease Obligations) or other obligations that do not constitute Indebtedness, in each case incurred in the ordinary course of business of the Issuer or any Restricted Subsidiary or customary in the Oil and Gas Business;

(12) any Guarantee of performance or other obligations (other than Indebtedness) arising in the ordinary course in the Oil and Gas Business, including obligations under oil and natural gas exploration, development, joint operating and related agreements and licenses or concessions related to the Oil and Gas Business;

(13) Investments in any Person to the extent such Investments consist of prepaid expenses, negotiable instruments held for collection and lease, utility and workers’ compensation, performance and other similar deposits made in the ordinary course of business by the Issuer or any Restricted Subsidiary;

(14) any Investment existing on, or made pursuant to binding commitments existing on, the date of the Indenture and any Investment consisting of an extension, modification or renewal of any Investment existing on, or made pursuant to a binding commitment existing on, the date of the Indenture; provided that the amount of any such Investment may be increased (a) as required by the terms of such Investment as in existence on the date of the Indenture or (b) as otherwise permitted under the Indenture;

(15) Investments acquired after the date of the Indenture as a result of the acquisition by the Issuer or any Restricted Subsidiary of another Person, including by way of a merger, amalgamation or consolidation with or into the Issuer or any Restricted Subsidiary in a transaction that is not prohibited by the covenant described above under the caption “—Certain Covenants—Merger, Consolidation or Sale of Assets” after the date of the Indenture to the extent that such Investments were not made in contemplation of such acquisition, merger, amalgamation or consolidation and were in existence on the date of such acquisition, merger, amalgamation or consolidation;

(16) Permitted Business Investments; and

(17) other Investments in any Person other than an Affiliate of the Issuer that is not a Subsidiary of the Issuer having an aggregate Fair Market Value (measured on the date each such Investment was made and without giving effect to subsequent changes in value), when taken together with all other Investments made pursuant to this clause (17) that are at the time outstanding that do not exceed the greater of (a) $15.0 million and (b) 1.5% of Adjusted Consolidated Net Tangible Assets.

“Permitted Liens” means:

(1) Liens on assets of the Issuer or any Guarantor securing Indebtedness and other Obligations under Credit Facilities that were permitted by the terms of the Indenture to be incurred pursuant to clause (1) or clause (17) of the definition of “Permitted Debt” and/or securing Hedging Obligations related thereto and/or securing Obligations with regard to Treasury Management Arrangements;

(2) Liens in favor of the Issuer or the Guarantors;

(3) Liens on property of a Person existing at the time such Person becomes a Restricted Subsidiary or is merged with or into or consolidated with the Issuer or any Restricted Subsidiary; provided that such Liens were in existence prior to, and not in contemplation of, such Person becoming a Restricted Subsidiary or such merger or consolidation and do not extend to any assets other than those of the Person that becomes a Restricted Subsidiary or is merged with or into or consolidated with the Issuer or any Restricted Subsidiary;

(4) Liens on property (including Capital Stock) existing at the time of acquisition of the property by the Issuer or any Subsidiary of the Issuer; provided that such Liens were in existence prior to such acquisition and not incurred in contemplation of, such acquisition;

(5) Liens to secure the performance of statutory or regulatory obligations, insurance, surety or appeal bonds, workers’ compensation obligations, bid, plugging and abandonment and performance bonds or other obligations of a like nature incurred in the ordinary course of business (including Liens to secure letters of credit and guarantees issued to assure payment of such obligations);

(6) Liens to secure Indebtedness permitted by clause (4) or (16) of the second paragraph of the covenant entitled “—Certain Covenants—Incurrence of Indebtedness and Issuance of Preferred Stock” covering only the assets acquired with or financed by such Indebtedness; provided that in the case of clause (4), such Lien is granted not more than

180 days after such acquisition or financing and in the case of clause (16), such Lien does not attach to any assets other than those owned by the applicable Foreign Subsidiary;

(7) Liens existing on the date of the Indenture;

(8) Liens created for the benefit of (or to secure) the notes (or the Note Guarantees) and other obligations arising under the Indenture;

(9) Liens to secure any Permitted Refinancing Indebtedness permitted to be incurred under the Indenture; provided, however, that:

(a) the new Lien is limited to all or part of the same property and assets that secured or, under the written agreements pursuant to which the original Lien arose, could secure the original Lien (plus improvements and accessions to, such property or proceeds or distributions thereof); and

(b) the Indebtedness secured by the new Lien is not increased to any amount greater than the sum of (x) the outstanding principal amount, or, if greater, committed amount, of the Indebtedness renewed, refunded, refinanced, replaced, defeased or discharged with such Permitted Refinancing Indebtedness and (y) an amount necessary to pay any fees and expenses, including premiums, related to such renewal, refunding, refinancing, replacement, defeasance or discharge;

(10) Liens for taxes, assessments or governmental charges or claims that are not yet delinquent by more than 30 days or that are being contested in good faith by appropriate proceedings promptly instituted and diligently concluded; provided that any reserve or other appropriate provision as is required in conformity with GAAP has been made therefor;

(11) Liens imposed by law, such as carriers’, warehousemen’s, landlord’s, lessor’s, suppliers, banks, repairmen’s and mechanics’ Liens, and Liens of landlords securing obligations to pay lease payments that are not yet delinquent by more than 30 days, in each case, incurred in the ordinary course of business;

(12) easements, rights of way, zoning and similar restrictions, reservations (including severances, leases or reservations of minerals or water rights), restrictions or encumbrances in respect of real property that were not incurred in connection with Indebtedness and that do not in the aggregate materially adversely affect the value of said properties or materially impair their use in the operation of the business of such Person;

(13) Liens on Capital Stock of an Unrestricted Subsidiary that secure Non-Recourse Debt or other obligations of such Unrestricted Subsidiary;

(14) Liens arising under the Indenture in favor of the trustee for its own benefit and similar Liens in favor of other trustees, agents and representatives arising under instruments governing Indebtedness permitted to be incurred under the Indenture; provided that such Liens are solely for the benefit of the trustees, agents or representatives in their capacities as such and not for the benefit of the holders of the Indebtedness;

(15) Liens on insurance policies and proceeds thereof, or other deposits, to secure insurance premium financings;

(16) filing of Uniform Commercial Code financing statements in connection with operating leases;

(17) bankers’ Liens, rights of setoff and similar rights, Liens arising out of judgments, attachments or awards not constituting an Event of Default and notices of lis pendens and associated rights related to litigation being contested in good faith by appropriate proceedings and for which reserves have been made to the extent required by GAAP;

(18) Liens on cash, Cash Equivalents or other property arising in connection with the defeasance, discharge or redemption of Indebtedness;

(19) Liens on specific items of inventory or other goods (and the proceeds thereof) of any Person securing such Person’s obligations in respect of bankers’ acceptances issued or created in the ordinary course of business for the account of such Person to facilitate the purchase, shipment or storage of such inventory or other goods;

(20) grants of software and other technology licenses in the ordinary course of business;

(21) Liens arising out of conditional sale, title retention, consignment or similar arrangements for the sale of goods entered into in the ordinary course of business;

(22) Liens on any property or asset acquired, constructed or improved by the Issuer or any of its Restricted Subsidiaries which (a) are in favor of the seller of such property or assets, in favor of the Person developing, constructing, repairing or improving such asset or property, or in favor of the Person that provided the funding for the acquisition, development, construction, repair or improvement cost, as the case may be, of such asset or property, (b) are created within 360 days after the acquisition, development, construction, repair or improvement, (c) secure the purchase price or development, construction, repair or improvement cost, as the case may be, of such asset or property in an amount up to

100% of the Fair Market Value of such acquisition, construction, repair or improvement of such asset or property and (d) are limited to the asset or property so acquired, constructed, repaired or improved (including the proceeds thereof, accessions thereto and upgrades thereof);

(23) Liens in respect of Production Payments and Reserve Sales; provided, that such Liens are limited to the property that is subject to such Production Payments and Reserve Sales;

(24) Liens on pipelines or pipeline facilities that arise by operation of law;

(25) Liens arising under oil and gas leases or subleases, assignments, farm-out agreements, farm-in agreements, division orders, contracts for the sale, purchase, exchange, transportation, gathering or processing of Hydrocarbons, unitizations and pooling designations, declarations, orders and agreements, development agreements, joint venture agreements, joint operating agreements, partnership agreements, operating agreements, royalties, working interests, net profits interests, reversionary interests and other similar interests, joint interest billing arrangements, participation agreements, production sales contracts, area of mutual interest agreements, gas balancing or deferred production agreements, injection, repressuring and recycling agreements, salt water or other disposal agreements, seismic or geophysical permits or agreements, licenses, sublicenses and other agreements which are customary in the Oil and Gas Business; provided, however, in all instances that such Liens are limited to the assets that are the subject of the relevant agreement, program, order or contract;

(26) Liens to secure performance of Hedging Obligations of the Issuer or any Restricted Subsidiary entered into in the ordinary course of business and not for speculative purposes;

(27) Liens incurred in the ordinary course of business of the Issuer or any Restricted Subsidiary with respect to Indebtedness that does not exceed the greater of (i) $15.0 million and (ii) 1.0% of Adjusted Consolidated Net Tangible Assets at any one time outstanding; and

(28) any Lien renewing, extending, refinancing or refunding a Lien permitted by clause (3), (4) or (7) above, provided that (a) the principal amount of the Indebtedness secured by such Lien is not increased except by an amount equal to a reasonable premium or other reasonable amount paid, and fees and expenses reasonably incurred, in connection therewith and by an amount equal to any existing commitments unutilized thereunder and (b) no assets encumbered by any such Lien other than the assets permitted to be encumbered immediately prior to such renewal, extension, refinance or refund are encumbered thereby (other than improvements thereon, accessions thereto and proceeds thereof).

“Permitted Refinancing Indebtedness” means

(a) with respect to Indebtedness, any Indebtedness of the Issuer or any Restricted Subsidiary issued in exchange for, or the net proceeds of which are used to renew, refund, refinance, replace, defease or discharge other Indebtedness of the Issuer or any Restricted Subsidiary (other than intercompany Indebtedness); provided that:

(1) the liquidation preference or principal amount (or accreted value, if applicable) of such Permitted Refinancing Indebtedness does not exceed the principal amount (or accreted value, if applicable) of the Indebtedness renewed, refunded, refinanced, replaced, defeased or discharged (plus all accrued interest on the Indebtedness and the amount of all fees and expenses, including premiums, incurred in connection therewith);

(2) such Permitted Refinancing Indebtedness has a final maturity date that is (A) later than the final maturity date of, and has a Weighted Average Life to Maturity equal to or greater than the Weighted Average Life to Maturity of, the Indebtedness being renewed, refunded, refinanced, replaced, defeased or discharged or (B) more than 90 days after the final maturity date of the notes;

(3) if the Indebtedness being renewed, refunded, refinanced, replaced, defeased or discharged is subordinated in right of payment to the notes or the Note Guarantees, such Permitted Refinancing Indebtedness is subordinated in right of payment to the notes or the Note Guarantees, as applicable, on terms at least as favorable to the holders of notes as those contained in the documentation governing the Indebtedness being renewed, refunded, refinanced, replaced, defeased or discharged; and

(4) such Permitted Refinancing Indebtedness is not incurred (other than by way of a Guarantee) by a Restricted Subsidiary that is not a Guarantor if the Issuer or a Restricted Subsidiary that is a Guarantor is the issuer or other primary obligor on the Indebtedness being renewed, refunded, refinanced, replaced, defeased or discharged; and

(b) with respect to Existing Preferred Stock, any Disqualified Stock or Indebtedness of the Issuer or any Restricted Subsidiary issued in exchange for, or the net proceeds of which are used to renew, refund, refinance, replace, defease or discharge such Existing Preferred Stock or Disqualified Stock; provided that:

(1) the liquidation preference (or accreted value, if applicable) of such Permitted Refinancing Indebtedness does not exceed the principal amount (or accreted value, if applicable) of such Existing Preferred

Stock renewed, refunded, refinanced, replaced, defeased or discharged (plus all accrued interest on such Existing Preferred Stock and the amount of all fees and expenses, including premiums, incurred in connection therewith);

(2) such Permitted Refinancing Indebtedness is (A) Disqualified Stock or (B) Indebtedness; provided that such Indebtedness shall be contractually subordinated to the notes pursuant to subordination terms that are customary for senior subordinated high yield debt securities; and

(3) such Permitted Refinancing Indebtedness is not incurred (other than by way of a Guarantee) by a Restricted Subsidiary that is not a Guarantor.

“Person” means any individual, corporation, partnership, joint venture, association, joint‑stock company, trust, unincorporated organization, limited liability company or government or other entity.

“Preferred Stock” means, with respect to any Person, any and all preferred or preference stock or other similar Equity Interests (however designated) of such Person whether outstanding or issued after the date of the Indenture.

“Production Payments” means Dollar‑Denominated Production Payments and Volumetric Production Payments, collectively.

“Production Payments and Reserve Sales” means the grant or transfer by the Issuer or any Restricted Subsidiary to any Person of a royalty, overriding royalty, net profits interest, Production Payment, partnership or other interest in Oil and Gas Properties, reserves or the right to receive all or a portion of the production or the proceeds from the sale of production attributable to such properties where the holder of such interest has recourse solely to such production or proceeds of production, subject to the obligation of the grantor or transferor to operate and maintain, or cause the subject interests to be operated and maintained, in a reasonably prudent manner or other customary standard or subject to the obligation of the grantor or transferor to indemnify for environmental, title or other matters customary in the Oil and Gas Business, including any such grants or transfers pursuant to incentive compensation programs on terms that are reasonably customary in the Oil and Gas Business for geologists, geophysicists or other providers of technical services to the Issuer or any Restricted Subsidiary.

“Projected Production” means the projected production of oil or natural gas (measured by volume unit or BTU equivalent, not sales price), in each case net of royalties, for the term of the contracts from Oil and Gas Properties that have attributable to them Proved Reserves, after deducting projected production from any Oil and Gas Properties sold or under contract for sale that had been included in such report and after adding projected production from any Oil and Gas Properties acquired or that had not otherwise been reflected in such report but that are reflected in a separate or supplemental Reserve Report.

“Proved Reserves” means crude oil and natural gas reserves constituting “proved oil and gas reserves” as defined in Rule 4-10 of Regulation S-X of the Securities Act.

“Rating Agency” means (1) each of Moody’s and S&P and (2) if Moody’s or S&P ceases to rate the notes, a “nationally recognized statistical rating organization” within the meaning of Section 3(a)(62) of the Exchange Act selected by the Issuer as a replacement agency for Moody’s or S&P, as the case may be.

“Registration Rights Agreements” means (i) the Registration Rights Agreement related to the original notes dated as of the date of the Indenture, among the Issuer, the Guarantors and the Original Initial Purchasers, as amended or supplemented, (ii) the Registration Rights Agreement related to the add-on notes dated as of December 18, 2012, among the Issuer, the Guarantors and the Add-On Initial Purchasers, as amended or supplemented, and (iii) any other registration rights agreement or similar agreement entered into in connection with the issuance of additional notes in a private offering by the Issuer after the date of the Indenture.

“Reserve Report” means a report setting forth, as of each December 31 and June 30, the oil and gas reserves attributable to the Proved Reserves of the Issuer and its Subsidiaries, together with a projection of the rate of production and future net income, taxes, operating expenses and capital expenditures with respect thereto as of such date. Until superseded, the Initial Reserve Report will be considered the Reserve Report.

“Restricted Investment” means an Investment other than a Permitted Investment.

“Restricted Subsidiary” means any direct or indirect Subsidiary of the Issuer that is not an Unrestricted Subsidiary.

“Secured Indebtedness” means any Indebtedness of the Issuer or any of its Restricted Subsidiaries secured by a Lien.

“Senior Indebtedness” means:

(1) all Indebtedness of the Issuer or any Restricted Subsidiary outstanding under Credit Facilities and all Hedging Obligations with respect thereto; and

(2) any other Indebtedness of the Issuer or any Restricted Subsidiary permitted to be incurred under the terms of the Indenture, unless the instrument under which such Indebtedness is incurred expressly provides that it is subordinated in right of payment to the notes or any Guarantee; and

(3) all Obligations with respect to the items listed in the preceding clauses (1) and (2).

Notwithstanding anything to the contrary in the preceding sentence, Senior Indebtedness will not include:

(1) any intercompany Indebtedness of the Issuer or any Restricted Subsidiary to the Issuer or any Restricted Subsidiary;

(2) any liability for Federal, state, local or other taxes owed or owing by the Issuer or any of its Subsidiaries;

(3) any accounts payable or other liability to trade creditors arising in the ordinary course of business;

(4) any Indebtedness or other Obligation of the Issuer or any of its Subsidiaries which is subordinate or junior in right of payment to any other Indebtedness or other Obligation of the Issuer or any of its Subsidiaries; or

(5) any Indebtedness that is incurred in violation of the Indenture.

“S&P” means Standard & Poor’s Ratings Services, and any successor to the ratings business thereof.

“Series C Capital Stock” means the Issuer’s 10.25% Series C Cumulative Preferred Stock, par value $0.01 per share. Notwithstanding anything to the contrary, Series C Capital Stock outstanding on the date of the Indenture shall be deemed to be Disqualified Stock for purposes of the Indenture.

“Series D Capital Stock” means the Issuer’s 8.0% Series D Cumulative Preferred Stock, par value $0.01 per share. Notwithstanding anything to the contrary, Series D Capital Stock outstanding on the date of the Indenture shall be deemed to be Disqualified Stock for purposes of the Indenture.

“Significant Subsidiary” means any Restricted Subsidiary that would be a “significant subsidiary” as defined in Article 1, Rule 1-02 of Regulation S-X, promulgated pursuant to the Securities Act, as such Regulation is in effect on the date of the Indenture.

“Stated Maturity” means, with respect to any installment of interest or principal on any series of Indebtedness, the date on which the payment of interest or principal was scheduled to be paid in the original documentation governing such Indebtedness, and will not include any contingent obligations to repay, redeem or repurchase any such interest or principal prior to the date originally scheduled for the payment thereof.

“Subsidiary” means, with respect to any specified Person:

(1) any corporation, association or other business entity (other than a partnership or limited liability company) of which more than 50% of the total voting power of its Voting Stock is at the time owned or controlled, directly or indirectly, by that Person or one or more of the other Subsidiaries of that Person (or a combination thereof); and

(2) any partnership or limited liability company of which (a) more than 50% of the capital accounts, distribution rights, total equity and voting interests or general and limited partnership interests, as applicable, are owned or controlled, directly or indirectly, by such Person or one or more of the other Subsidiaries of that Person or a combination thereof, whether in the form of membership, general, special or limited partnership interests or otherwise, and (b) such Person or any Subsidiary of such Person is a controlling general partner or otherwise controls such entity.

“Treasury Management Arrangement” means any agreement or other arrangement governing the provision of treasury or cash management services, including deposit accounts, overdraft, credit or debit card, funds transfer, automated clearinghouse, zero balance accounts, returned check concentration, controlled disbursement, lockbox, account reconciliation and reporting and trade finance services and other cash management services.

“Treasury Rate” means, as of any redemption date, the yield to maturity as of the time of computation of United States Treasury securities with a constant maturity (as compiled and published in the most recent Federal Reserve Statistical Release H.15(519) that has become publicly available at least two business days prior to the redemption date (or, if such Statistical Release is no longer published, any publicly available source of similar market data)) most nearly equal to the period from the redemption date to May 15, 2016; provided, however, that if the period from the redemption date to May 15, 2016, is less than one year, the weekly average yield on actively traded United States Treasury securities adjusted to a constant maturity of one year will be used. The Issuer will (a) calculate the Treasury Rate on the second business day preceding the applicable redemption date and (b) prior to such redemption date file with the trustee an officers’ certificate setting forth the Applicable Premium and the Treasury Rate and showing the calculation of each in reasonable detail.

“Trust Indenture Act” means the Trust Indenture Act of 1939, as amended.

“Unrestricted Subsidiary” means any direct or indirect Subsidiary of the Issuer (including any newly acquired or newly formed Subsidiary or a Person becoming a Subsidiary through merger or consolidation or Investment therein) that is designated by the Board of Directors of the Issuer as an Unrestricted Subsidiary pursuant to a resolution of such Board of Directors, but only to the extent that such Subsidiary:

(1) has no Indebtedness other than Non-Recourse Debt;

(2) except as permitted by the covenant described above under the caption “—Certain Covenants—Transactions with Affiliates,” is not party to any agreement, contract, arrangement or understanding with the Issuer or any Restricted Subsidiary unless (a) the terms of any such agreement, contract, arrangement or understanding are no less favorable to the Issuer or such Restricted Subsidiary than those that might be obtained at the time from Persons who are not Affiliates of the Issuer or (b) such agreement, contract, arrangement or understanding is otherwise permitted under the provisions of the covenant described above under the caption “—Transactions with Affiliates”; provided, however, that to the extent that clause (a) or (b) is not satisfied, the excess value of such agreement, contract, arrangement or understanding shall be deemed a Restricted Payment;

(3) is a Person with respect to which none of the Issuer or any Restricted Subsidiary has any direct or indirect obligation (a) to subscribe for additional Equity Interests or (b) to maintain or preserve such Person’s financial condition or to cause such Person to achieve any specified levels of operating results; and

(4) has not Guaranteed or otherwise directly or indirectly provided credit support for any Indebtedness of the Issuer or any Restricted Subsidiary, except to the extent such Guarantee would be released upon such designation;

provided, however, that items (1) through (4) shall not be deemed to prevent Permitted Investments in Unrestricted Subsidiaries that are otherwise allowed under the Indenture.

All Subsidiaries of an Unrestricted Subsidiary shall also be Unrestricted Subsidiaries.

As of the date of this prospectus, Eureka Holdings, Eureka Pipeline, Eureka Hunter Land, LLC, Energy Hunter Securities, Inc., Magnum Hunter Midstream, LLC, Magnum Hunter Services, LLC, MHR Callco Corporation, MHR Exchangeco Corporation, Triad Hunter Gathering, LLC, TransTex Hunter, Sentra Corporation, Williston Hunter Canada, Inc. (formerly known as Nuloch Resources, Inc.) and 54NG, LLC are Unrestricted Subsidiaries.

“Volumetric Production Payments” means production payment obligations recorded as deferred revenue in accordance with GAAP, together with all undertakings and obligations in connection therewith.

“Voting Stock” of any specified Person as of any date means the Capital Stock of such Person entitling the holders thereof (whether at all times or only so long as no senior class of Capital Stock has voting power by reason of any contingency) to vote in the election of members of the Board of Directors of such Person.

“Weighted Average Life to Maturity” means, when applied to any Indebtedness at any date, the number of years obtained by dividing:

(1) the sum of the products obtained by multiplying (a) the amount of each then remaining installment, sinking fund, serial maturity or other required payments of principal, including payment at final maturity, in respect of the Indebtedness, by (b) the number of years (calculated to the nearest one-twelfth) that will elapse between such date and the making of such payment; by

(2) the then outstanding principal amount of such Indebtedness.

USE OF PROCEEDS

The exchange offer is intended to satisfy our obligations under the registration rights agreements. We will not receive any proceeds from the issuance of the exchange notes in the exchange offer. Because we are exchanging the outstanding notes for the exchange notes, which have substantially identical terms, the issuance of the exchange notes will not result in any increase in our indebtedness.

CERTAIN MATERIAL UNITED STATES FEDERAL INCOME TAX CONSIDERATIONS

This section describes certain material United States federal income tax considerations that may be relevant to the exchange of the outstanding notes for the exchange notes. It applies to you only if you are the original beneficial owner of the outstanding notes, exchange the outstanding notes for the exchange notes, and hold the outstanding notes and the exchange notes as capital assets (generally property held for investment).

This discussion does not address all of the United States federal income tax considerations that may be relevant to a holder in light of such holder’s particular circumstances. This discussion does not address the effect of any other federal tax laws or of any applicable state, local, foreign or other tax laws, including gift and estate tax laws. This section does not apply to you if you are a member of a class of holders subject to special rules, such as:


•	a dealer in securities or foreign currencies,


•	a trader in securities that elects to use a mark-to-market method of accounting for securities holdings,


•	a bank, thrift or other financial institution,


•	an insurance company,


•	a regulated investment company or real estate investment trust,


•	an S-corporation, partnership or other pass-through entity, and holders of interests therein,


•	a tax-exempt organization,


•	a person that owns exchange notes that are a hedge or that are hedged against interest rate risks,


•	a person that owns exchange notes as part of a hedge, straddle, conversion transaction or other ‘‘synthetic security’’ or integrated transaction for tax purposes,


•	a person subject to the alternative minimum tax,


•	a person that purchases or sells exchange notes as part of a wash sale for tax purposes,


•	a United States expatriate or former long-term resident, or


•	a United States holder (as defined below) whose functional currency for tax purposes is not the U.S. dollar.

This section is based on the Internal Revenue Code of 1986, as amended (the “Code”), its legislative history, existing and proposed regulations under the Code, published rulings and court decisions, all as currently in effect, and all of which are subject to change, possibly on a retroactive basis, or to different interpretations.

If an entity or arrangement treated as a partnership for United States federal tax purposes holds the outstanding or exchange notes, the United States federal income tax treatment of a partner will generally depend on the status of the partner and the activities of the partnership. If you are a partner in a partnership holding outstanding notes, you should consult your own tax advisor regarding the tax consequences of an exchange of the outstanding notes for the exchange notes pursuant to this exchange offer.

The exchange of outstanding notes for exchange notes in the exchange offer will not constitute a taxable exchange by the holders for United States federal income tax purposes, and accordingly, the United States federal income tax consequences of holding the exchange notes will be identical to those of holding the outstanding notes. As a result, no gain or loss will be recognized for United States federal income tax purposes by a holder upon receipt of an exchange note in exchange for an outstanding note and any such holder will have the same adjusted basis and holding period in the exchange note as in the outstanding note immediately before the exchange.

This discussion is provided for general information only and does not constitute legal advice to any holder of the outstanding notes. Persons considering the exchange of outstanding notes for exchange notes in the exchange offer should consult their own tax advisors concerning the United States federal income tax consequences in light of their particular situations as well as any consequences arising under the laws of any other taxing jurisdiction.

PLAN OF DISTRIBUTION

Each broker-dealer that receives exchange notes for its own account pursuant to the exchange offer must acknowledge that it will deliver a prospectus in connection with any resale of such exchange notes. This prospectus, as it may be amended or supplemented from time to time, may be used by a broker-dealer in connection with resales of exchange notes received in exchange for outstanding notes where such outstanding notes were acquired as a result of market-making activities or other trading activities. The Company has agreed that, for a period of 180 days after the expiration date, it will make this prospectus, as amended or supplemented, available to any broker-dealer for use in connection with any such resale. In addition, for a period of time, generally until 90 days following October 8, 2013, the effective date of the registration statement on Form S-4 (of which this prospectus forms a part), all dealers effecting transactions in the exchange notes may be required to deliver a prospectus. Since we are not Form S-3 eligible and cannot incorporate by reference into this prospectus, there is no assurance that we will be able to deliver a current prospectus at the time a broker dealer is required to deliver it. See “Risk Factors-You may be required to deliver a prospectus and comply with other requirements in connection with any resale of the exchange notes. We may be unable to provide a current prospectus, however, due to our inability to incorporate by reference.”

If you wish to exchange your outstanding notes for exchange notes in the exchange offer, you will be required to make representations to us as described in “Exchange Offer— Terms of the Exchange Offer” in this prospectus and in the letter of transmittal. Each broker-dealer that receives exchange notes for its own account pursuant to the exchange offer in exchange for outstanding notes that were acquired by such broker-dealer as a result of market-making or other trading activities must acknowledge that it will deliver a prospectus in connection with any resale of such exchange notes. This prospectus, as it may be amended or supplemented from time to time, may be used by a broker-dealer in connection with resales of exchange notes received in exchange for outstanding notes where such outstanding notes were acquired for its own account as a result of market-making activities or other trading activities.

The Company will not receive any proceeds from any sale of exchange notes by broker-dealers. Exchange notes received by broker-dealers for their own account pursuant to the exchange offer may be sold from time to time in one or more transactions in the over-the-counter market, in negotiated transactions, through the writing of options on the exchange notes or a combination of such methods of resale, at market prices prevailing at the time of resale, at prices related to such prevailing market prices or negotiated prices. Any such resale may be made directly to purchasers or to or through brokers or dealers who may receive compensation in the form of commissions or concessions from any such broker-dealer or the purchasers of any such exchange notes. Any broker-dealer that resells exchange notes that were received by it for its own account pursuant to the exchange offer and any broker or dealer that participates in a distribution of such exchange notes may be deemed to be an “underwriter” within the meaning of the Securities Act and any profit on any such resale of exchange notes and any commission or concessions received by any such persons may be deemed to be underwriting compensation under the Securities Act. The letter of transmittal states that, by acknowledging that it will deliver and by delivering a prospectus, a broker-dealer will not be deemed to admit that it is an “underwriter” within the meaning of the Securities Act.

For a period of 180 days after the expiration date the Company will use commercially reasonable efforts to promptly send additional copies of this prospectus and any amendment or supplement to this prospectus to any broker-dealer that requests such documents in the letter of transmittal, but there is no assurance the Company will be able to do so since its lack of Form S-3 eligibility prevents it from incorporating by reference into this prospectus. See “Risk Factors-You may be required to deliver a prospectus and comply with other requirements in connection with any resale of the exchange notes. We may be unable to provide a current prospectus, however, due to our inability to incorporate by reference.” The Company has agreed to pay all reasonable and documented expenses incident to the exchange offer (including the reasonable and documented expenses of one counsel for the holders of the notes) other than commissions or concessions of any brokers or dealers and will indemnify the holders of the notes (including any broker-dealers) against certain liabilities, including liabilities under the Securities Act.

Based on the interpretations by the staff of the SEC as set forth in no-action letters issued to third parties (including Exxon Capital Holdings Corporation (available May 13, 1998), Morgan Stanley & Co. Incorporated (available June 5, 1991), K-11 Communications Corporation (available May 14, 1993) and Shearman & Sterling (available July 2, 1993)), we believe that the exchange notes issued pursuant to the exchange offer may be offered for resale, resold and otherwise transferred by any holder of such exchange notes, other than any such holder that is a broker-dealer or an “affiliate” of us within the meaning of Rule 405 under the Securities Act, without compliance with the registration and prospectus delivery provisions of the Securities Act, provided that:


•	such exchange notes are acquired in the ordinary course of business;


•	at the time of the commencement of the exchange offer, such holder has no arrangement or understanding with any person to participate in a distribution of such exchange notes; and


•	such holder is not engaged in and does not intend to engage in a distribution of such exchange notes.

We have not sought and do not intend to seek a no-action letter from the SEC, with respect to the effects of the exchange offer, and there can be no assurance that the staff of the SEC would make a similar determination with respect to the exchange notes as it has in such no-action letters.

RATIO OF EARNINGS TO FIXED CHARGES



	Six Months Ended June 30, 2013				Years Ended December 31,
	Six Months Ended June 30, 2013				2012				2011				2010				2009				2008
	(in thousands)
Fixed Charges:
Interest Charges	$	39,846			$	57,394			$	12,961			$	3,995			$	2,801			$	2,361
Series A Convertible Preferred Units of Eureka Hunter Holdings, LLC, cumulative distribution rate of 8.0%	9,834				8,090				—				—				—				—
Total Fixed Charges	$	49,680			$	65,484			$	12,961			$	3,995			$	2,801			$	2,361

Loss Before Taxes and Non-controlling Interest	$	(114,726	)		$	(188,607	)		$	(86,631	)		$	(22,812	)		$	(15,633	)		$	(11,109	)
Fixed Charges (Calculated Above)	49,680				65,484				12,961				3,995				2,801				2,361
Less: Capitalized Interest	(1,081		)		(4,240		)		—				—				—				—
Less: Series A Convertible Preferred Units of Eureka Hunter Holdings, LLC, cumulative distribution rate of 8.0%	(9,834		)		(8,090		)		—				—				—				—
Earnings	$	(75,961	)		$	(135,453	)		$	(73,670	)		$	(18,817	)		$	(12,832	)		$	(8,748	)

Ratio of Earnings to Fixed Charges ⁽¹⁾	—			^-7	—			^-6	—			^-5	—			^-4	—			^-3	—			^-2

(1)

For purposes of determining the ratio of earnings to fixed charges, earnings are defined as income from continuing operations before income taxes and non-controlling interest, plus fixed charges and amortization of capitalized interest, less capitalized interest. Fixed charges consist of interest incurred (whether expensed or capitalized), and amortization of deferred financing costs and an estimate of the interest within rental expense. All reported periods of the calculation of the ratio of earnings to fixed charges exclude discontinued operations.


(2)	Earnings were inadequate to cover fixed charges for the year ended December 31, 2008 by $11.1 million


(3)	Earnings were inadequate to cover fixed charges for the year ended December 31, 2009 by $15.6 million


(4)	Earnings were inadequate to cover fixed charges for the year ended December 31, 2010 by $22.8 million


(5)	Earnings were inadequate to cover fixed charges for the year ended December 31, 2011 by $86.6 million


(6)	Earnings were inadequate to cover fixed charges for the year ended December 31, 2012 by $200.9 million


(7)	Earnings were inadequate to cover fixed charges for the six months ended June 30, 2013 by $125.6 million

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 the section of this prospectus entitled "Management's Discussion and Analysis of Financial Condition and Results of Operations." The selected consolidated financial data as of December 31, 2012 and 2011 and for the years in the three year period ended December 31, 2012, are derived from the audited consolidated financial statements included elsewhere in this prospectus. The selected consolidated balance sheet data as of December 31, 2010, 2009 and 2008 are derived from audited consolidated financial statements not included in this prospectus. The selected consolidated statement of operations and cash flow data for the years ended December 31, 2009 and 2008 are derived from audited financial statements not included in this prospectus. The selected consolidated financial data as of and for the six months ended June 30, 2013 and 2012 are derived from the unaudited consolidated financial statements included elsewhere in this prospectus.



	Six Months Ended June 30,						Year Ended December 31,
	2013			2012			2012			2011			2010			2009			2008
	(In thousands, except per-share data)
Statement of Operations Data
Revenues	$	156,217		$	84,787		$	198,860		$	93,441		$	28,609		$	6,844		$	11,590
Loss from continuing operations, net of tax	(66,306		)	(34,754		)	(156,411		)	(83,644		)	(22,812		)	(15,569		)	(9,468		)
Income from discontinued operations, net of tax	14,208			7,517			17,281			7,232			2,481			445			2,582
Gain on sale of discontinued operations, net of tax	172,452			2,224			2,409			—			6,660			—			—
Net income (loss)	120,354			(25,013		)	(136,721		)	(76,412		)	(13,671		)	(15,124		)	(6,886		)
Dividends on preferred stock	(27,617		)	(12,860		)	(34,706		)	(14,007		)	(2,467		)	(26		)	(734		)
Net income (loss) attributable to common shareholders	93,626			(37,895		)	(167,414		)	(90,668		)	(16,267		)	(15,150		)	(7,620		)
Basic and Diluted Earnings (Loss) Per Share
Continuing operations	(0.55		)	(0.34		)	(1.20		)	(0.86		)	(0.39		)	(0.40		)	(0.28		)
Discontinued operations	1.10			0.07			0.13			0.06			0.14			0.01			0.07
Net income (loss) per share	0.55			(0.27		)	(1.07		)	(0.80		)	(0.25		)	(0.39		)	(0.21		)
Statement of Cash Flows Data
Net cash provided by (used in)
Operating activities	$	73,868		$	49,165		$	58,011		$	33,838		$	(1,168	)	$	3,372		$	3,437
Investing activities	104,198			(658,720		)	(1,009,207		)	(361,715		)	(118,281		)	(16,624		)	(10,379		)
Financing activities	(202,590		)	619,499			996,442			342,193			117,721			9,413			(2,338		)
Balance Sheet Data
Total assets	$	2,035,920		$	1,805,614		$	2,198,632		$	1,168,760		$	248,967		$	66,584		$	61,665
Long-term debt	665,318			606,322			886,769			285,824			25,699			13,000			21,500
Other long-term liabilities	158,783			167,023			155,677			124,609			4,834			2,673			1,590
Redeemable preferred stock	221,271			183,081			200,878			100,000			70,236			5,374			—
Shareholders’ equity	815,530			679,047			711,652			490,652			103,322			39,318			35,078

````````````````````````

DESCRIPTION OF OTHER MATERIAL INDEBTEDNESS

Set forth below is a summary of the material terms of the documents governing the material outstanding indebtedness of the Company and its subsidiaries. The following descriptions do not purport to be complete and are qualified in their entirety by reference to their respective governing documents.

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 September 30, 2013, the aggregate borrowing base under this facility was $265.0 million, and $90.0 million of borrowings were outstanding. The borrowing base is subject to certain automatic reductions upon the issuance of additional 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 “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 1.005% to 2.25% for ABR loans and from 2.00% to 3.25% 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 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 (i) 2.00 to 1.00 for the fiscal quarters ended June 30, 2013 and ending September 30, 2013, (ii) 2.25 to 1.00 for the fiscal quarter ending December 31, 2013 and (iii) 2.50 to 1.00 for the fiscal quarter ending March 31, 2014 and each fiscal quarter ending thereafter; (3) commencing with the fiscal quarter ending June 30, 2014, a ratio of total debt to EBITDAX of not more than (i) 4.50 to 1.0 for the fiscal quarters ending June 30, 2014 and September 30, 2014 and (ii) 4.25 to 1.00 for the fiscal quarter ending December 31, 2014 and for each fiscal quarter ending thereafter, and (4) commencing with the fiscal quarter ended June 30, 2013 through and including the fiscal quarter ending March 31, 2014, a ratio of senior debt to EBITDAX not more than 2.00 to 1.00.

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.

The Company and its restricted subsidiaries are in preliminary discussions with their existing senior lenders to enter into a new senior secured revolving credit facility. Any such facility would replace, and is expected to be on terms substantially similar to, the existing MHR Senior Revolving Credit Facility.

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 September 30, 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. Neither Eureka Holdings nor its subsidiaries, including Eureka Pipeline, are guarantors of the notes to which this prospectus relates.

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 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.

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) 1.50 to 1.00, for the fiscal quarter ended June 30, 2013, (B) 1.75 to 1.00, for the fiscal quarter ending September 30, 2013, (C) 2.25 to 1.00, for the fiscal quarters ending December 31, 2013 and March 31, 2014, (D) 2.50 to 1.00, for the fiscal quarters ending June 30, 2014 and September 30, 2014, and (E) 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) 1.75 to 1.00, for the fiscal quarter ended June 30, 2013, (B) 2.00 to 1.00, for the fiscal quarter ending September 30, 2013, (C) 2.50 to 1.00, for the fiscal quarters ending December 31, 2013 and March 31, 2014, (D) 2.75 to 1.00, for the

fiscal quarters ending June 30, 2014 and September 30, 2014, and (E) 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) 6.00 to 1.0 for the fiscal quarters ended March 31, 2013 and June 30, 2013, (B) 5.00 to 1.0 for the fiscal quarter ending September 30, 2013, (C) 4.50 to 1.0 for the fiscal quarters ending December 31, 2013, March 31, 2014, June 30, 2014, and September 30, 2014, and (D) 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) 5.75 to 1.0 for the fiscal quarters ended March 31, 2013 and June 30, 2013, (B) 4.75 to 1.0 for the fiscal quarter ending September 30, 2013, (C) 4.50 to 1.0 for the fiscal quarters ending December 31, 2013 and March 31, 2014, and (D) 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.

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 2014 of all or part of our midstream operations. We have also identified a number of properties, that we believe represent up to $300 million in aggregate value, for possible divestiture in 2013 and 2014. These assets include the Company's remaining properties in south Texas and certain properties in North Dakota, Kentucky, and Canada.

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 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 September 30, 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 and Monroe Counties, Ohio. As of September 30, 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 September 30, 2013, approximately 76% of our mineral leases in the Marcellus Shale area were held by production. As of September 30, 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 September 30, 2013, we had a total of approximately 91,000 net leasehold acres prospective for the Utica Shale (a portion of which acreage overlaps our Marcellus Shale acreage). We believe approximately 32,000 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. The Company has deemed this well to be a “tight-hole” for competitive reasons and therefore, no disclosure regarding any specifics concerning the completion of this well is being made at this time. We plan to drill two 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 29 gross (19 net) wells in the Marcellus Shale and three gross (2.5 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 September 30, 2013, our Williston Basin properties included approximately 151,354 net leasehold acres consisting of approximately 100,122 net acres and 51,232 net acres in the Bakken/Three Forks Sanish formations in North Dakota and Saskatchewan, respectively. As of September 30, 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 353 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 860 boepd.

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 September 30, 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.

On September 2, 2013, Williston Hunter, Inc., a wholly owned subsidiary of the Company, entered into a purchase and sale agreement with Oasis Petroleum of North America LLC, or Oasis, to sell Williston Hunter's non-operated working interest in certain oil and gas properties located in Burke County, North Dakota, consisting of a non-operated working interest in approximately 51,495 gross (14,500 net) leasehold acres for consideration of $32.5 million in cash, subject to customary adjustments. The transaction closed on September 27, 2013, and was effective as of July 1, 2013.

Midstream Operations

We are exploring the possible monetization in 2014 of all or part of our midstream operations. Concurrently, 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 September 30, 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 September 30, 2013, we were flowing approximately 60,000 mcf of natural gas per day through the Eureka Hunter Gas Gathering System. Through put has been reduced temporarily while the Mobley Processing Plant is restored to service following a break in a NGL pipeline associated with the plant. See "Business-Midstream Operations-Mobley Gas Processing Operations."

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.

Agreement to Purchase Utica Shale Acreage

On August 12, 2013, Triad Hunter, LLC, referred to as Triad Hunter, a Delaware limited liability company and wholly-owned subsidiary of the Company, entered into an Asset Purchase Agreement, referred to as the Purchase Agreement, with MNW Energy, LLC, an Ohio limited liability company, referred to as MNW. MNW represents an informal association of various land owners, lessees of mineral acreage and sublessees of mineral acreage who own or have rights in mineral acreage located in Monroe, Noble and/or Washington Counties, Ohio, referred to as the Counties. Pursuant to the Purchase Agreement, Triad Hunter has agreed to acquire from MNW up to 32,000 net mineral acres, including currently leased and subleased acreage, located in the Counties, referred to as the Subject Acreage, over the next 10 months or possibly longer, subject to certain conditions set forth below.

that have defects that MNW cannot cure to Triad Hunter's satisfaction. If Triad Hunter rejects any Subject Acreage due to title or lease defects, MNW will offer Triad Hunter replacement acreage pursuant to the terms of the Purchase Agreement. After Triad Hunter conducts its review of the Subject Acreage, MNW will assign to Triad Hunter and Triad Hunter will purchase from MNW the Subject Acreage that is satisfactory to Triad Hunter.

The Subject Acreage is expected to be acquired in multiple closings, with a closing to occur each time Triad Hunter has reviewed and approved title to at least $15.0 million in aggregate Purchase Price of the Subject Acreage. Notwithstanding the foregoing, the parties are required to close no more than every 30 days on the Subject Acreage that is satisfactory to Triad Hunter after completion of its title and lease review. At each closing, MNW will execute an assignment in the form provided in the Purchase Agreement, and the lessors and sublessors will also deliver ratifications of the leases and subleases being closed upon.

The Purchase Agreement provides that Triad Hunter will acquire the Subject Acreage for $4,441 per net mineral acre; provided, however, that the price per net mineral acre will be reduced to $3,331 for any portion of subleased acreage for which the terms of the underlying lease contain a defect that materially reduces the value of such underlying lease, but which Triad Hunter is nevertheless willing to accept pursuant to the Purchase Agreement. The maximum aggregate purchase price for MNW's delivery of 32,000 net mineral acres of leased and subleased acreage with acceptable title and lease terms is $142.1 million.

Pursuant to the Purchase Agreement, 0.5% of the purchase price will be held by Triad Hunter in escrow at each closing. MNW will earn the escrow funds pursuant to the Earn-Out Agreement executed by Triad Hunter and MNW concurrently with the Purchase Agreement by providing certain curative title work and other services to Triad Hunter with respect to one or more projects yet to be determined by Triad Hunter.

The Purchase Agreement contains certain representations, warranties, covenants and indemnities by the parties as described therein.

Possible Divestitures

We are exploring the possible monetization in 2014 of all or part of our midstream operations. In addition, we have identified a number of properties (our remaining properties in south Texas and certain properties in North Dakota, Kentucky, and Canada), which we believe represent up to $300 million in aggregate value, for possible divestiture in 2013 and 2014.

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 prospectus). 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.


•	Our daily production volumes at September 30, 2013 were approximately 11,500 boepd. The temporary shut-down of the Mobley Processing Plant resulted in production curtailments and reduced our volumes by approximately 3,300 boepd. See "Business-Midstream Operations-Mobley Gas Processing Operations."


•	As of September 30, 2013, we had approximately 361,112 net leasehold acres in our core operating areas, including (i) approximately 81,000 net acres in the Marcellus Shale, (ii) approximately 91,000 net acres prospective for the Utica Shale (a portion of which acreage overlaps our Marcellus Shale acreage) and (iii) approximately 151,354 net acres in the Williston Basin/Bakken Shale.

Proved, Probable and Possible Reserves (3P) as of June 30, 2013

The Company's combined estimated proved, probable and possible reserves, referred to as 3P Reserves, were 119.3 MMBoe as of June 30, 2013 (such 3P reserves not having been adjusted to reflect any of the risks associated with commerciality of production). The Company's 3P Reserves at June 30, 2013 were prepared by a third-party engineering consultant, Cawley Gillespie & Associates, Inc., referred to as CG&A, and include the Marcellus Shale and Williston Basin/Bakken/Sanish Shale reserves. No Utica Shale reserves were included, however.

The Williston Basin/Bakken/Sanish Shale and Marcellus Shale probable and possible reserves were estimated at 49.8 MMBoe and 11.7 MMBoe, respectively, as of June 30, 2013.

The table below summarizes the Company's estimated 3P Reserves using SEC pricing, broken out by operating area:



June 30, 2013 3P Reserves
		Total Proved	Total Probable/Possible	Total 3P Reserves
Area	Reservoir	(MMBoe) (1)	(MMBoe) (1)	(MMBoe) (1)
Williston Hunter	Bakken/Sanish/Other
USA		17.2	47.6	64.8
Canada		2.3	2.3	4.6
Triad Hunter	Marcellus/Other	30.6	11.8	42.4
	Utica	—	—	—
Shale Hunter	Eagle Ford/Wilcox	0.5	—	0.5
MH Production	Devonian Shale/Other	7.2	—	7.2
Total		57.8	61.7	119.5


(1)	The 3P Reserves have not been adjusted to reflect any risks associated with achieving commerciality of production.

Proved Reserves Overview as of June 30, 2013

The Company's total proved reserves, excluding the Eagle Ford Shale properties divestment which occurred in April 2013, decreased by 6% to 57.8 MMBoe (51% crude oil and NGLs; 61% proved developed producing) at June 30, 2013 as compared to 61.6 MMBoe (57% crude oil and NGLs; 56% proved developed producing) at December 31, 2012. This decline was primarily due to higher lease operating expenses, or LOE, in the Williston Basin which moved certain proved undeveloped reserves into the probable category. Proved developed reserves increased by 3% from year-end 2012 to 35.4 MMBoe as of June 30, 2013 as a result of the Company's continued execution of its development drilling program. Aggregate proved undeveloped reserves decreased slightly primarily due to higher LOE costs related to rental equipment, manpower and field fuel use. The Company anticipates LOE costs in the Williston Basin to decrease over time due to increased efficiencies at the field level, including electrification of certain fields.

As of June 30, 2013, no proved reserves had been booked in the Company's significant leasehold acreage position owned in the Utica Shale in the Appalachian Basin (80,000+ net acres) where the Company has initiated an active exploratory drilling program. The Company also expects a significant increase in reserves during the second half of 2013 due to “pad” related drilling in Appalachia for both the Utica and Marcellus Shales. Given the Company's successful drilling results to date, as well as those of other operators in the vicinity of its leasehold acreage, the Company believes that a substantial portion of its Utica Shale acreage will be added to proved reserves over time as more wells are drilled and delineated in this region. The Appalachian Basin accounted for 65% of the Company's proved reserve volumes at June 30, 2013, the Williston Basin accounted for 34% and other legacy assets, including our remaining assets in South Texas, accounted for the remaining 1%. At mid-year 2013, 50% of the Company's proved reserves by volume were natural gas, 38% were crude oil and 12% were NGLs.

The present value of estimated future cash flows discounted at an annual rate of 10%, referred to as PV-10, of the Company's proved reserves at June 30, 2013 decreased to $666.4 million from $753.4 million at December 31, 2012, excluding the Eagle Ford Properties Sale described under “Eagle Ford Properties Sale” (see “Non-GAAP Financial Measures and Reconciliations,” below). Under the SEC guidelines, the commodity prices used in the June 30, 2013 and December 31, 2012 PV-10 estimates were based on the 12-

month unweighted arithmetic average of the first day of the month prices for the period July 1, 2012 through June 1, 2013 and for the period December 30, 2011 through November 30, 2012, respectively, adjusted by lease for transportation fees and regional price differentials. For crude oil and NGL volumes, the average West Texas Intermediate posted price of $91.60 per barrel was used to calculate PV-10 at June 30, 2013, which was down 3.3% from the average price of $94.71 per barrel used to calculate PV-10 at December 31, 2012. For natural gas volumes, the average Henry Hub spot price of $3.46 per million British thermal units (“MMBTU”) was used to calculate PV-10 at June 30, 2013, which was up 26% from the average price of $2.75 per MMBTU used to calculate PV-10 at December 31, 2012. All prices were held constant throughout the estimated economic life of the properties.

The December 31, 2012 proved reserves and and the June 30, 2013 3P reserves and the related PV-10 values of the proves reserves as of such dates exclude the reserves and related PV-10 values associated with the Eagle Ford Properties Sale, which closed on April 24, 2013.

For a reconciliation of PV-10, a non-GAAP financial measure, to the standard measure of financial future net cash flow, see “Properties—Non-GAAP Measures; Reconciliations.”

SEC Case Reserve Summary at December 31, 2012



	At December 31, 2012
	Proved Reserves(a)	PV-10 (b)(c)		% Proved Developed	% Oil/Liquids
	Proved Reserves(a)	PV-10 (b)(c)				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 “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" to our consolidated financial statements 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 “Properties-Other Properties”.


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

NYMEX Futures Strip Case Reserve Summary at December 31, 2012



	At December 31, 2012
	Proved Reserves(a)	PV-10 (b)(c)		% Proved Developed	% Oil/Liquids	Productive Wells
	Proved Reserves(a)	PV-10 (b)(c)				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 “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 “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 deliver 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 September 30, 2013, we had a total of approximately 494,840gross acres (323,956 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

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 are exploring the possible monetization in 2014 of all or part of our midstream operations. We have also identified a number of properties, that we believe represent up to $300 million in aggregate value, for possible divestiture in 2013 and 2014. These assets include the Company's remaining properties in south Texas and certain properties in North Dakota, Kentucky, and Canada.

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 September 30, 2013, following our sale of the Eagle Ford Properties, we were operating approximately 79.4% 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. Approximately 45% 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 September 30, 2013, we had total liquidity of approximately $223 million, including cash on hand of approximately $55.6 million and approximately $167.8 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.

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) the net proceeds Magnum Hunter received from the now completed sale of all of the Penn Virginia common stock it received as partial consideration for its sale of the Eagle Ford Properties; 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 September 30, 2013, we held ownership interests in approximately 4,383 gross (3,050.1 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 September 30, 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 353 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 860 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 September 30, 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 Team with 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.

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). In accordance with the stock purchase agreement, the Company supplied Penn Virginia with its calculation of the final cash purchase price adjustments on August 22, 2013, with final settlement expected to occur within 60 days of that date. 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 September 30, 2013, we continued to own (a) approximately 6,200 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.

As a result of the Eagle Ford Properties Sale, the Eagle Ford Properties have been classified as discontinued operations in the Company's financial statements as filed for the three and six months ended June 30, 2013 and 2012 and the revised financial statements for the fiscal years ended December 31, 2012, 2011 and 2010 in the Financial Statements section in this prospectus and such revised financial statements are taken into account in the “Results of Operations” section below.

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 three wells in Washington County and Monroe County, Ohio to test the Utica Shale formation. In connection with this planned test development, Triad Hunter has drilled 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 ten horizontal wells. Triad Hunter spud its first Utica Shale test well from the Farley Pad in April 2013. The Company has deemed this well to be a “tight-hole” for competitive reasons and therefore, no disclosure regarding any specifics concerning the completion of this well is being made at this time.

Triad Hunter also has constructed a Utica Shale drilling pad in Monroe, County, Ohio, designed to drill up to 18 horizontal wells. Triad Hunter has drilled a vertical pilot and horizontal Marcellus well. The first Utica vertical pilot is now drilling, and subsequent horizontal Utica well will follow. Plans are to test both horizontal wells by year end. Both wells are part of Triad's 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 rich 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.

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.

MNW Energy, LLC Acquisition. Effective August 13, 2013, Triad Hunter entered into definitive agreements to lease and/or sublease the "deep rights" (defined as rights to the Marcellus Shale and below) in approximately 32,000 acres located in Washington, Noble and Monroe Counties, Ohio, for approximately $142.1 million. Triad Hunter will have 10 months to perform due diligence and consummate the transaction. Triad Hunter anticipates multiple closings over the next 10 months affecting three to four thousand acres per closing.

Transactions Impacting Williston Basin Position

The Company’s activity in the Williston Basin included the acquisition of assets from Samson, Baytex and Eagle Operating, the entry into a gas gathering agreement with Oneok and the disposition to Oasis. 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 associated natural gas production from our oil properties in Divide County, North Dakota dedicated by us to Oneok for this purpose.

100

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.

Oasis Disposition. On September 2, 2013, Williston Hunter, Inc., a wholly owned subsidiary of the Company, entered into a purchase and sale agreement with Oasis Petroleum of North America LLC, or Oasis, to sell Williston Hunter's non-operated working interest in certain oil and gas properties located in Burke County, North Dakota, consisting of a non-operated working interest in approximately 51,495 gross (14,500 net) leasehold acres for consideration of $32.5 million in cash, subject to customary adjustments. The transaction closed on September 27, 2013, and was effective as of July 1, 2013.

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 20 miles of additional pipeline. As of September 30, 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 September 30, 2013, we were flowing approximately 60,000 mcf of natural gas per day through the Eureka Hunter Gas Gathering System. Through put has been reduced temporarily while the Mobley Processing Plant is restored to service following a break in a NGL pipeline associated with the plant. See "Business-Midstream Operations-Mobley Gas Processing Operations."

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.

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.

On September 27, 2013, MarkWest announced a temporary shut-down of the Mobley Processing Plant resulting from a break that occured August 13, 2013 in a MarkWest natural gas liquids pipeline caused by a landslide in a remote area of Wetzel County, West Virgina. MarkWest indicated that it expects to complete repairs to the pipeline in mid-October 2013. As a result of the temporary shut-down of the Mobley Processing Facilities, the Eureka Hunter Gas Gathering System’s natural gas throughput volumes (on an mcf per day basis) to the Mobley Processing Facilities have been reduced by approximately 75%. Currently, the natural gas volumes that are delivered by the Eureka Hunter Gas Gathering System to the Mobley Processing Facilities are being bypassed around the facilities (and therefore are not being processed) for sale in the interstate market. Eureka Hunter is also redirecting some of the natural gas volumes gathered through the Eureka Hunter Gas Gathering System that would have been delivered to the Mobley Processing Facilities (and therefore are not being processed) to another interstate sales outlet. The shut-down of the Mobley Processing Facilities has also resulted in the temporary shut-in by Triad Hunter of approximately 20,000 mcfe per day of natural gas production from its Marcellus Shale acreage. The Company expects all the foregoing described effects of the shut-down to continue until the Mobley Processing Facilities are back on-line, which is currently expected to be mid-October 2013.

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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 $73 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 September 30, 2013, we owned approximately 57.4% and Ridgeline owned approximately 40.6% 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 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 September 30, 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 September 30, 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 offering expenses, were approximately $431.1 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

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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.

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 prospectus 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 “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.

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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, 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 “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 “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,

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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 “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. 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.

Employees

As of September 30, 2013, we had approximately 459 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 under a lease that expires in April 2016. 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. Our Eureka Pipeline subsidiary purchased an existing building in July 2013 located in Reno, Ohio, which is approximately 7,744 square feet. The building is awaiting remodeling before occupancy. 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.

Eureka Pipeline maintains offices consisting of approximately 7,700 square feet of office space in a building we own in Reno, Ohio.

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 approximately 3,300 square feet of office space, under a lease that expires in 2016, 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" to our consolidated financial statements. For information regarding our major customers for fiscal years 2010, 2011 and 2012, see "Note 15 - Major Customers" to our consolidated financial statements. This information is incorporated in this "Business" section by reference.

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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.

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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 prospectus 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 prospectus and “Risk Factors” for additional discussion of some of these factors and risks.

Business Overview

On April 24, 2013, we monetized certain of the Company's 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 for a total purchase price of $422.1 million, paid to us in the form of $379.8 million in cash (after customary initial purchase price adjustments) and $42.3 million in Penn Virginia common stock (valued based on the closing market price of the stock of $4.23 per share as of April 24, 2013). In accordance with the stock purchase agreement, the Company supplied Penn Virginia with its calculation of the final cash purchase price adjustments on August 22, 2013, with final settlement expected to occur within 60 days. 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 and Utica Shale plays in Appalachia and our Bakken and Sanish plays in the Williston Basin. See "Note 6 - Divestments and Discontinued Operations" to our consolidated financial statements for further details.

Our midstream operations are conducted through our majority-owned subsidiary, Eureka Hunter Holdings. Eureka Hunter Holdings conducts its operations primarily through the following two subsidiaries: (i) Eureka Hunter 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, 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 ("Alpha Hunter"), 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 robotic walking drilling rig that can also drill the horizontal sections of wells in the shale plays where we are active. This drilling rig was designed especially for pad drilling with its unique footprint and capability to walk and rotate without being dismantled.

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Summary of Principal Upstream Properties

Appalachian Basin

As of September 30, 2013, our Appalachian Basin properties included approximately 527,378 gross (462,372 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 38.8 mmboe on a NYMEX basis. As of September 30, 2013, our Appalachian Basin properties included approximately 3,918 gross (2,790.7 net) productive wells, of which we operated approximately 83%.

Williston Basin

As of September 30, 2013, our Williston Basin properties included approximately 182,310 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 September 30, 2013, our Williston Basin properties included approximately 446 gross (251.9 net) productive wells, of which we operated approximately 49%.

Summary of Midstream Operations

Eureka Pipeline

As of September 30, 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 and are currently constructing approximately 20 miles of 20-inch pipeline in Monroe County, Ohio.

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 September 30, 2013, our wholly-owned subsidiary, Alpha Hunter Drilling, owned and operated five 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.

At September 30, 2013, four 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 through December 2014, one Schramm T200XD drilling rig was under contract to an independent producer in the Appalachian Basin and will also be utilized by Triad Hunter for its top hole program, and the Schramm T500XD drilling rig was under contract to the Company to implement 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.

Recent Events

Agreement to Purchase Utica Shale Acreage

The structure of the transaction is such that the members of the association will transfer all or from time-to-time, portions of the Subject Acreage to MNW. Following such transfers, MNW will offer the Subject Acreage to Triad Hunter and, pursuant to the Purchase Agreement, Triad Hunter will have a ten month review period from the effective date of the relevant lease or sublease to MNW during which Triad Hunter has the right to examine each lessor's or sublessor's title to the leased acreage and the provisions of the lease and subleases for title defects. MNW is obligated to cure any defects in the title or the lease terms that Triad Hunter objects to during the review period. Subject to the terms of the Purchase Agreement, Triad Hunter may reject the leases and subleases that have defects that MNW cannot cure to Triad Hunter's satisfaction. If Triad Hunter rejects any Subject Acreage due to title or lease defects, MNW will offer Triad Hunter replacement acreage pursuant to the terms of the Purchase Agreement. After Triad Hunter conducts its review of the Subject Acreage, MNW will assign to Triad Hunter and Triad Hunter will purchase from MNW the Subject Acreage that is satisfactory to Triad Hunter.

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The Subject Acreage is expected to be acquired in multiple closings, with a closing to occur each time Triad Hunter has reviewed and approved title to at least $15,000,000 in aggregate Purchase Price of the Subject Acreage. Notwithstanding the foregoing, the parties are required to close no more than every 30 days on the Subject Acreage that is satisfactory to Triad Hunter after completion of its title and lease review. At each closing, MNW will execute an assignment in the form provided in the Purchase Agreement, and the lessors and sublessors will also deliver ratifications of the leases and subleases being closed upon.

The Purchase Agreement provides that Triad Hunter will acquire the Subject Acreage for $4,441.25 per net mineral acre; provided, however, that the price per net mineral acre will be reduced to $3,330.94 for any portion of subleased acreage for which the terms of the underlying lease contain a defect that materially reduces the value of such underlying lease, but which Triad Hunter is nevertheless willing to accept pursuant to the Purchase Agreement. The maximum aggregate purchase price for MNW's delivery of 32,000 net mineral acres of leased and subleased acreage with acceptable title and lease terms is $142.1 million.

The Purchase Agreement contains certain representations, warranties, covenants and indemnities by the parties as described therein. A copy of the Purchase Agreement was previously filed as an exhibit to this prospectus.

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, referred to as the Eagle Ford Properties Sale, 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 (after customary initial purchase price adjustments) and $42.3 million in Penn Virginia common stock (valued based on the closing market price of the stock of $4.23 per share as of April 24, 2013). In accordance with the stock purchase agreement, the Company supplied Penn Virginia with its calculation of the final cash purchase price adjustments on August 22, 2013, with final settlement expected to occur within 60 days of that date. 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 Eagle Ford Properties included approximately 19,000 net Eagle Ford Shale leasehold acres. As a result of our sale of the Eagle Ford Properties, we are now strategically focused on our Marcellus Shale and Utica Shale plays in Appalachia and our Bakken and Sanish plays in the Williston Basin.

Sale of Certain North Dakota Oil and Gas Properties

On September 2, 2013, Williston Hunter, Inc., a wholly owned subsidiary of the Company, entered into a purchase and sale agreement with Oasis Petroleum of North America LLC, or Oasis, to sell its non-operated working interest in certain oil and gas properties located in Burke County, North Dakota, consisting of a non-operated working interest in approximately 51,495 gross (14,500 net) leasehold acres for consideration of $32.5 million in cash, subject to customary adjustments. The transaction closed on September 27, 2013, and was effective as of July 1, 2013.

Equity Financings

We raised cash in the total amount of $30.1 million in net proceeds, after offering discounts, commissions and placement fees, but before other offering expenses, through equity transactions from January 1, 2013 through September 30, 2013. Those transactions included:


•	$9.6 million in net proceeds from issuances of our Series D Preferred Stock, at an average gross sales price of $45.34 per share;


•	$590,000 in net proceeds from issuances of Depositary Shares representing our Series E Preferred Stock, at an average gross sales price of $24.24 per Depositary Share; and


•	$27.4 million in net proceeds from issuances of Series A Preferred Units of Eureka Hunter Holdings.

We may continue raising both preferred and common equity in the future depending on our working capital needs, capital expenditure program, acquisition activities, and the condition of the capital markets. However, as a result of our failure to file our 2012 Form 10-K and First Quarter 2013 Form 10-Q within the time frames required by the SEC, we may be limited for a period of time 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.

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Until we have timely filed all our required SEC reports for a period of twelve months, which period we expect to expire in August 2014, assuming we remain timely in the filing of our SEC reports for that period, 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 ATM offerings of our equity securities. We had conducted ATM offerings 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 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.

Common Stock Options Granted to Employees, Officers and Directors

See "Note 9 - Share-Based Compensation" of our consolidated financial statements for details relating to stock option grants to employees, officers and members of our board of directors.

Increase in the Number of Authorized Common 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.

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 Holdings capital requirements, which Ridgeline did in April 2013, with the next $70.5 million of such capital requirements to be funded by the Company and Ridgeline on a 60%/40% basis, respectively. After giving effect to this equity contribution by Magnum Hunter and the issuances of Series A Preferred Units noted above, as of September 30, 2013, the Company had a 57.4% controlling interest in Eureka Hunter Holdings.

Issuance of Series A Preferred Units of Eureka Hunter Holdings

During 2013, Eureka Hunter Holdings issued 1,400,000 Series A Preferred Units to Ridgeline for net proceeds of $27.4 million, after transaction costs. The Series A Preferred Units outstanding at September 30, 2013 represent 40.6% of the ownership of Eureka Hunter Holdings on a basis as converted to Class A Common Units of Eureka Hunter Holdings.

On July 25, 2013, Eureka Hunter Holdings issued 88,901 of Series A Preferred Units with a redemption value of $1.8 million for dividends paid-in-kind subsequent to June 30, 2013 through August 7, 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 robotic walking 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 and components were $14.6 million, of which $1.1 million remained due in equal installments over twelve months beginning once certain operating criteria are met.

Filing of Annual Report on Form 10-K

On June 14, 2013, we filed with the SEC our 2012 Form 10-K.

Filing of Quarterly Report on Form 10-Q

On July 9, 2013, we filed with the SEC our First Quarter 2013 Form 10-Q.

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Sale of Penn Virginia Common Stock

During July 2013 through September 10, 2013, the Company sold all of its remaining shares of Penn Virginia common stock, which the Company acquired as partial consideration for its sale of Eagle Ford Hunter to Penn Virginia. The Company sold each of its shares of Penn Virginia common stock for a weighted average of $5.06 per share for total net consideration of approximately $50.4 million in cash.

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 that, as of December 31, 2012, the Company's internal control over financial reporting was not effective due to the material weaknesses described in the "Controls and Procedures" section of this prospectus. 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 its 2012 Form 10-K or its First Quarter 2013 Form 10-Q, by the required SEC filing deadlines. The Company made these two filings on June 14, 2013 and July 9, 2013, respectively.

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 "Controls and Procedures" section of this prospectus 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.

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•

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.

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 "Business” and "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.

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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.

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" to our consolidated financial statements, 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.

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

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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.

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.

Goodwill and 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

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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

Three and Six Months Ended June 30, 2013 and 2012

The following table sets forth summary information regarding oil, natural gas and NGLs, revenues, production, average product prices and average production costs and expenses for the three and six months ended June 30, 2013 and 2012.



		Three Months Ended June 30,				Six Months Ended June 30,
		2013		2012		2013		2012
Oil and gas revenue and production
Revenues (in thousands, U.S. Dollars)
Oil	US	$	35,869	$	19,199	$	63,077	$	32,683
	Canada	8,330		7,357		20,935		16,295
Gas	US	17,646		9,272		28,727		22,858
	Canada	203		114		376		224
NGLs	US	4,409		1,242		5,907		2,900
	Canada	—		1		—		7
Total oil and gas sales		$	66,457	$	37,185	$	119,022	$	74,967

Production
Oil (mbbls)	US	421		240		732		391
	Canada	93		91		245		186
Gas (mmcfs)	US	4,451		3,802		7,227		8,156
	Canada	45		61		91		125
NGL (mboe)	US	114		35		158		71
Total (mboe)		1,376		1,008		2,355		2,028
Total (boe/d)		15,125		11,089		13,009		11,141

Average prices (U.S. Dollars)
Oil (per bbl)	US	$	85.20	$	80.35	$	86.11	$	83.75
	Canada	$	89.69	$	80.85	$	85.54	$	87.38
Gas (per mcf)	US	$	3.96	$	2.44	$	3.98	$	2.80
	Canada	$	4.46	$	1.87	$	4.12	$	1.80
NGL (per boe)	US	$	38.93	$	35.55	$	37.45	$	41.06
Total average price (per boe)		$	48.28	$	36.85	$	50.55	$	36.97

Costs and expenses (per boe)
Lease operating expense		$	14.98	$	10.62	$	13.90	$	10.62
Severance tax and marketing		$	3.53	$	2.72	$	3.42	$	2.74
Exploration and abandonment expense		$	3.75	$	9.33	$	14.84	$	9.09
Impairment of proved oil and gas property		$	11.65	$	—	$	6.81	$	—
General and administrative expense (see Footnote 1 below)		$	14.24	$	16.66	$	17.79	$	15.60
Depletion, depreciation and accretion		$	27.61	$	22.49	$	28.47	$	20.87

Midstream and oilfield service segments (in thousands) ⁽²⁾
Midstream and marketing operations segment revenue		$	16,151	$	4,213	$	33,453	$	5,377
Midstream and marketing operations segment expense		$	18,749	$	3,956	$	36,104	$	4,856
Oilfield services segment revenue		$	3,690	$	1,392	$	7,421	$	5,984
Oilfield services segment expense		$	4,775	$	1,525	$	8,812	$	4,121

(1)

General and administrative expense includes: (i) acquisition and divestiture related expenses of $294,000 for the three months in 2013 ($0.21 per boe) and $1.8 million for the three months in 2012 ($1.56 per boe), (ii) acquisition and divestiture related expenses of $1.8 million ($0.75 per boe) for the six months in 2013 and $2.6 million ($1.10 per boe) for the six months in 2012, (iii) non-cash stock compensation of $2.4 million ($1.78 per boe) for the three months in 2013 and $7.9 million ($7.84 per boe) for the three months in 2012, and (iv) non-cash stock compensation of $8.7 million ($3.69 per boe) for the six months in 2013 and $12.5 million ($6.16 per boe) for the six months in 2012.

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(2)	Midstream and oilfield service segment revenue and expense includes all revenue and expense for the segment, as further detailed in "Footnote 15 - Segment Reporting."

Three Months Ended June 30, 2013 and 2012

Oil and gas production. Production increased by 36.5%, or 368 mboe, to 1,376 mboe for the three months ended June 30, 2013 compared to the three months ended June 30, 2012. Our average daily production was 15,125 boepd during the 2013 period, representing an overall increase of 36.4%, or 4,036 boepd, compared to 11,089 boepd for the 2012 period. The increase in production in 2013 is primarily attributable to organic growth through the Company’s expanded drilling program which focused mainly on oil and NGLs. However, the increase in production during the three months ended June 30, 2013 was offset by the shut-in of an average of approximately 1,873 boepd of Marcellus Shale production. Including these production shut-ins, our production was 16,998 boepd on a pro forma basis for the three months ended June 30, 2013. These production shut-ins were due to complications with our midstream subsidiary in bringing on our production after MarkWest’s Mobley, West Virginia gas processing plant was completed late in 2012. The Company experienced higher than anticipated NGLs present in its Marcellus production which necessitated that Eureka Hunter Pipeline implement a pigging process at its gathering lines. Once the pigging process was implemented, the Company was also further delayed as new air permits for compression facilities were required from the State of West Virginia. The gathering issues related to the Marcellus production shut-in were resolved in May 2013. These production shut-ins were largely natural gas and NGLs, thus the impact on the Company’s cash flow was substantially less than any reduction in our oil volumes. Production for 2013, on a boe basis, was 46.0% oil and NGLs and 54.0% natural gas compared to 36.0% oil and NGLs and 64.0% natural gas for 2012. The change in production mix toward more oil and NGLs was attributable to increased focus on the development of more oil production in the Williston Basin region.

U.S. Upstream segment. In our U.S. Upstream operating segment, production increased 41%, from 907 mboe to 1,277 mboe for the three months ended June 30, 2013 compared to the three months ended June 30, 2012. Production for 2013 on a boe basis was 42.0% oil and NGLs and 58.0% natural gas compared to 30.0% oil and NGLs and 70.0% natural gas for 2012 reflecting the Company’s focus on oil and NGLs in 2013. Our average daily production increased from 11,087 boepd to 13,467 boepd during 2013 compared to 2012. This increase in production for the U.S. Upstream segment in 2013 compared to 2012 was primarily attributable to organic growth through the Company’s expanded drilling program. In April 2012, we divested our Eagle Ford Hunter subsidiary. The division is considered discontinued operations and as such the historical production for Eagle Ford Hunter of 2.47 mboepd for the three months ended June 30, 2013 and 1.87 mboepd for the three months ended June 30, 2012 is no longer included in U.S. Upstream segment production revenues or volumes.

Canadian Upstream segment. Production decreased slightly in the Canadian Upstream operating segment by 1.0%, or 1.0 mboe, to 100 mboe for the three months ended June 30, 2013 from 101 mboe for the three months ended June 30, 2012. Production from the Canadian segment comprised 93.0% oil and NGLs and 7.0% natural gas on a boe basis in 2013 compared to 90.0% oil and NGLs and 10.0% natural gas on a boe basis in 2012.

Oil and gas sales. Oil and gas sales increased 78.7%, or $29.3 million, for the three months ended June 30, 2013 to $66.5 million from $37.2 million for the three months ended June 30, 2012. 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 operations focused on oil and NGLs in our unconventional resources plays throughout 2013. The average price we received for our production increased from $36.85 per boe to $48.28 per boe, or 31.0%, primarily as a result of our higher volumes of oil and NGLs over natural gas on a percentage basis. 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 and marketing operations. Revenue from the midstream operations segment (which consisted of Eureka Hunter Pipeline, TransTex Hunter, and Magnum Hunter Marketing operations in 2013) increased by $11.9 million, or 283.4%, for the three months ended June 30, 2013 to $16.2 million from $4.2 million for the three months ended June 30, 2012. Magnum Hunter Marketing revenues increased by $8.7 million to $9.4 million in the three month period ended June 30, 2013, compared to $733,000 in the same period in 2012 due to the ramp up of marketing operations targeting third-party producers. Eureka Hunter Pipeline revenue increased by $323,000 to $1.4 million for the three months ended June 30, 2013 from $1.1 million for the three months ended June 30, 2012. Eureka Hunter Pipeline increased throughput volumes by 181.0% or 4.9 million mmbtu to 7.5 million mmbtu for the three month period ended June 30, 2013 from 2.7 million mmbtu for the period ended June 30, 2012. During the three months ended June 30, 2013, TransTex Hunter’s revenues were $3.2 million compared to $2.3 million for the three month period ended June 30, 2012. TransTex Hunter’s revenues are primarily related to fees earned by treating natural gas at the wellhead for third-party producers in Texas and other states.

Expenses from the midstream operations increased by $14.8 million, or 373.9%, for the three months ended June 30, 2013 to $18.7 million from $4.0 million for the three months ended June 30, 2012. Magnum Hunter Marketing expenses increased by $9.9 million to $10.5 million in the three month period ended June 30, 2013, compared to $713,000 in the same period in 2012 due to the ramp up of marketing operations targeting third-party producers. Eureka Hunter Pipeline expenses increased by $679,000 to $845,000 for the three months ended June 30, 2012 from $166,000 for the three months ended June 30, 2012. During the three months ended

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June 30, 2013, TransTex Hunter’s expenses were $2.0 million compared to $1.1 million for the three month period ended June 30, 2012.

Oil field services. Drilling services revenue increased by 165.1%, or $2.3 million, for the three months ended June 30, 2013 to $3.7 million from $1.4 million for the three months ended June 30, 2012. Revenues from oilfield services are comprised primarily of drilling rig rentals and operations to third parties.

Lease operating expense. Our lease operating expenses, or LOE, increased $9.9 million, or 92.6%, for the three months ended June 30, 2013 to $20.6 million ($14.98 per boe) from $10.7 million ($10.62 per boe) for the three months ended June 30, 2012. The increase in LOE was comprised of $6.0 million attributable to higher LOE per boe costs, and increased volumes, which accounted for $3.9 million. The increase in LOE costs per boe for the three months ended June 30, 2013 was primarily related to higher LOE costs associated with the increased percentage of our production being oil and NGLs which generally have higher LOE costs per boe than natural gas. In addition, LOE costs per boe increased in the Williston Basin division due to increased rental equipment costs. The Company expects lease operating expense per boe costs to decline in the second half of 2013 due to adding efficiencies such as electrification of fields.

Exploration and abandonments. We record exploration costs, geological and geophysical, and unproved property impairments and leasehold expiration as exploration and abandonment expense. We recorded $5.2 million of exploration and abandonment expense for the three months ended June 30, 2013, compared to $9.4 million for the three months ended June 30, 2012. During the 2013 period, the Company’s exploration and abandonment expense was primarily attributable to $4.8 million of leasehold impairments on leases in the Williston Basin region expiring in the quarter ended June 30, 2013, and impairment of leases that we do not plan to develop or extend in the third quarter and fourth quarter of 2013. The significant component of the Company’s exploration and abandonment expense during the three months ended June 30, 2012 consisted of a $9.0 million impairment of our Williston Basin unproved oil and gas properties which expired undrilled prior to June 30, 2012.

Impairment of proved oil & gas properties. Proved oil and natural gas properties are reviewed for impairment on a field-by-field basis when events and circumstances indicate a possible decline in the recoverability of the carrying amount of such property. We estimate the expected future cash flows of our oil and natural gas properties and compare these undiscounted cash flows to the carrying amount of the oil and natural gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, we will write down the carrying amount of the oil and natural gas properties to fair value. The factors used to determine fair value include, but are not limited to, estimates of reserves, future commodity prices, future production estimates, estimated future capital expenditures and discount rates commensurate with the risk associated with realizing the projected cash flows.

During the three months ended June 30, 2013, changes in production estimates and lease operating costs provided indications of possible impairment of the Company’s proved properties in the Williston and Appalachian Basins. As a result of management’s assessments, during the second quarter of 2013, the Company recognized pretax non-cash impairment charges of $16.0 million to reduce the carrying value of these properties to their estimated fair values. The Company calculated the estimated fair value as of June 30, 2013 using a discounted cash flow model. The expected future net cash flows were discounted using an annual rate of 10 percent to determine estimated fair value.

Oilfield services expenses. Oilfield services expenses increased by $3.3 million, or 213.1% for the three months ended June 30, 2013 to $4.8 million from $1.5 million for the three months ended June 30, 2012 due to increased personnel attributable to a combination of additional rigs in service and higher utilization of additional rigs.

Depletion, depreciation, amortization, and accretion. Our depletion, depreciation and accretion expense, or DD&A, increased $15.3 million, or 67.6%, to $38.0 million for the three months ended June 30, 2013 from $22.7 million for the three months ended June 30, 2012 due to increases in capitalized costs subject to DD&A, as a result of our capital expenditures and acquisition programs in 2012, and increased production in 2013. Our DD&A per boe increased by $5.12, or 22.8%, to $27.61 per boe for the three months ended June 30, 2013, compared to $22.49 per boe for the three months ended June 30, 2012. The increase in DD&A per boe was primarily attributable to additional production from new oil wells drilled during the first quarter in the Williston Basin. These oil wells generally have a higher cost to drill and complete and a greater initial depletion rate than wells completed in prior years, which consisted of more natural gas wells and generally have a lower DD&A per boe rate.

General and administrative. Our general and administrative expenses, or G&A, increased $2.8 million, or 16.7%, to $19.6 million or $14.24 per boe for the three months ended June 30, 2013 from $16.8 million or $16.66 per boe for the three months ended June 30, 2012. G&A expenses increased overall during 2013 mainly due to accounting personnel and professional accounting and advisory services necessitated by the recent growth of the Company. The non-cash stock compensation expense totaled approximately $2.4 million or $1.78 per boe for the three months ended June 30, 2013 and $7.9 million or $7.84 per boe for the three months ended June 30, 2012. Non-cash stock compensation expense decreased as a result of the Company granting no stock options in the quarter ended June 30, 2013 compared to 4.8 million stock options with an associated expense of $6.6 million granted during the same period of 2012. Acquisitions and divestiture related costs, comprised primarily of legal and other professional fees, were $294,176 or $0.21 per boe for the 2013 period, compared to $1.8 million or $1.79 per boe of acquisition and divestiture related costs in 2012.

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Interest expense, net. Our interest expense, net of interest income, decreased by 3.2%, to $18.7 million from $19.4 million for the three months ended June 30, 2013 compared to the three months ended June 30, 2012. Our lower average debt level in the second quarter due to the repayment of debt with the net cash proceeds from the sale of Eagle Ford Hunter accounted for the majority of the decrease in the 2013 quarter, offset by the write off of $800,000 in deferred financing charges as a result of the Seventeenth Amendment to our MHR Senior Revolving Credit Facility. Interest on projects lasting six months or greater is capitalized. During the three months ended June 30, 2013 we capitalized $573,000 and we did not capitalize interest in the three months ended June 30, 2012.

Commodity and financial derivative activities. Net gains from our commodity and financial derivative activity increased our earnings by $6.4 million and $18.1 million for the quarters ended June 30, 2013 and 2012, respectively. The following table summarizes the realized and unrealized gains and losses on change in fair value of our derivative contracts as of the dates indicated:



	Three Months Ended June 30,
	2013			2012
	(in thousands)
Realized gain (loss)	$	(1,261	)	$	4,251
Unrealized gain (loss)	7,661			13,853
Net gain (loss)	$	6,400		$	18,104

We continue not to designate our derivative instruments as cash-flow hedges for 2013 and 2012. See “Note 5 - Financial Instruments and Derivatives” for further details regarding our commodity and financial derivatives.

At June 30, 2013, 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. See “Note 5 – Fair Value of Financial Instruments” and “Note 11 — Redeemable Preferred Stock,” for more information. This contract resulted in an unrealized loss of $11.4 million in the three months ended June 30, 2013. Also at June 30, 2013, 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. See “Note 4 – Fair Value of Financial Instruments,” “Note 6 – Divestitures and Discontinued Operations” and “Note 13 – Related Party Transactions,” for additional information. An unrealized gain of $211,000 is recorded for this contract in 2013. Both contracts originated in 2012 and have resulted in no cash outlays as of June 30, 2013.

Income tax benefit. The Company recorded an income tax benefit of $43.6 million and $6.9 million for the three months ended June 30, 2013 and 2012, respectively. The increase is a result of the tax effect of gain on sale of the Eagle Ford Hunter subsidiary in the three month period ended June 30, 2013.

Net income attributable to non-controlling interest. Net income attributable to non-controlling interest was approximately $386,000 for the three months ended June 30, 2013 versus net loss of $48,000 for same period in 2012. This represents 12.5% of the gain or loss incurred by our subsidiary, PRC Williston, LLC and 2.5% of the gain or loss incurred by our subsidiary, Eureka Hunter Holdings.

Discontinued operations. On April 24, 2013, we closed on the sale of Eagle Ford Hunter, previously a wholly-owned subsidiary. On June 30, 2013, income from the operations of and gain related to the sale of Eagle Ford Hunter was determined to be discontinued operations. We reclassified operating loss of $2.4 million, net of tax, for the divested subsidiary for the three months ended June 30, 2013 and operating income of $2.4 million, net of tax, for the three months ended June 30, 2012. We recorded a gain on sale of discontinued operations of $172.5 million, net of tax in the three months ended June 30, 2013.

Loss from continuing operations. We incurred net losses from continuing operations of $5.0 million and $16.9 million in the three months ended June 30, 2013 and 2012, respectively. Our 2013 revenues increased to $84.0 million compared to $42.5 million in 2012; however, our 2013 operating loss increased to $37.7 million, compared to $23.4 million in 2012 due to an increase in our operating expenses. The increase in the operating expenses in the three month period 2013 was principally due to increases in proved property impairments of $16.0 million, compared to none in the three month period 2012. Exploration and abandonment expense decreased $4.3 million compared to 2012. In addition, during the three months ended June 30, 2013, non-cash stock compensation expense decreased to $2.4 million from $7.9 million in 2012, and acquisition related expenses decreased to $0.3 million for the three months ended June 30, 2013 from $1.8 million in 2012.

Dividends on preferred stock. Dividends on our Series A, Series C, Series D, and Series E Preferred Stock were $14.1 million for the three months ended June 30, 2013 compared to $8.2 million in 2012.

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The Series E Preferred Stock had a stated value of $95.1 million and $94.4 million as of June 30, 2013 and December 31, 2012, respectively, and carries a cumulative dividend rate of 8.0% per annum. The Series D Preferred Stock had a stated value of $221.2 million at June 30, 2013, compared to $210.4 million at December 31, 2012. The Series D Preferred Stock carries a cumulative dividend rate of 8.0% per annum. The Series C Preferred Stock had a stated value of $100.0 million at June 30, 2013 and December 31, 2012, and carries a cumulative dividend rate of 10.25% per annum. The Series A Convertible Preferred Units of Eureka Hunter Holdings had a liquidation preference of $202.4 million and $167.4 million as of June 30, 2013 and December 31, 2012, respectively, and carries a cumulative dividend rate of 8.0% per annum.

Net income (loss) attributable to common shareholders. Net income attributable to common shareholders was $151.3 million in the three months ended June 30, 2013 versus a net loss of $22.7 million in 2012. Our net income per common share, basic and diluted, was $0.89 per share in the three months ended June 30, 2013 compared to a net loss $0.15 per share in 2012. The increase in income is related to the gain on the sale of discontinued operations of $172.5 million, partially offset by the increase of loss on continuing operations of $15.7 million. Our weighted average shares outstanding increased by 18.2 million shares, or 12.0%, to approximately 169.7 million shares, principally as a result of the shares issued for cash to finance acquisitions during 2012. Our net loss per share from continuing operations was $0.11 per share for the three months ended June 30, 2013, compared to a loss from continuing operations of $0.19 per share for the three months ended June 30, 2012.

Six Months Ended June 30, 2013 and 2012

Oil and gas production. Oil and gas production increased 16.1% to 2,355 MBoe for the six months ended June 30, 2013, from 2,028 MBoe for the six months ended June 30, 2012, primarily as a result of organic growth as a result of our drilling program in the Williston and Appalachian Basins. Production for the 2013 period was approximately 48.0% oil and 52.0% natural gas compared to 32.0% oil and 68.0% natural gas for the 2012 period. Our average daily production on a Boe basis increased 16.8% to 13,009 Boe/d for the 2013 period compared to 11,141 Boe/d for the 2012 period. The increase in production is primarily attributable to organic growth from the success of the Company’s ongoing drilling program in its shale plays. However, the increase in production during the six months ended June 30, 2013 was offset by the shut-in of approximately 2,500 boepd of Marcellus Shale production. Including these production shut-ins, our production would have been 15,502 boepd on a pro forma basis for the six months ended June 30, 2013. These production shut-ins were due to complications in bringing on line our production after MarkWest’s Mobley, West Virginia gas processing plant was completed late last year. The Company experienced higher than expected NGLs present in its Marcellus production which necessitated that Eureka Hunter Pipeline implement a pigging process at its gathering lines. Once the pigging process was implemented, the Company was also further delayed as new air permits for compression facilities were required from the State of West Virginia. The gathering issues related to the Marcellus production shut-in were resolved in May 2013. These production shut-ins were largely natural gas and NGLs, thus the impact on the Company’s cash flow was substantially less than any reduction in our oil volumes.

U.S. Upstream segment. Production increased in the US Upstream operating segment by 15.1% to 2,095 Mboe, for the six months ended June 30, 2013 from 1,820 Mboe for the six months ended June 30, 2012. Production for 2013 on a Boe basis was 42.0% oil and NGLs and 58.0% natural gas compared to 25.0% oil and NGLs and 75.0% natural gas for 2012. Our average daily production increased by 15.7% to 11,573 Boepd during 2013 compared to 10,004 Boepd for 2012. The increase in production is primarily attributable to organic growth from the success of the Company’s ongoing drilling program. In April 2012, we divested our Eagle Ford Hunter subsidiary. The division is considered discontinued operations and as such the historical production for Eagle Ford Hunter of 2.79 mboepd for the six months ended June 30, 2013 and 1.65 mboepd for the six months ended June 30, 2012 is no longer included in U.S. Upstream segment production revenues or volumes.

Canadian Upstream segment - Bakken/Three Forks Sanish. Canadian Upstream operating segment production increased 25.6% to 260 Mboe, for the six months ended June 30, 2013 from 207 Mboe for the six months ended June 30, 2012. Production for 2013 on a Boe basis was 94.0% oil and 6.0% natural gas compared to 90.0% oil and 10.0% natural gas for 2012. Our average daily production increased by 26.3% to 1,436 Boepd during 2013 compared to 1,137 Boepd for 2012. This increase in production for the Canadian Upstream segment in 2013 compared to 2012 is primarily attributable to organic growth through the Company’s ongoing drilling programs.

Oil and gas sales. Oil and gas sales increased $44.1 million, or 58.8% for the six months ended June 30, 2013, to $119.0 million from $75.0 million for the six months ended June 30, 2012. The increase in oil and gas sales principally resulted from increased production as described above. The average price we received for our oil increased $5.62 per bbl or 7.0% to $86.01 per bbl, while the average price received for gas production increased $1.54 per Mcf or 63.4% to $3.97 per Mcf. Our average price received for oil and gas production increased due to market trends in the prices for these commodities. Of the $44.1 million increase in oil and gas sales, approximately $32.0 million, or 72.6%, was attributable to an increase in price per Boe of $13.58, while approximately $12.1 million, or 27.4% of the increase in oil and gas sales was attributable to the increase in production volumes. 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 “Note 5 - Financial Instruments and Derivatives.”

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Oilfield services revenue. Oilfield services revenue increased by $1.4 million , or 24.0% for the six months ended June 30, 2013 to $7.4 million from $6.0 million for the six months ended June 30, 2012. This increase was primarily attributable to a combination of additional rigs in service and higher utilization of the existing fleet.

Gas transportation, gathering, processing, and marketing revenue. Revenue from the midstream and marketing segment which consisted of Eureka Hunter Pipeline, TransTex Hunter, and Magnum Hunter Marketing operations in 2013) increased by 522.1% or $28.0 million, for the six months ended June 30, 2013, to $33.5 million from $5.4 million for the year ended June 30, 2012. The increase in revenues resulted primarily from increased revenue in Magnum Hunter Marketing which increased $19.5 million to $20.2 million for the six month period ended June 30, 2013 from $733,000 for the six month period ended June 30, 2012. TransTex Hunter revenue increased $4.8 million to $7.1 million for the six month period ended June 30, 2013 from $2.3 million for the six month period ended June 30, 2012. Eureka Hunter Pipeline revenues increased $317,000 to $2.6 million for the six months ended June 30, 2013 from $2.3 million for the six month period ended June 30, 2012 as throughput volumes increased to 12.1 million mmbtu from 5.2 million mmbtu for the six month period ended June 30, 2013 compared to the six month period ended June 30, 2012.

Expenses from the midstream operations increased by $31.2 million, or 643.5% for the six months ended June 30, 2013 to $36.1 million from $4.9 million for the six months ended June 30, 2012. Magnum Hunter Marketing expenses increased by $20.3 million to $21.0 million in the six month period ended June 30, 2013, compared to $713,000 in the same period in 2012 due to the ramp up of marketing operations targeting third-party producers. Eureka Hunter Pipeline expenses increased by $1.2 million to $1.5 million for the six months ended June 30, 2012 from $286,000 for the six months ended June 30, 2012. During the six months ended June 30, 2013, TransTex Hunter’s expenses were $4.3 million compared to $1.1 million for the six month period ended June 30, 2012.

Other revenues. We recorded a net loss in other revenues of $418,686 for the six months ended June 30, 2013. For the six months ended June 30, 2012, we recorded a net loss on sale of assets of $174,000 related to the sale of a drilling rig by our oilfield services segment and various equipment from the Appalachian region of our upstream segment.

Lease operating expense. Our lease operating expenses increased $11.2 million, or 52.0% for the six months ended June 30, 2013, to $32.7 million ($13.90 per Boe) from $21.5 million ($10.62 per Boe) for the six months ended June 30, 2012. The increase in LOE was comprised of $7.7 million attributable to higher LOE per boe costs, and increased volumes, which accounted for $3.5 million. The increase in LOE costs per boe for the six months ended June 30, 2013 was primarily related to higher LOE costs associated with the increased percentage of our production being oil and NGLs which generally have higher LOE costs per boe than natural gas. In addition, LOE costs per boe increased in the Williston Basin due to workovers and increased rental equipment costs. The Company expects lease operating costs per boe to decline in the second half of the year due to efficiencies such as electrification of fields.

Severance taxes. Our severance taxes increased $2.5 million, or 44.7% for the six months ended June 30, 2013, to $8.0 million from $5.6 million for the six months ended June 30, 2012. All of the increase in severance taxes was attributable to the increase in oil and gas production.

Exploration and abandonment. We incurred $34.9 million of exploration and abandonment expense for the six months ended June 30, 2013, compared to $18.4 million for the six months ended June 30, 2012. During the 2013 period, the Company’s exploration and abandonment expense was primarily attributable to $29.5 million of leasehold impairments on leases in the Williston Basin region expiring in the quarter ended June 30, 2013, and impairment of leases that we do not plan to develop or extend in the third quarter and fourth quarter of 2013. In addition, we recorded $4.7 million of lease abandonment expense related to leases that expired undrilled prior to June 30, 2013. The significant components of the Company’s exploration and abandonment expense during the six months ended June 30, 2012 were abandonments of approximately $12.7 million on our Williston Basin unproved properties and $4.8 million of our Appalachian unproved properties under leases which expired undrilled prior to June 30, 2012.

Impairment of proved oil and gas properties. We recorded proved impairments of $16.0 million for the six months ended June 30, 2013, compared to none for the six months ended June 30, 2012 due to changes in production estimates and lease operating costs indicating potential impairment of our Williston and Appalachian Basin proved properties, and the resulting provision for reduction to the carrying value of these properties to their estimated fair values.

Oilfield services expenses. Oilfield services expenses increased by $4.7 million, or 113.8% for the six months ended June 30, 2013 to $8.8 million from $4.1 million for the six months ended June 30, 2012 due to increased personnel related to the utilization of additional rigs.

Depletion, depreciation, amortization, and accretion. Our DD&A increased $24.7 million, or 58.4%, to $67.0 million for the six months ended June 30, 2013, from $42.3 million for the six months ended June 30, 2012 due to increased production in the 2013 period described above. Our DD&A per Boe increased by $7.60, or 36.4%, to $28.47 per Boe for the six months ended June 30, 2013, compared to $20.87 per Boe for the six months ended June 30, 2012. The increase in DD&A expense per Boe was primarily attributable to aforementioned production increases in the Company’s Appalachian and Williston Basin areas.

General and administrative. Our G&A increased $10.3 million, or 32.5%, to $41.9 million ($17.79 per Boe) for the six months ended June 30, 2013, from $31.6 million ($15.60 per Boe) for the six months ended June 30, 2012. G&A increased overall during the 2013 period due to increased organizational costs related to the Company’s growth in the six months ended June 30, 2013

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compared to the six months ended June 30, 2012. Non-cash stock compensation totaled approximately $8.7 million ($3.69 per Boe) and $12.5 million ($6.16 per Boe) for the six months ended June 30, 2013 and 2012, respectively. This represents a decrease of approximately $4.1 million. The primary reason for the decrease was that 4.8 million stock options with an associated expense of $6.6 million were granted during the six months ended June 30, 2012, compared to 4.3 million stock options with an associated expense of $4.5 million were granted during the six months ended June 30, 2013. This represents a decrease of $2.1 million. In addition, 632,000 shares with associated expense of $2.6 million expired or forfeited during the six months ended June 30, 2012 while 413,000 shares with associated expense of $1.5 million forfeited during the six months ended June 30, 2012. The six months ended June 30, 2013 also included transaction costs of $1.8 million ($0.75 per Boe) related to divestitures activity. The six months ended June 30, 2012 included acquisition related costs of approximately $2.6 million ($1.28 per Boe) which were for legal, consulting and other costs related to the acquisitions of properties in May 2012.

Interest expense, net. Our interest expense, net of interest income, increased approximately $12.7 million, or 51.2% to $37.4 million for the six months ended June 30, 2013, from $24.7 million for the six months ended June 30, 2012. This increase was the result of our higher average debt level during 2013, the write off of $800,000 in deferred financing charges as a result of the Seventeenth Amendment to our MHR Senior Revolving Credit Facility, and fees and non-cash amortization of deferred financing costs. Interest on projects lasting six months or greater is capitalized. During the six months ended June 30, 2013, we capitalized $1.4 million and we did not capitalize interest in the six months ended June 30, 2012.

Commodity and financial derivative activities. For the six month period ended June 30, 2013, we had a net loss on commodity and financial derivatives of $1.1 million compared to a net gain of $19.2 million for the six month period ended June 30, 2012.

The following table summarizes the realized and unrealized gains and losses on change in fair value of our derivative contracts as of the dates indicated:



	Six Months Ended June 30,
	2013			2012
	(in thousands)
Realized gain (loss)	$	(305	)	$	5,738
Unrealized gain (loss)	(786		)	13,469
Net gain (loss)	$	(1,091	)	$	19,207

Income tax benefit. The Company recorded an income tax benefit of $48.4 million and $9.2 million for the six months ended June 30, 2013 and 2012 respectively.

Net income attributable to non-controlling interest. Net income attributable to non-controlling interest was $888,859 for the six months ended June 30, 2013 versus net loss of $22,000 for same period in 2012. This represents 12.5% of the gain or loss incurred by our subsidiary, PRC Williston, LLC and 2.5% of the gain or loss incurred by our subsidiary, Eureka Hunter Holdings.

Loss from Continuing Operations. We had a loss from continuing operations of $66.3 million for the period ended June 30, 2013 versus a loss of $34.8 million for the 2012 period, an increased loss of $31.6 million, or 90.8%. We had increased revenues of $71.4 million, however these increases were offset by increases in expenses of $109.8 million, including increased exploration and abandonment costs of $16.5 million, proved property impairments of $16.0 million, interest expense of $12.7 million, general and administrative expense of $10.3 million, and net decrease in gain on derivatives of $20.3 million in the six month period ended June 30, 2013 compared to the six month period ended June 30, 2012.

Discontinued Operations. On April 24, 2013, we closed on the sale of Eagle Ford Hunter, previously a wholly-owned subsidiary. On June 30, 2013, income from the operations and the gain related to the sale of Eagle Ford Hunter was determined to be discontinued operations. We reclassified operating income (net of income taxes) of the divested subsidiary of $14.2 million and $7.2 million, respectively, for the six months ended June 30, 2013 and 2012. We recorded a gain on sale of discontinued operations of $172.5 million in the six months ended June 30, 2013.

On February 17, 2012, we closed on the sale of Hunter Disposal, previously a wholly owned subsidiary. We have reclassified $354,000 of net operating income (net of income tax) of the divested subsidiary to discontinued operations for the six month period ended June 30, 2012. We have also reclassified the gain on sale of $2.2 million to discontinued operations for the six months ended June 30, 2012.

Dividends on Preferred Stock. Total dividends on our Preferred Stock were approximately $27.6 million for the six months ended June 30, 2013, and $12.8 million for the six months ended June 30, 2012.

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The Series C Preferred Stock had a stated value of $100 million at both June 30, 2013 and December 31, 2012 and carries a cumulative dividend rate of 10.25% per annum. The Series D Preferred Stock had a stated value of $221.2 million and $210.4 million at June 30, 2013 and December 31, 2012, respectively and carries a cumulative dividend rate of 8.0% per annum. The Series E Preferred Stock had a stated value of $95.1 million and $94.4 million at June 30, 2013 and December 31, 2012, respectively and carries a cumulative dividend rate of 8.0% per annum. The Series A Preferred Units of Eureka Hunter Holdings had a liquidation preference of $202.4 million and $167.4 million at June 30, 2013 and December 31, 2012, respectively, and carries a cumulative dividend rate of 8% per annum.

Net Income attributable to Common Shareholders. Net income attributable to common shareholders was $93.6 million in the 2013 period versus a loss of $37.9 million in the 2012 period. Our net income per common share, basic and diluted was $0.55 per share for the six months ended June 30, 2013, compared to net loss of $0.27 per share for the 2012 period. Our weighted average shares outstanding increased by approximately 27,364,524 shares, or 19.2%, from 142,293,282 shares in the 2012 period to 169,657,806 shares during the 2013 period. Our net loss per share from continuing operations was $0.55 per share for the six months ended June 30, 2013, versus a net loss of $0.37 per share for the 2012 period. We had income from discontinued operations of $186.7 million ($1.10 per share) in the 2013 period from the sale of Eagle Ford Hunter. In the 2012 period, we had income from discontinued operations of $1.5 million ($0.02 per share) from Hunter Disposal.

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Years ended December 31, 2012, 2011 and 2010

The following table sets forth summary information regarding oil, natural gas and NGLs 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 prospectus 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	81,907	40,507	22,151
	Canada	38,974	9,864	—
Gas	US	46,142	30,295	4,823
	Canada	552	834	—
NGLs	US	5,678	4,433	—
	Canada	30	33	—
	Total oil and gas sales	173,283	85,966	26,974
Production
Oil (mbbls)	US	998	464	307
	Canada	456	105	—
Gas (mmcfs)	US	14,445	6,589	952
	Canada	212	201	—
NGLs(mboe)	US	158	85	—
	Canada	1	1	—
MBOE		4,056	1,787	466
BOE/DAY		11,082	4,896	1,277

Average prices
Oil (per bbl)	US	82.07	87.30	72.15
	Canada	85.33	93.92	—
Gas (per mcf)	US	3.19	4.60	5.07
	Canada	2.59	4.15	—
NGL (per boe)	US	35.94	52.15	—
	Canada	30.00	33.00	—
	Total average price (per boe)	42.72	48.11	57.88

Costs and expenses (per boe)
Lease operating		11.26	14.25	22.91
Severance tax and marketing		2.66	3.63	5.04
Exploration and abandonment		28.90	1.48	2.02
Impairment of properties		1.01	12.19	0.66
General and administrative ⁽¹⁾		15.87	35.20	53.16
Depletion, depreciation and accretion		24.63	20.68	17.57

Midstream and Oil Field Services segments (in thousands)
Oil Field Services segment revenue		12,952	9,426	3,390
Oil Field Services segment expense		11,805	9,320	3,926
Midstream segment revenue		15,942	2,491	414
Midstream segment expense		17,669	3,012	330


(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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(2)	Midstream and oilfield service segment revenue and expense includes all revenue and expense for the segment, as further detailed in "Note 16 - Other Information."

Years ended December 31, 2012 and 2011

Oil and gas production. Production increased by 127.0%, or 2,269 mboe, to 4,056 mboe for the year ended December 31, 2012 compared to 1,787 mboe for the year ended December 31, 2011. Our average daily production was 11,082 boepd during 2012, representing an overall increase of 126.3%, or 6,186 boepd compared to 4,896 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 39.8% oil and NGLs and 60.2% natural gas compared to 36.7% oil and NGLs and 63.3% natural gas for 2011. The change was attributable to increased focus on the development of oil production in the Williston Basin region.

U.S. Upstream segment. In the U.S. Upstream Production operating segment, production increased 116.3%, from 1,647 mboe to 3,564 mboe for the year ended December 31, 2012 compared to the year ended December 31, 2011. Production for 2012 on a boe basis was 32.4% oil and NGLs and 67.6% natural gas compared to 33.3% oil and NGLs and 66.7% natural gas for 2011. Our average daily production increased from 4,513 boepd, to 9,736 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 from continued operations increased 101.6%, or $87.3 million, for the year ended December 31, 2012 to $173.3 million from $86.0 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 $48.11 per boe to $42.72 per boe, or 11.2% primarily due to lower natural gas prices. The $87.3 million increase in revenues comprised an increase of approximately $109.2 million attributable to increased production volumes of 2,269 mboe, partially offset by a decrease of $21.9 million due to a decrease in price of $5.39 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 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 $20.2 million, or 79.5%, for the year ended December 31, 2012 to $45.7 million ($11.26 per boe) from $25.5 million ($14.25 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 $32.3 million, reduced by lower cost per boe produced, which offset the effect of the increase in volume by $12.1 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 $4.3 million, or 66.4%, for the year ended December 31, 2012 to $10.8 million from $6.5 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.

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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 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 $62.9 million, or 170.3%, to $99.9 million for the year ended December 31, 2012 from $37.0 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 $3.95, or 19.1%, to $24.63 per boe for the year ended December 31, 2012, compared to $20.68 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 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 ($15.87 per boe) for the year ended December 31, 2012 from $62.9 million ($35.20 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 ($3.87 per boe) for the year ended December 31, 2012 and $25.1 million ($14.02 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 ($1.16 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 ($4.98 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 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.

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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 $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 $32.2 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., and the tax effect of discontinued operations during the period. The Company recorded a deferred tax benefit at the applicable statutory rates of $3.0 million during the year ended December 31, 2011, as a result of the operating loss incurred by Williston Hunter Canada, Inc. and Williston Hunter, Inc., and the tax effect of discontinued operations 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 $156.4 million and $83.6 million in 2012 and 2011, respectively. Our 2012 revenues increased $105.4 million to $198.9 million compared to $93.4 million in 2011. However, this increase was more than offset by increases in operating expenses. Our 2012 operating loss increased $91.3 million, to $161.3 million, compared to $69.9 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 $62.9 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.

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 income taxes) 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.

On April 24, 2013, we closed on the sale of all of our ownership interest in a wholly-owned subsidiary, Eagle Ford Hunter, to an affiliate of Penn Virginia. We have reclassified $17.1 million and $4.3 million of net operating income of the divesting subsidiary to discontinued operations for the year ended December 31, 2012 and 2011, respectively.

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 approximately 155.7 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 $1.20 per share for the year ended December 31, 2012, compared to a loss from continuing operations of $0.86 per share for the year ended December 31, 2011.

Years ended December 31, 2011 and 2010

Oil and gas production. Production from continued operations increased by 283.5%, or 1,321 mboe, to 1,787 mboe for the year ended December 31, 2011 from 466 mboe for the year ended December 31, 2010. Production for 2011, on a boe basis, was 36.7% oil and NGLs and 63.3% natural gas compared to 65.9% oil and NGLs and 34.0% 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 4,896 boepd during 2011 compared to 1,277 boepd for 2010 representing an overall

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increase of 283.4%, or 3,619 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 253.7%, or 1,182 mboe, for the year ended December 31, 2011 from 466 mboe for the year ended December 31, 2010. Production for 2011 on a boe basis was 33.3% oil and NGLs and 66.7% natural gas compared to 65.9% oil and NGLs and 34.1% natural gas for 2010. Our average daily production increased by 253.7%, or 3,237boepd, to 4,513 boepd during 2011 compared to 1,276 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.

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 218.7%, or $59.0 million, for the year ended December 31, 2011 to $86.0 million from $27.0 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 $57.88 per boe to $48.11 per boe, or 9.8%. Of the $59.0 million increase in revenues, a decrease of approximately $17.5 million net was attributable to an increase in oil prices net with a decrease in gas prices, and $76.5 million was attributable to the increase in production volumes of 1,321 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 $14.8 million, or 138.4%, for the year ended December 31, 2011 to $25.5 million ($14.25 per boe) from $10.7 million ($22.91 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 $30.3 million, reduced by lower cost per boe produced, which offset the volume effect by $15.5 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 $4.1 million, or 176.2%, for the year ended December 31, 2010 to $6.5 million from $2.3 million for the year ended December 31, 2010. The increase in production taxes and marketing was due to the increased 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 South Texas 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 $28.8 million, or 351.2% to $37.0 million for the year ended December 31, 2011 from $8.2 million for the year ended December 31, 2010 due to increased production in 2011. Our DD&A per boe increased by $3.11, or 17.7%, to $20.68 per boe for the year ended December 31,

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2011, compared to $17.57 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 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 153.9%, to $62.9 million ($35.20 per boe) for the year ended December 31, 2011 from $24.8 million ($53.16 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 ($14.05 per boe) for the year ended December 31, 2011 and $6.4 million ($13.73 per boe) for the year ended December 31, 2010. Also included in G&A for 2011 are acquisition-related costs of $8.9 million ($4.98 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 ($4.72 per boe) of acquisition-related expenses related to the acquisition of Triad Energy. These costs were 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 $3.6 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 $3.0 million during the year ended December 31, 2011, as a result of the operating loss incurred by Williston Hunter Canada, Inc. and Williston Hunter, Inc., and tax effect of discontinued operations 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 $83.6 million in 2011 versus a loss of $22.8 million in 2010, an increase of $63.1 million in loss, or 278.0%. 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.

On April 24, 2013, we closed on the sale of all of our ownership interest in a wholly-owned subsidiary, Eagle Ford Hunter, to an affiliate of Penn Virginia. We have reclassified $4.3 million and $131,000 of net operating income of the divested subsidiary to discontinued operations for the year ended December 31, 2011 and 2010, respectively.

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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 $0.86 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.

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 utilize our credit agreements to fund a portion of our operating and capital needs. The Company had no outstanding debt under the MHR Senior Revolving Credit Facility at June 30, 2013, with available borrowing capacity at that date of $264.8 million. On April 24, 2013, the Company sold its 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 17 - Subsequent Events" for additional information. Our liquidity at June 30, 2013 was $297.5 million, comprised of $264.8 million available under the MHR Senior Revolving Credit Facility and $32.7 million in available cash. As of September 30, 2013, we had approximately $167.8 million available for additional borrowing under our MHR Senior Revolving Credit Facility.

As of June 30, 2013, we were in compliance with all of our covenants, as amended or waived, contained in our credit agreements as described in "Note 8 - Long-Term Debt."

and (v) anticipated sales of non-core assets will 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 remainder of 2013.

For the six months ended June 30, 2013, our primary sources of cash were cash flows from operating activities and borrowings under our MHR Senior Revolving Credit Facility.

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



	Six Months Ended June 30,
	2013			2012
	(In thousands)
Cash flows provided by operating activities	$	73,868		$	49,165
Cash flows provided by (used in) investing activities	104,198			(658,720		)
Cash flows provided by (used in) financing activities	(202,590		)	619,499
Effect of foreign currency exchange rates	(357		)	(33		)
Net increase (decrease) in cash and cash equivalents	$	(24,881	)	$	9,911

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 of $50.4 million from the sale of 10 million shares of Penn Virginia common stock on September 10, 2013, 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 September 30, 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. As of September 30, 2013, we had $167.8 million available to borrow under our MHR Senior Revolving Credit Facility. At September 30, 2013, 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

Our cash provided by operating activities was $73.9 million for the six months ended June 30, 2013 compared to $49.2 million for the six months ended June 30, 2012, an increase of $24.7 million or 50.2%. This increase was mainly due to increased oil and gas sales from the success of our drilling program and our acquisitions during 2012.

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

Our cash provided by investing activities for the six months ended June 30, 2013 was $104.2 million, principally from the cash proceeds from the sale of Eagle Ford Hunter of $379.8 million, partially offset by capital expenditures of $277.5 million (See "Note 6 - Divestitures and Discontinued Operations" to our consolidated financial statements).

Our cash used in investing activities for the six months ended June 30, 2012 was $658.7 million, principally from acquisition and drilling activities. We used $312.0 million in cash acquiring Bakken Shale oil and gas properties from Baytex, $50.9 million acquiring Williston Basin oil and gas properties from Eagle Operating, $24.8 million in cash for our Utica Shale property acquisition, and $219.5 million in cash for drilling and other capital expenditures under our 2012 capital expenditures budget. Also during the six months ended June 30, 2012, we received $783,000 in cash proceeds, net of working capital adjustments, from the sale of Hunter Disposal.

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

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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

Our cash used in financing activities for the six months ended June 30, 2013 was $202.6 million mainly from debt pay-down under the MHR Senior Revolving Credit Facility and other debt agreements of $327.1 million, partially offset by borrowings of $106.0 million. The Company also raised $10.2 million in proceeds from the issuance of shares of our Series D Preferred Stock for cumulative net proceeds of approximately $9.6 million, and the issuance of our Series E Preferred Stock for cumulative net proceeds of $590,000. See "Note 10 - Shareholder's Equity" for details. In the 2013 period, we paid preferred dividends of $10.4 million and incurred $701,000 in deferred finance costs on loans.

Our cash flows from financing activities for the six months ended June 30, 2012 were $619.5 million. We issued $444.0 million of Senior Notes. We used the proceeds from the offering to repay principal of $362.0 million of our MHR Senior Revolving Credit Facility and retired the term note of $100.0 million. We received $50.9 million from the issuance of our Series D Preferred Stock and $127.4 million from the issuance of Series A Preferred Units of Eureka Hunter Holdings, of which $60 million was distributed to Magnum Hunter. We also received $1.2 million in proceeds from exercise of stock options and warrants and incurred $18.2 million of deferred finance cost on loans and paid $9.5 million in dividends on our preferred stock.

As a result of our failure to file our 2012 Form 10-K and First Quarter 2013 Form 10-Q within the time frames required by the SEC, 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. Until we have timely filed all our required SEC reports for a period of twelve months (which period we expect to expire in August 2014, assuming we remain timely in the filing of our SEC reports for that period), 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 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 delinquent SEC filings. We may use Form S-1 to register a sale of our 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.

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 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.

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As of September 30, 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 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) the net proceeds Magnum Hunter received from the now completed sale of all of the Penn Virginia common stock it received as partial consideration for its sale of the Eagle Ford Properties; and (v) proceeds from anticipated non-core asset sales will provide sufficient funds to conduct our operations, meet our contractual obligations, including our debt covenant requirements, as amended, and complete our budgeted capital expenditure program for the remainder of 2013.

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."

2013 Capital Expenditures Budget

The following table summarizes our estimated capital expenditures (excluding acquisitions) for 2013. We intend to fund 2013 capital expenditures, excluding any acquisitions, partially out of internally-generated cash flows and, as necessary, borrowings under our MHR Senior Revolving Credit Facility.



	Year Ending December 31, 2013
	(in millions)
Upstream Operations
Appalachian Basin drilling	$	150
Williston Basin drilling	$	150
Midstream and Marketing Operations
Eureka Hunter Holdings ⁽¹⁾	100
Total estimated capital expenditures	$	400

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________________________________

⁽¹⁾Expected to be financed through equity and debt facilities that are non-recourse to Magnum Hunter, and Company capital contributions.

Our capital expenditure 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 and our ability to obtain permits for the drilling locations.

Credit Facilities

MHR Senior Revolving Credit Facility

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 September 30, 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.

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 1.005% to 2.25% for ABR loans and from 2.00% to 3.25% for adjusted LIBOR loans.

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 (i) 2.00 to 1.00 for the fiscal quarters ended June 30, 2013 and September 30, 2013, (ii) 2.25 to 1.00 for the fiscal quarter ending December 31, 2013 and (iii) 2.50 to 1.00 for the fiscal quarter ending March 31, 2014 and each fiscal quarter ending thereafter; (3) commencing with the fiscal quarter ending June 30, 2014, a ratio of total debt to EBITDAX of not more than (i) 4.50 to 1.0 for the fiscal quarters ended June 30, 2014 and September 30, 2014 and(ii) 4.25 to 1.00 for the fiscal quarter ending December 31, 2014 and for each fiscal quarter ending thereafter, and (4) commencing with the fiscal quarter ended June 30, 2013 through and including the fiscal quarter ending March 31, 2014, a ratio of senior debt to EBITDAX not more than 2.00 to 1.00.

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.

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Eureka Pipeline Credit Facilities

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).

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

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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 September 30, 2013, we had $600 million aggregate principal amount of Senior Notes outstanding.

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;

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•	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, 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 our 2012 Form 10-K and First Quarter 2013 Form 10-Q, 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.

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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 our 2012 Form 10-K, First Quarter 2013 Form 10-Q and certain pro forma financial information regarding our sale of Eagle Ford Hunter, Inc. to Penn Virginia (as part of the Form 8-K we filed with the SEC on April 30, 2013 reporting the sale) not having been filed within 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.” 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 September 30, 2013, Eureka Holdings had sold preferred units to Ridgeline for an aggregate purchase price of $179.8 million.


•	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.

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contributions ($20.0 million of which had been paid by September 30, 2013) 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.

Related Party Transactions

Three and Six Months Ended June 30, 2013 and 2012

The following table sets forth the related-party transaction activities for the three and six months ended June 30, 2013 and 2012, respectively:



		Three Months Ended				Six Months Ended
		June 30,				June 30,
		2013		2012		2013		2012
GreenHunter
	Salt water disposal (1)	$	589,985	$	—	$	1,445,510	$	—
	Equipment rental (1)	98,306		316,000		72,783		631,000
	Professional services (1)	—		—		—		—
	Interest Income from Note Receivable (2)	53,931		56,611		107,708		81,889
	Dividends received from Series C shares	36,667		55,000		91,667		81,278
	Loss on investments (2)	208,480		65,280		677,007		121,087
Pilatus Hunter, LLC
	Airplane rental expenses (3)	20,100		64,125		67,350		81,225
Executive of the Company
	Corporate apartment rental (4)	—		4,000		—		18,000

⁽¹⁾ GreenHunter is an entity of which Gary C. Evans, our Chairman and CEO, is the Chairman, a major shareholder and former CEO; and of which Ronald Ormand, our Executive Vice President - Finance and Head of Capital Markets, and our former Chief Financial Officer and a former director, is a former director; and of which David Krueger, our former Chief Accounting Officer and Senior Vice President, is the former Chief Financial Officer. Eagle Ford Hunter, Triad Hunter and Viking International Resources, Inc. ("Virco"), wholly-owned subsidiaries of the Company, receive services related to brine water and rental equipment from GreenHunter and affiliated companies White Top Oilfield Construction, LLC and Black Water Services, LLC. 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. Prepaid expenses from GreenHunter were $55,800 and $0 at June 30, 2013 and December 31, 2012, respectively. The Company had net accounts payable of $546,038 and $0 at June 30, 2013 and December 31, 2012, respectively.

⁽²⁾ On February 17, 2012, the Company sold its wholly-owned subsidiary, Hunter Disposal, to GreenHunter Water. The Company recognized an embedded derivative asset resulting from the conversion option on the convertible promissory note it received as partial consideration for the sale. The fair market value of the derivative was $53,000, and $264,000 at June 30, 2013 and December 31, 2012, respectively. See "Note - 4 Fair Value of Financial Instruments." The Company has recorded interest income as a result of the note receivable from GreenHunter. Also as a result of this transaction, the Company has an equity method investment in GreenHunter that is included in derivatives and other long term assets and an available for sale investment in GreenHunter included in investments.

⁽³⁾ We rented an airplane for business use for certain members of Company management at various times from Pilatus Hunter, LLC, an entity 100% owned by Mr. Evans. Airplane rental expenses are recorded in general and administrative expense.

⁽⁴⁾ During the three and six months ended June 30, 2012, the Company paid rent pertaining to a lease for a corporate apartment from an executive of the Company which was being used by other Company employees. The lease was terminated in May of 2012.

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In connection with the sale of Hunter Disposal, Triad Hunter entered into agreements with Hunter Disposal and GreenHunter Water for wastewater hauling and disposal capacity in Kentucky, Ohio, and West Virginia and a five-year tank rental agreement with GreenHunter Water. See "Note 6 - Divestitures and Discontinued Operations" for additional information.

Years Ended December 31, 2012, 2011, and 2010

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, who was then 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.

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

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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.

Contractual Commitments

The following table summarizes our contractual commitments as of June 30, 2013 (in thousands):



Contractual Obligations	Total		2013		2014 - 2015		2016 - 2017		After 2017
Long-term debt (1)	$	672,462	$	2,172	$	16,514	$	3,776	$	650,000
Interest on long-term debt (2)	442,556		32,900		130,717		129,759		149,180
Dividends on Preferred Stock (3)	74,009		16,948		36,816		20,245		—
Gas transportation and compression contracts	31,006		2,706		8,454		6,177		13,669
Asset retirement obligations (4)	33,359		2,842		1,945		7,654		20,918
Commodity derivative liabilities (5)	2,429		1,127		1,302		—		—
Operating lease obligations	1,161		422		656		83		—
Total	$	1,256,982	$	59,117	$	196,404	$	167,694	$	833,767


⁽¹⁾	See "Note 8 - 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 June 30, 2013 on the debt facilities in place as of June 30, 2013. This results in a weighted average interest rate of 9.78%.


⁽³⁾	See "Note 10 - Shareholders' Equity" to our consolidated financial statements for further details regarding our obligations to preferred shareholders.


⁽⁴⁾	See "Note 7 - Asset Retirement Obligations" to our consolidated financial statements for a discussion of our asset retirement obligations.


⁽⁵⁾	See “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.

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 June 30, 2013, 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.

Recently Issued Accounting Standards

Accounting standards-setting organizations frequently issue new or revised accounting rules. We regularly review all new pronouncements to determine their impact, if any, on our financial statements.

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loss carryforward, a similar tax loss, or a tax credit carryforward is not available at the reporting date under the tax law of the applicable jurisdiction or the tax law of the jurisdiction does not require, and the entity does not intend to use, the deferred tax asset for such purpose, the unrecognized tax benefit should be presented in the financial statements as a liability and should not be combined with deferred tax assets. This ASU is effective prospectively for fiscal years, and interim periods within those years, beginning after December 15, 2013. Retrospective application is permitted. We are currently evaluating the impact of this ASU on our consolidated financial statements and financial statement disclosures.

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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 "Financial Statements and Supplementary Data" and "Liquidity and Capital Resources" included in "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 perform a write down of the carrying value of our oil and gas properties.

We may enter into financial swaps and collars to reduce the risk of commodity price fluctuations. We do not designate such instruments as cash flow hedges. Accordingly, we record open commodity derivative positions on our consolidated balance sheets at fair value and recognize changes in such fair values as income (expense) on our consolidated statements of operations as they occur.

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 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" for information regarding derivative transactions.

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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" 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 "Financial Statements and Supplementary Data" for information regarding derivative transactions.

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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 September 30, 2013, we had approximately 81,000 net leasehold acres in the Marcellus Shale and approximately 91,000 net leasehold acres prospective for the Utica Shale (a portion of which acreage overlaps our Marcellus Shale acreage). We believe approximately 32,000 of these Utica Shale net acres are located in the wet gas window of the play. As of September 30, 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.

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.

Marcellus Shale Properties

Our Marcellus Shale acreage is located principally in Tyler, Pleasants, Doddridge, Wetzel and Lewis Counties, West Virginia and in Washington and Monroe Counties, Ohio. As of September 30, 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 September 30, 2013, approximately 76% of our mineral leases in the Marcellus Shale area were held by production. As of September 30, 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 beginning 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

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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 September, 2013, Stone Energy had drilled and completed eleven producing Marcellus Shale wells pursuant to this joint development program.

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.

The following table contains certain information regarding our completed Marcellus Shale horizontal wells as of September 30, 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	5,350	13	3,360	3,114	2,789
Lance Mills Unit 2 #2H	Wetzel, WV	Marcellus	50	%	6/6/2011	5,600	11	3,875	2,987	2,620
Mills Wetzel #8H	Wetzel, WV	Marcellus	50	%	12/19/2012	3,500	11	3,792	3,015	N/A
Mills Wetzel #10H	Wetzel, WV	Marcellus	50	%	12/22/2012	3,000	10	3,954	2,528	2,588
Mills Wetzel #11H	Wetzel, WV	Marcellus	50	%	12/24/2012	3,600	12	3,397	1,806	1,630
Mills Wetzel #9H	Wetzel, WV	Marcellus	50	%	2/22/2013	4,900	20	3,257	2,945	2,892
Mills Wetzel #12H	Wetzel, WV	Marcellus	50	%	2/27/2013	3,400	14	4,661	2,701	2,456
Mills Wetzel #13H	Wetzel, WV	Marcellus	50	%	3/9/2013	4,000	16	3,140	4,009	3,286
Mills Wetzel #15H	Wetzel, WV	Marcellus	50	%	3/19/2013	4,600	18	3,951	2,412	2,891
Mills Wetzel #4H	Wetzel, WV	Marcellus	50	%	4/6/2013	4,150	17	3,044	3,144	2,882
Mills Wetzel #5H	Wetzel, WV	Marcellus	50	%	4/13/2013	4,200	17	3,225	3,700	3,217
Mills Wetzel #6H	Wetzel, WV	Marcellus	50	%	4/20/2013	4,050	17	3,787	6,412	4,360
Mills Wetzel #7H	Wetzel, WV	Marcellus	50	%	4/27/2013	4,600	18	3,560	3,380	3,612

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 September 30, 2013, we owned leasehold rights to a total of approximately 91,000 net acres that are presently prospective for the Utica Shale. Approximately 59,000 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).

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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.

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.

Agreement to Purchase Utica Acreage. On August 12, 2013, Triad Hunter, a Delaware limited liability company and wholly-owned subsidiary of the Company, entered into an Asset Purchase Agreement, referred to as the Purchase Agreement, with MNW Energy, LLC, an Ohio limited liability company, referred to as MNW. MNW represents an informal association of various land owners, lessees of mineral acreage and sublessees of mineral acreage who own or have rights in mineral acreage located in Monroe, Noble and/or Washington Counties, Ohio, referred to as the Counties. Pursuant to the Purchase Agreement, Triad Hunter has agreed to acquire from MNW up to 32,000 net mineral acres, including currently leased and subleased acreage, located in the Counties, referred to as the Subject Acreage, over the next 10 months or possibly longer, subject to certain conditions - for more information, see "Business-Agreement to Purchase Utica Acreage."

Our Utica Drilling Activity. During 2013, Triad Hunter plans to drill a minimum of three wells in Washington County and Monroe County, Ohio to test the Utica Shale formation. In connection with this planned test development, Triad Hunter has drilled 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 ten horizontal wells. Triad Hunter spud its first Utica Shale test well from the Farley Pad in April 2013. The Company has deemed this well to be a “tight-hole” for competitive reasons and therefore, no disclosure regarding any specifics concerning the completion of this well is being made at this time.

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The Company also commenced construction of a 18-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 two 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 September 30, 2013, our southern Appalachian Basin properties included approximately 286,000 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.

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. As of September 30, 2013, we had drilled and completed two gross (0.9 net) Weir wells. One is now producing to sales, and the second is flowing back.

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 September 30, 2013, our Williston Basin properties included (a) approximately 151,000 net leasehold acres consisting of 100,000 net acres in the Bakken/Three Forks Sanish in North Dakota and 51,000 net acres in the Bakken/Three Forks Sanish in Saskatchewan, and (b) approximately 31,000 net leasehold acres comprising our North Dakota legacy properties described below.

As of September 30, 2013, we had drilled and completed approximately 271 gross (73.1 net) wells on our Bakken/Three Forks Sanish properties, including 229 gross (56.3 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 136 gross (31.2 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 September 30, 2013. As of September 30, 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 September 30, 2013, we operated 182 gross (173 net) Madison formation wells on our North Dakota legacy properties.

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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.

Williston Hunter U.S. Properties

Bakken/Three Forks Sanish Properties in North Dakota. As of September 30, 2013, our Williston Hunter U.S. properties included approximately 100,122 net acres in the Bakken/Three Forks/Sanish formations in the Williston Basin in North Dakota. As of September 30, 2013, our Bakken/Three Forks Sanish properties in North Dakota included approximately 243 gross (54.7 net) productive wells, and we were operating five of these gross wells. As of September 30, 2013, nine horizontal wells (3.6 net) were awaiting completion, one well (0.9 net) were being drilled, seventeen gross (4.8 net) were being completed, and two 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 September 30, 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 353 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 860 boepd.

Oasis Disposition. On September 2, 2013, Williston Hunter, Inc., a wholly owned subsidiary of the Company, entered into a purchase and sale agreement with Oasis Petroleum of North America LLC, or Oasis, to sell Wiliston Hunter's non-operated working interest in certain oil and gas properties located in Burke County, North Dakota, consisting of a non-operated working interest in approximately 51,495 gross (14,500 net) leasehold acres for consideration of $32.5 million in cash, subject to customary adjustments. The transaction closed on September 27, 2013, and is effective as of July 1, 2013.

North Dakota Legacy Properties. The Company also holds operating working interests in approximately 31,000 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 182 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.

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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 September 30, 2013, our Williston Hunter Canada properties included approximately 51,000 net acres in the Tableland Field in the Williston Basin in Saskatchewan and approximately 28,000 net acres in Alberta. As of September 30, 2013, the Williston Hunter Canada properties included approximately 88 gross (79.3 net) productive wells, 98% of which we operate. At September 30, 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 September 30, 2013, Williston Hunter Canada had approximately 51,000 net acres of largely contiguous land that is prospective for Bakken/Three Forks Sanish oil in the Tableland Field. As of September 30, 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 September 30, 2013, our eight most recently completed wells in the Tableland Field generated approximately 358 boepd average IP-24 hour rates.

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 September 30, 2013, Williston Hunter Canada had approximately 28,000 net acres in Alberta. At September 30, 2013, Williston Hunter Canada had four producing oil wells (2.8 net) and no wells drilling in Alberta.

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The following table contains certain information regarding our Bakken/Three Forks Sanish horizontal wells completed during the period from January 1, 2013 to September 30, 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	87.5	%	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	%	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	298
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	923	765	551
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	361	348	314
Border Farms 3130-5TFH (31-30-164-99)	Divide	Bakken	34.1	%	4/19/2013	1 Mile	26	626	472	383
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	281	246
Bakke 3229-6TFH (32-29-164-99)	Divide	Three Forks/Sanish	39.3	%	4/25/2013	1 Mile	25	330	209	177
Titan 3625 2TFH	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	298
Montclair 0112-2TFH (1-12-163-99)	Divide	Three Forks/Sanish	16.7	%	5/7/2013	2 Mile	40	683	381	334

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J Olson 22-15-162-98H 2DM	Divide	Three Forks/Sanish	36.3	%	5/14/2013	2 Mile	36	872	817	644
J Olson 27-34-162-98H 2XM	Divide	Three Forks/Sanish	35.7	%	5/19/2013	2 Mile	36	971	782	608
Murphy 29-32-160-99 1CN	Divide	Three Forks/Sanish	25.4	%	5/31/2013	2 Mile	32	643	396	281
Baja 2215-3H (15-22-163-99)	Divide	Bakken	30.4	%	6/1/2013	2 Mile	25	1,076	899	620
Baja 2215-1H (15-22-163-99)	Divide	Bakken	30.4	%	6/1/2013	2 Mile	25	913	779	567
Baja 2215-2H (15-22-163-99)	Divide	Three Forks/Sanish	30.4	%	6/1/2013	2 Mile	25	813	733	496
Bonneville 3625-2TFH (36-25-163-100)	Divide	Three Forks/Sanish	26.8	%	6/5/2013	2 Mile	26	374	336	278
Bonneville 3625-3TFH (36-25-163-100)	Divide	Bakken	26.8	%	6/6/2013	2 Mile	40	297	262	223
Ebreck 4-9-161-97H 1XN	Divide	Three Forks/Sanish	8.1	%	6/8/2013	2 Mile	32	496	439	345
Sandvol 22-15-162-98H 3PA	Divide	Three Forks/Sanish	36.3	%	6/30/2013	2 Mile	30	687	615	454
Marcella 36-25-162H 2XD	Divide	Three Forks/Sanish	22.4	%	7/1/2013	2 Mile	32	498	382	321
Sandvol 27-34-162-98H 3XQ	Divide	Three Forks/Sanish	35.7	%	7/4/2013	2 Mile	30	934	744	634
Marcella 1-12-161-98H2DM	Divide	Three Forks/Sanish	23.2	%	7/7/2013	2 Mile	32	797	580	491
Montclair 0112-6TFH	Divide	Bakken	11.3	%	7/7/2013	2 Mile	25	578	450	367
Pulvermacher 31-30-162-99 1PB	Divide	Three Forks/Sanish	33.4	%	7/29/2013	2 Mile	32	833	615	467
Titan 3625-6TFH	Divide	Three Forks/Sanish	11.3	%	8/1/2013	1 Mile	18	302	206	159
Titan 3625-5TFH	Divide	Three Forks/Sanish	11.3	%	8/4/2013	1 Mile	18	302	194	138
Montclair 0112-5TFH	Divide	Bakken	11.3	%	8/4/2013	2 Mile	25	354	315	215
Twin Butte 17-20-162-99H 1BP	Divide	Three Forks/Sanish	34.9	%	8/6/2013	2 Mile	32	906	520	411
Stingray 1819-1H (18-19-162-98)	Divide	Bakken	46.2	%	8/7/2013	2 Mile	25	554	378	—
Stingray 1819-2H (18-19-162-98)	Divide	Bakken	46.2	%	8/12/2013	2 Mile	25	439	385	—
Coronet 2314-1H (23-14-163-99)	Divide	Bakken	45.6	%	9/1/2013	2 Mile	25	874	826	—
Charger 0706-2TFH (6-7-162-98)	Divide	Bakken	47.5	%	9/6/2013	2 Mile	25	647	461	—
Strom 2536-2H (25-36-163-99)	Divide	Bakken	46.1	%	9/6/2013	2 Mile	25	1,559	1,290	—
Charger 0706-1H (6-7-162-98)	Divide	Bakken	47.5	%	9/8/2013	2 Mile	25	782	603	—

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.

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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 September 30, 2013, we continued to own (a) approximately 6,200 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 September 30, 2013, we were operating and producing from five gross (3.7 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 30% non-operating working interest) in the drilling and completion of our first Pearsall Shale well, which is operated by Marathon Oil Corporation.

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 September 30, 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 September 30, 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 September 30, 2013, we were flowing approximately 60,000 mcf of natural gas per day through the Eureka Hunter Gas Gathering System. Through put has been reduced temporarily while the Mobley Processing Plant is restored to service following a break in a NGL pipeline associated with the plant. See "Business-Midstream Operations-Mobley Gas Processing Operations."

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.

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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 September 30, 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 September 30, 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 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 September 30, 2013, we have committed to approximately 95% of the processing capacity of the 200 mmcfe per day Mobley Processing Plant. Through put has been reduced temporarily while the Mobley Processing Plant is restored to service following a break in a NGL pipeline associated with the plant. See "Business-Midstream Operations-Mobley Gas Processing Operations."

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 September 30, 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

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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 September 30, 2013, Alpha Hunter Drilling’s operating fleet consisted of five 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.

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.

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.

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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 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

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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.

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

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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 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 “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.

159

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.

160

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



Proved Reserves (mboe)	For the Year Ended December 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.

161

Mid-Year 2013 Reserves Estimates

For information about our mid-year 2013 reserves estimates, see "Business-Proved, Probable and Possible Reserves (3P) as of June 30, 2013."

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).



	Developed Acreage⁽¹⁾		Undeveloped Acreage⁽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 “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 September 30, 2013, following our Eagle Ford Properties Sale in April 2013 and taking into account our drilling activities during 2013:



	Developed Acreage⁽¹⁾		Undeveloped Acreage⁽²⁾		Total Acreage
	Gross	Net	Gross	Net	Gross	Net
Appalachian Basin⁽³⁾	301,053	260,788	260,687	222,995	561,740	483,783
Eagle Ford Shale	1,248	766	10,394	5,434	11,642	6,200
Williston Basin
Williston Hunter U.S.	182,698	78,854	104,571	52,224	287,269	131,078
Williston Hunter Canada	12,841	11,296	39,972	39,936	52,813	51,232
Other U.S.⁽⁴⁾	1,504	795	—	—	1,504	795
Other Canada ⁽⁵⁾	24,790	19,689	11,360	8,307	36,150	27,996
Total at September 30, 2013	524,134	372,188	426,984	328,896	951,118	701,084

_______________


(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 40,663 gross acres and 36,119 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 “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.

162

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
Year Ending December 31,	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:



	Producing Oil Wells		Producing Gas Wells		Total Producing Wells
	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 "Properties-Other Properties”.


(2)	Other Canada pertains to our Alberta properties.

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.

163



	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 September 30, 2013, we were in the process of drilling or completing two gross (1.5 net) wells on our Appalachian Basin properties, 18 gross (6.6 net) wells on our Williston Basin properties and one gross (0.3 net) wells on our Eagle Ford Shale properties.

164

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

_______________

165

(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 34 gross (21.5 net) producing wells as of September 30, 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 227 gross (51.8 net) producing wells as of September 30, 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 September 30, 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.

Non-GAAP Measures; Reconciliations

This prospectus contains certain financial measures that are non-GAAP measures. We have provided reconciliations within this prospectus 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 prospectus.

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.

166

The standardized measure of discounted future net cash flows relating to our total proved oil and gas reserves as of June 30, 2013 is as follows:



As of June 30, 2013

Future cash inflows	$	2,768,997
Future production costs		(1,199,407	)	)
Future development costs		(285,526	)	)
Future income tax expense		—
Future net cash flows		1,284,064
10% annual discount for estimated timing of cash flows		(617,695	)	)
Standardized measure of discounted future net cash flows related to proved reserves	$	666,369
Reconciliation of Non-GAAP Measure
PV-10	$	666,369
Less: Income taxes
Undiscounted future income taxes		—
10% discount factor		—
Future discounted income taxes		—
Standardized measure of discounted future net cash flows	$	666,369

The PV-10 value and the standardized measure shown in the table above are the same as the Company projects that any potential future net tax expense related to the projected future net cash flows above would be offset by currently existing net operating loss carry forwards and tax basis even after consideration of the tax gain from the sale of the Eagle Ford Properties. The tax gain on the sale is expected to be primarily offset in 2013 by the Company's expensing of intangible drilling costs and a projected tax loss from continuing operations. As a result, the majority of the net operating loss carry forwards available at December 31, 2012 will still be available to offset future net cash flows. Based on the lower projected future net cash flows, no tax expense, after utilization of the net operating loss carry forwards and tax basis, would be recognized.

167

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 of December 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

After giving effect to the Eagle Ford Properties Sale:



	As of December 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

168

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 June 30, 2013 and 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 June 30, 2013 and December 31, 2012.

Management's Report on Internal Control Over Financial Reporting

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 criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Management excluded from our year-end 2012 assessment the internal control over financial reporting of Virco, which was acquired on November 2, 2102, 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.

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, included elsewhere in this prospectus.

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 identified material weaknesses in the internal control over financial reporting as of December 31, 2012, relating to the following processes and has described the current status of the deficiency as of June 30, 2013:

Effective Control Environment to Meet the Company's Growth

The Company has not completed the process of establishing controls, and upgrading resources around internal audit, tax, financial reporting and certain accounting areas. Adequate controls were not completely redesigned and in place in order to achieve operating effectiveness.

The Company has not performed an adequate risk assessment process commensurate with the growth of the Company's corporate structure and financial reporting requirements. Specifically, the Company did not have appropriate processes in place 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 has not completed its assessment of redesigning the controls for its wholly-owned subsidiary, Magnum Hunter Production, Inc., specifically around segregation of duties and timeliness of reporting with respect to revenue, joint interest, partnership accounting, and division of interests.

These material weaknesses have also contributed to the material weaknesses described below.

169

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 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 on debt related to assets under construction that had not been placed in service. The recorded costs of pipeline assets were understated in prior quarters, while interest expense was overstated.

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 consolidated financial statements for such fiscal periods, and resulted in revised consolidated financial statements for the three-and nine-month periods ended September 30, 2012. Although controls were implemented in early 2013, the Company is unable to demonstrate remediation of this deficiency until the Company has performed tests of operating effectiveness of the controls.

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.

The Company has designed appropriate controls over review of properties for expirations and impairments of unproven acreage, but testing of controls to demonstrate effectiveness of the control has not occurred.

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, the Company's preferred stock embedded derivative liabilities, and the loss on derivatives and related disclosures in the consolidated financial statements for the three and six-month periods ended June 30, 2012. This issue also resulted in adjustments to the Company's 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 June 30, 2013 as the control has not yet been tested for 2013.

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 to hiring additional

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personnel with greater accounting knowledge and expertise. The Company has also engaged outside consultants and accounting firms for assistance, and is investing in updated information technology.

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 was initiated in the second quarter of 2012. Management believes that the appropriate and adequate staffing levels in accounting have been substantially achieved, although several positions are currently filled by contractors and consultants pending the hiring of permanent staff members. The Company has hired a new Chief Financial Officer, corporate level controllers, regional controllers, and managers of internal audit, tax, expenditure accounting, and financial reporting. Management will continue to supplement the Company's in-house internal audit and tax functions in 2013 with the use of an accounting consulting firm as needed. Additionally, management is developing 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

During 2013, management has continued to add resources and re-aligned positions within the financial reporting area and continued efforts to further improve processes. This improvement in processes includes new and revised controls, such as appropriate segregation of duties and enhanced review procedures, implemented during the quarter ended June 30, 2013.

Leasehold Property Costs

Management is implementing processes to ensure that there are appropriate and effective controls over leasehold property accounts. A new Manager of Expenditure Accounting is in place to provide the required managerial control and review over this area. Management is implementing controls over documentation retention and accuracy of records for leasehold property accounts.

In 2013, management will continue the process of transitioning manually tracked leases to an automated land system in order to improve the completeness, accuracy, timeliness, 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(s) status and the review of acreage analysis, and proper review of related transfers of leasehold property costs.

Management is taking appropriate measures to ensure that proved property costs and unproved leasehold costs are reviewed periodically for impairment. These measures include documenting land management's assessment of any impairment triggers, and if required performing property analysis in order to identify any indicators that unproved properties that may be impaired due to 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 has begun to develop additional review controls over setup and maintenance of division of interest records and retention of adequate support and documentation. Additional controls have been designed to establish ownership and accountability of accuracy of division of interest information and coordinated communication between the land departments and accounting.

Complex Accounting Issues

Management has added additional 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 engaged experienced outside consultants, including an accounting consulting firm, to assist with research and review of accounting treatment of transactions where 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.

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Tax

The Company now has in place a full-time tax manager, and a tax senior accountant who prepare detailed supporting schedules to track current and prior year net operating losses (NOLs) to make sure NOLs are properly reflected in the financial statements and tax returns. All prior year tax returns have been reviewed and reconciled to the supporting schedules. Prior year ownership changes were detailed, and Section 382 limitation procedures have been performed. In addition, the Company has engaged an accounting consulting firm to review and perform their independent test procedures to ensure NOLs are presented correctly in financial statements and tax returns. The firm is also providing advisory services on tax matters including accounts and disclosures affecting financial reporting and preparation of tax returns.

Although there have been several control improvements addressing the control weaknesses, 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 CAO reporting to the Audit Committee of the Board of Directors, management will continue to assess the design of the Company's internal control environment to improve the effectiveness of internal control over financial reporting.

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 served 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 served 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. On September 9, 2013, the Securities Cases pending in Texas, which had been consolidated , were dismissed after the plaintiffs voluntarily abandoned their claims. The complaints in the Securities Cases pending in New York 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. On June 18, 2013, Mark Respler filed another shareholder derivative suit in the District of Delaware on behalf of the Company against the Company's directors and senior officers. On June 27, 2013, Timothy Bassett filed another shareholder derivative suit in the Southern District of Texas on behalf of the Company against the Company's directors and senior officers. On September 16, 2013, the Southern District of Texas allowed Joseph Vittelone to substitute for Mr. Bassett as plaintiff in that action. 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. The individual defendants intend to vigorously defend the Derivative Cases. It is possible that additional shareholder derivative suits could be filed over these events.

The Company was also named as a defendant in a Section 220 books and records complaint filed by Anthony Scavo in the Delaware Court of Chancery, which we refer to as the Books and Records Action. The Books and Records Action seeks an order compelling the Company to produce documents relating to the allegations in the Securities Cases and Derivative Cases and to pay the costs and fees incurred by Mr. Scavo in bringing the Books and Records Action. The Company is preparing a response to the Books and Records Action.

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.

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The Company believes that these claims are covered by the terms of our directors' and officers' insurance policies, and that the coverage available under these insurance policies will be adequate to cover the costs of these claims, including professional fees and other defense costs. However, we cannot provide any assurances regarding the foregoing, and we refer you to the "Risk Factors" section of this prospectus, including the risk factor entitled "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."

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MANAGEMENT

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 compliance with the Sarbanes–Oxley Act of 2002 were factors taken into account by the Board in determining that Mr. Bailes’ tax, accounting and industry experience 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 connection with his nomination.

Rocky Duckworth, was elected as a director of the Company in October 2013. Mr. Duckworth brings more than 40 years of regulatory compliance, financial reporting (including internal controls over financial reporting), technical accounting and oil and gas accounting experience to the Magnum Hunter Board. Mr. Duckworth has served as a director of Northern Tier Energy GP LLC, the general partner of Northern Tier Energy LP since May 2013. Mr. Duckworth is a former partner of KPMG LLP (and its predecessor firms), retiring after more than 38 years of service to KPMG in 2010, including more than 29 years as a partner. Since his retirement from KPMG, Mr. Duckworth has been a private investor. Mr. Duckworth became a KPMG partner in 1981, and the partner in-charge of the firm's audit practice in Oklahoma City in 1984, and he was the managing partner of the firm's Oklahoma City office from 1987 to 2000, when he relocated to the firm's Houston office to serve as the energy industry leader of that office's audit practice, serving global energy clients. Mr. Duckworth served as the lead audit engagement partner for large, multi-national clients operating in different segments of the energy industry, including upstream oil and gas exploration and production companies, energy marketing and trading companies, and merchant independent power producers and retail power providers. Mr. Duckworth is a member of the Texas State Board of Public Accountancy. He holds a B.S. in accounting with honors from Oklahoma State University and is a certified public accountant.

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 public 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.

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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 38 years of experience in the oil and gas industry. Mr. Hurley serves on the Board of Directors of Brigham Resources, LLC, a privately held oil and gas company. Additionally, Mr. Hurley is a member of the Advisory Board of United Oilfield Services, a privately held oil and gas service company. 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 February 2012. Prior to joining Hunt Oil Company, Mr. Hurley served as Chief Operating Officer, Executive Vice President and a director for Chieftain International, Inc., or Chieftain, from August 1995 to August 2001 when Chieftain was acquired by Hunt Oil Company. Prior to joining Chieftain, Mr. Hurley was Executive Vice President of worldwide Exploration and Production for Murphy Exploration and Production Company, or Murphy. During his 16-year tenure at Murphy, he held the positions of Senior Geologist, Exploration Manager, Vice President and Executive Vice President. From 1975 to 1980, Mr. Hurley was a geologist with Exxon Company USA. Mr. Hurley holds both a B.S. and M.S. in geology from the University of Arkansas and an advanced degree in business studies from Harvard University. He is a past President of both the Dallas Petroleum Club and Dallas Wildcatters Committee. The Board has concluded that the Company benefits from Mr. Hurley’s extensive executive-level experience in the energy industry.

Joe L. McClaugherty, age 62, 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.

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 public 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 Mr. Evans, whose biographical information is included above under “Managment—Biographical Information of Our Directors.”

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

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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.

Joseph C. Daches, age 46, currently serves as Senior Vice President and Chief Financial Officer of the Company. Mr. Daches joined the Company in July 2013. He brings more than 20 years of regulatory compliance, financial reporting, technical accounting, management and oil and gas accounting experience, primarily within the energy industry. Prior to joining the Company, Mr. Daches served as Executive Vice President and Chief Accounting Officer of Energy & Exploration Partners, Inc. since September 2012 and became a director of that company in April 2013. He previously served as Partner and Managing Director of the Willis Consulting Group, LLC from January 2012 to September 2012 and from October 2003 to December 2011, Mr. Daches served as the Director of E&P Advisory Services at Sirius Solutions, LLC where he was primarily responsible for financial reporting, technical, and oil and gas accounting and the overall management of the exploration and production advisory services practice. Mr. Daches earned a B.S. in Accounting from Wilkes University in Pennsylvania, and he is a certified public accountant in good standing with the Texas State Board of Public Accountancy.

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.

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 of 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

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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.

Ronald D. Ormand, age 55, has served as Executive Vice President–Finance and Head of Capital Markets since July 2013. Mr. Ormand has also served as a director of Magnum Hunter from 2009 until September 2013. From May 2009 to July 2013, Mr. Ormand served as Chief Financial Officer and Executive Vice President of the Company. 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.

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 our directors 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., Victor G. Carrillo, Joe L. McClaugherty, Stephen C. Hurley and Jeff Swanson were independent directors in 2012 and continue to be independent directors. Brad Bynum and Steven A. Pfeifer, who both resigned from our Board on July 23, 2013, were independent directors in 2012 through the date of their resignations. Upon his election to the Board in October 2013, our Board determined that Mr. Duckworth satisfied the requirements to be an independent director.

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.

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 10 times 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 this prospectus:

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Director	Audit Committee	Compensation Committee	Governance Committee
J. Raleigh Bailes, Sr.	*ü
Victor G. Carrillo			*ü
Joe L. McClaugherty	ü	*ü
Stephen C. Hurley	ü	ü	ü
Jeff Swanson		ü	ü

(*) Denotes Chair

Compensation Committee Interlocks and Insider Participation

Gary C. Evans in the only director who also serves as an executive officer of Magnum Hunter. Mr. Evans does not serve 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.

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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 lead independent director will receive an additional annual retainer of $15,000, also payable quarterly, as compensation for the additional duties required of that position.

The non-employee directors that served on the GreenHunter special committee described under “Transactions with Related Persons—Certain Relationships and Related Transactions—GreenHunter Transactions” below 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 prospectus, 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 retainers were 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.

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 (4)	—	$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 (4)	—	$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 prospectus 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). For information regarding the assumptions made in determining these values, please refer to Note 12 to our consolidated financial statements included in our 2012 Form 10-K.

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

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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.


(4)	Messrs. Bynum and Pfeifer resigned from the Board on July 23, 2013.

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–Finance, Head of Capital Markets and Secretary (Executive Vice President, Chief Financial Officer and Secretary during 2012)


•	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.

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:

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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 prospectus 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 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. Unless otherwise indicated, the Compensation Committee used March 31, 2013 as the measurement date for the achievement of the performance goals. The Compensation Committee has determined that the Company met or exceeded the established performance goals in all areas other than the price of the Company’s common stock. This represented an overall achievement of 80% of the target on a goal-weighted basis, which was factored into determining each NEO’s bonus for 2012. The actual performance level obtained is indicated in bold and in italics.



		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.

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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.

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:

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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;


•	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.

2012 Summary Compensation Table

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.



Name and Principal						Stock		Option		All Other
Position	Year	Salary (1)		Bonus (2)		Awards (3)		Awards (3)		Compensation (4)		Total
Gary C. Evans (5) Chairman and CEO	2012	$	465,000	$	500,000	—		$	2,943,232	$	90,507	$	3,998,739
	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) Executive V.P. and CFO	2012	$	275,000	$	50,000	—		$	981,077	$	28,057	$	1,334,134
	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 Executive V.P. and President, Appalachian Division	2012	$	275,000	$	275,000	—		$	981,077	$	61,454	$	1,592,531
	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) Executive V.P. and President, Eagle Ford Division	2012	$	275,000	$	500,000	—		$	981,077	$	27,199	$	1,783,276
	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) Executive V.P. and President, Williston Basin Division	2012	$	274,342	$	200,000	—		$	981,077	$	13,668	$	1,469,087

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(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)	For a discussion of the 2012 Executive Bonus Program, refer to “Our Compensation Philosophy—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 to our consolidated financial statements included in our 2012 Form 10-K.


(4)	Amounts in this column are detailed in the All Other Compensation Table, below.


(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.

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.

Mr. Ormand served as Chief Financial Officer until July 2013, when he assumed the roles of Executive Vice President–Finance and Head of Capital Markets.

(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 Canadian dollars (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, above.

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			Health, Dental, Vision,					Disability
	401(k) Matching			and Executive Illness		Life Insurance			Insurance
	Contribution (1)			Premiums		Premiums			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.


(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.



		Number of Securities	Exercise Price of	Grant Date Fair Value
	Grant Date	Underlying Options	Option Awards	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

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.

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		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.

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.

186



	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-End table, above, 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.

187

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS

The following table sets forth information regarding beneficial ownership of Magnum Hunter’s common stock and preferred stock as of September 30, 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.

188



Title of Class	Name of Beneficial Owner	Amount and Nature of Beneficial Ownership (1)	Percent of Class (%)
Common Stock	Gary C. Evans (a)	7,242,276	4%
Common Stock	Ronald D. Ormand (b)	2,189,084	1%
Common Stock	H.C. “Kip” Ferguson, III (c)	914,874	*
Common Stock	R. Glenn Dawson (d)	1,947,594	1%
Common Stock	James W. Denny, III (e)	544,264	*
Common Stock	J. Raleigh Bailes, Sr. (f)(l)	415,601	*
Common Stock	Victor G. Carrillo (h)(m)	33,320	*
Common Stock	Stephen C. Hurley (g)(n)	193,130	*
Common Stock	Joe L. McClaugherty (i) (j)	1,073,543	*
Common Stock	Jeff Swanson (h) (k)	280,784	*
Common Stock	BlackRock, Inc. (o)	14,087,134	8%
Common Stock	The Vanguard Group (p)	8,915,346	5%
Common Stock	Directors and executive officers as a group (15 persons) (q)	16,216,021	10%

10.25% Series C Cumulative Perpetual Preferred Stock	Directors and executive officers as a group	- 0 -	—

8.0% Series D Cumulative Preferred Stock	James W. Denny, III	4,680	*
8.0% Series D Cumulative Preferred Stock	Directors and executive officers as a group (1 person named above)	4,680	*

8.0% Series E Cumulative Convertible Preferred Stock (represented by depositary shares)	Directors and executive officers as a group	- 0 -	—

*Less than 1%.


(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 7,664 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.

189

(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 private family investment companies controlled by Mr. Ormand; and an indirect interest in 7,664 shares of common stock held by the Company’s 401(k) plan. Mr. Ormand has pledged 1,465,600 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 7,664 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 7,664 shares of common stock held by the Company’s 401(k) plan.


(f)	The amount for Mr. Bailes includes an option to purchase 275,000 shares of common stock which has vested.


(g)	Includes an option to purchase 136,000 shares of common stock which has vested.


(h)	The amounts for each of Messrs. Carrillo 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.


(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 175 shares of common stock underlying presently exercisable warrants.


(n)	Includes 1,500 shares of common stock underlying presently exercisable warrants.


(o)	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.


(p)	The Vanguard Group’s principal business office address is 100 Vanguard Boulevard. 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.


(q)	Includes 7,060,749 shares pledged by our officers and directors.

190

TRANSACTIONS WITH RELATED PERSONS

Under SEC rules, public companies, such as Magnum Hunter, must disclose certain “Related Person Transactions.” These are transactions in which: (i) the Company is a participant; (ii) the amount involved exceeds $120,000; and (iii) 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


•	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 and 2013, we rented an airplane for business use for certain members of Company management at various times from Pilatus Hunter, LLC, an entity wholly-owned by Gary C. Evans, our Chairman and Chief Executive Officer.

Airplane rental expenses totaled $174,000 for the year ended December 31, 2012 and $67,350 during the six months ended June 30, 2013.

GreenHunter Transactions

As discussed under “Management — Compensation Committee Interlocks and Insider Participation,” above, Gary C. Evans, our Chairman and Chief Executive Officer, is the Chairman and a major stockholder of GreenHunter; and Ronald D. Ormand, our Executive Vice President–Finance, Head of Capital Markets, Secretary and a former 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, served as the Chief Financial Officer of GreenHunter from May 2006 to August 2013.

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 2012 and 2013, certain subsidiaries of the Company received services related to disposal water and rented equipment from GreenHunter and certain of its subsidiaries. Rental costs totaled $1.0 million for the year ended December 31, 2012 and $72,783 for the six months ended June 30, 2013. Disposal charges totaled $2.4 million for the year ended December 31, 2012 and $1,445,510 for the six months ended June 30, 2013. 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.

On February 17, 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. 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. The special committee retained independent counsel and an independent consultant to assist in the negotiation, execution and closing of the sale. Total consideration for the sale was approximately $9.3 million comprised of $2.2 million in cash, 1,846,722 shares of GreenHunter’s 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’s 10% Series C Cumulative Preferred Stock, valued at $1.9 million based on a stated value of $25.00 per share, and a $2.2 million convertible promissory note which is convertible at the option of the Company into 880,000 shares of GreenHunter’s common stock based on the conversion price of $2.50 per share. 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.

Eagle Ford Hunter Inc., Triad Hunter, LLC and Alpha Hunter Drilling, LLC, each current or former wholly owned subsidiaries of the Company, regularly obtained, and will continue to obtain (in the case of Triad Hunter, LLC and Alpha Hunter Drilling, LLC),

191

services from GreenHunter for vacuum hauling, rig washing, waste fluid management and water management. The Company believes that such services were and will be provided at competitive market rates 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.

On August 1, 2012, Alpha Hunter Drilling, LLC entered into two International Association of Drilling Contractors "IADC" Drilling Bid Proposal and Daywork Drilling Contracts with GreenHunter Water, pursuant to each of which Alpha Hunter Drilling LLC agreed to provide drilling rig and contract operator services to GreenHunter Water for the purpose of drilling a saltwater disposal well to service the Company’s Eagle Ford Shale operations in South Texas. Alpha Hunter Drilling, LLC anticipated that it would take approximately 10 to 12 days to drill each well, resulting in a total drilling fee of approximately $155,000 per well. Drilling services revenues totaled $1.1 million for the year ended December 31, 2012.

TransTex Assets Acquisition

TransTex Gas Services, LP, or TransTex Gas Services, received total consideration of 622,641 Class A Common Units of Eureka Holdings, or Eureka Common Units, and cash of $46 million upon Eureka Holding’s acquisition of certain of its assets. This includes Eureka Common 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 additional Eureka Common Units in lieu of a portion of the cash distribution they would otherwise receive. Certain limited partners purchased such Eureka Common Units, including Mr. Evans (who was a 4.0% limited partner in TransTex Gas Services). Mr. Evans purchased 27,641 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 prospectus, Mr. Evans owned less than 1% of the total number of Eureka Common Units outstanding.

Corporate Apartment Rental

In 2011, the Company 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.

192

LEGAL MATTERS

Certain legal matters relating to the exchange notes and the guarantees offered by this prospectus will be passed upon for us by Fulbright & Jaworski LLP, a member of Norton Rose Fulbright, Dallas, Texas, and Wyatt, Tarrant & Combs, LLP, Louisville, Kentucky.

EXPERTS

Independent Accountants

The consolidated financial statements of the Company as of December 31, 2012 and for the year then ended and management's assessment of the effectiveness of internal control over financial reporting as of December 31, 2012 included in this prospectus have been so included in reliance on the reports of BDO USA, LLP, or BDO, an independent registered public accounting firm (the report on the effectiveness of internal control over financial reporting expresses an adverse opinion on the effectiveness of the Company's internal control over financial reporting as of December 31, 2012) appearing elsewhere herein, given on the authority of BDO as experts in auditing and accounting.

The consolidated financial statements of the Company as of December 31, 2011 and for the years ended December 31, 2011 and 2010 included in this prospectus have been so included in reliance on the report of Hein & Associates LLP , or Hein, an independent registered public accounting firm appearing elsewhere herein, given on the authority of Hein as experts in auditing and accounting.

The financial statements of PRC Williston, LLC (“PRC Williston”), a majority-owned subsidiary of the Company and a guarantor of the senior notes of the Company as of December 31, 2012 and for the year then ended included in this prospectus have been so included in reliance on the report of BDO, an independent registered public accounting firm appearing elsewhere herein, given on the authority of BDO as experts in auditing and accounting.

The financial statements of PRC Williston, as of December 31, 2011 and for the years ended December 31, 2011 and 2010 included in this prospectus have been so included in reliance on the report of Hein, an independent registered public accounting firm appearing elsewhere herein, given on the authority of Hein as experts in auditing and accounting.

The Revenue and Direct Operating Expenses statements of Baytex Energy USA Ltd (“Baytex”) for the year ended December 31, 2011, included in this prospectus have been so included in reliance on the report of Hein, an independent registered public accounting firm appearing elsewhere herein, given on the authority of Hein as experts in auditing and accounting.

Petroleum Engineers

The information relating to oil and natural gas reserves, as of December 31, 2012 and June 30, 2013, included in this prospectus, including all statistics and data, was derived from reserves reports dated January 8, 2013 and July 26, 2013, respectively, evaluating our oil and natural gas properties, prepared by Cawley, Gillespie & Associates, independent oil and gas industry consultants, in reliance on the authority of such firm as experts in the oil and gas industry.

WHERE YOU CAN FIND ADDITIONAL INFORMATION

We are subject to the information requirements of the Exchange Act. In accordance with the Exchange Act, we file reports, proxy statements and other information with the SEC. Such reports, proxy statements and other information filed by us are available to the public free of charge at www.sec.gov. Copies of certain information filed by us with the SEC are also available on our website at www.magnumhunterresources.com. You may also read and copy any document we file with the SEC at the SEC’s Public Reference Room located at 100 F Street, N.E., Washington, D.C. 20549. You may obtain information on the operation of the SEC’s Public Reference Room by calling the SEC at 1-800-SEC-0330. In addition, you may read our SEC filings at the offices of the New York Stock Exchange, which is located at 20 Broad Street, New York, New York 10005.

193

INDEX TO FINANCIAL STATEMENTS



	Page

MHR 10-Q	F-2
Consolidated Balance Sheets as of June 30, 2013 and December 31, 2012	F-2
Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2013 and 2012	F-4
Consolidated Statements of Comprehensive Income (Loss) for the Three and Six Months Ended June 30, 2013 and 2012	F-5
Consolidated Statement of Shareholders’ Equity for the Six Months Ended June 30, 2013	F-6
Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2013 and 2012	F-7
Notes to Consolidated Financial Statements	F-8
PRC 10-Q	F-48
Balance Sheets as of June 30, 2013 and December 31, 2012	F-48
Statements of Operations for the Three and Six Months Ended June 30, 2013 and 2012	F-49
Statements of Changes in Member’s Deficit for the Six Months Ended June 30, 2013 and December 31, 2012	F-50
Statements of Cash Flows for the Six Months Ended June 30, 2013 and 2012 (unaudited)	F-51
Notes to Financial Statements	F-52
MHR 10-K	F-55
Reports of Independent Registered Public Accounting Firms	F-56
Balance Sheets at December 31, 2012 and 2011	F-60
Statements of Operations for the years ended December 31, 2012, 2011, and 2010	F-62
Consolidated Statements of Comprehensive Loss for the years ended December 31, 2012, 2011, and 2010	F-63
Statements of Changes in Member’s Deficit for the years ended December 31, 2012, 2011, and 2010	F-64
Statements of Cash Flows for the years ended December 31, 2012, 2011, and 2010	F-66
Notes to Financial Statements	F-67
PRC 10-K	F-134
Reports of Independent Registered Public Accounting Firms	F-134
Balance Sheets at December 31, 2012 and 2011	F-136
Statements of Operations for the years ended December 31, 2012, 2011, and 2010	F-137
Statements of Changes in Member’s Deficit for the years ended December 31, 2012, 2011, and 2010	F-138
Statements of Cash Flows for the years ended December 31, 2012, 2011, and 2010	F-139
Notes to Financial Statements	F-140
Baytex 8-K	F-147
Statements of Revenues and Direct Operating Expenses of the Oil and Gas Properties Purchased by Bakken Hunter, LLC, from Baytex Energy USA, LTD for the three months ended March 31, 2012 and 2011, and the year ended December 31, 2011 and related notes	F-147
MHR Unaudited Combined Pro Forma Consolidated Statement of Operations	203

F-1

MAGNUM HUNTER RESOURCES CORPORATION

CONSOLIDATED BALANCE SHEETS

(In thousands, except shares and per-share data)



	June 30, 2013			December 31, 2012
	(unaudited)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	32,742		$	57,623
Restricted cash	—			1,500
Accounts receivable, net of allowance for doubtful accounts of $444 and $448 as of June 30, 2013 and December 31, 2012, respectively	72,094			124,861
Derivative assets	3,205			5,146
Inventory	13,088			9,162
Investments	49,294			3,278
Prepaid expenses and other assets	2,977			2,249
Assets held for sale	500			500
Total current assets	173,900			204,319

PROPERTY, PLANT AND EQUIPMENT:
Oil and natural gas properties, successful efforts method of accounting	1,737,830			1,908,118
Accumulated depletion, depreciation, and accretion	(187,810		)	(185,615		)
Total oil and natural gas properties, net	1,550,020			1,722,503
Gas transportation, gathering and processing equipment, net	247,720			201,910
Total property and equipment, net	1,797,740			1,924,413

OTHER ASSETS:
Deferred financing costs, net of amortization of $9,708 and $8,024 as of June 30, 2013 and December 31, 2012, respectively	21,610			23,862
Derivatives and other assets	4,452			6,455
Intangible assets, net	7,616			8,981
Goodwill	30,602			30,602
Total assets	$	2,035,920		$	2,198,632

The accompanying Notes to the Consolidated Financial Statements are an integral part of these unaudited financial statements.

F-2

MAGNUM HUNTER RESOURCES CORPORATION

CONSOLIDATED BALANCE SHEETS

(In thousands, except shares and per-share data)



	June 30, 2013			December 31, 2012
LIABILITIES AND SHAREHOLDERS’ EQUITY	(unaudited)
CURRENT LIABILITIES:
Current portion of notes payable	$	4,353		$	3,991
Accounts payable	120,375			196,515
Accrued liabilities	10,520			11,212
Revenue payable	19,189			20,394
Derivatives and other liabilities	20,581			11,544
Total current liabilities	175,018			243,656

Long-term debt	665,318			886,769
Asset retirement obligation	30,258			28,322
Deferred tax liability	66,881			74,258
Derivative liabilities	56,123			47,524
Other long term liabilities	5,521			5,573
Total liabilities	999,119			1,286,102

COMMITMENTS AND CONTINGENCIES (Note 14)

REDEEMABLE PREFERRED STOCK:
Series C Cumulative Perpetual Preferred Stock ("Series C Preferred Stock"), cumulative dividend rate 10.25% per annum, 4,000,000 authorized, 4,000,000 issued and outstanding as of June 30, 2013 and December 31, 2012, 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, 8,902,326 and 7,672,892 issued and outstanding as of June 30, 2013 and December 31, 2012, respectively, with liquidation preference of $202,446 and $167,403 as of June 30, 2013 and December 31, 2012, respectively	121,271			100,878
	221,271			200,878
SHAREHOLDERS’ EQUITY:
Preferred Stock, 10,000,000 shares authorized
Series D Cumulative Preferred Stock ("Series D Preferred Stock"), cumulative dividend rate 8.0% per annum, 5,750,000 authorized, 4,424,889 and 4,208,821 issued and outstanding as of June 30, 2013 and December 31, 2012, respectively, with liquidation preference of $50.00 per share	221,244			210,441
Series E Cumulative Convertible Preferred Stock ("Series E Preferred Stock"), cumulative dividend rate 8.0% per annum, 12,000 authorized, 3,803 and 3,775 issued and 3,722 and 3,705 outstanding as of June 30, 2013 and December 31, 2012, respectively, with liquidation preference of $25,000 per share	95,069			94,371
Common stock, $0.01 par value per share, 350,000,000 and 250,000,000 shares authorized, and 170,670,884 and 170,032,999 issued, and 169,755,932 and 169,118,047 outstanding as of June 30, 2013 and December 31, 2012, respectively	1,706			1,700
Exchangeable common stock, par value $0.01 per share, none and 505,835 issued and outstanding as of June 30, 2013 and December 31, 2012, respectively	—			5
Additional paid in capital	722,302			715,033
Accumulated deficit	(213,858		)	(307,484		)
Accumulated other comprehensive loss	(16,239		)	(8,889		)
Treasury Stock, at cost:
Series E Preferred Stock, 81 and 70 shares as of June 30, 2013 and December 31, 2012, respectively	(2,030		)	(1,750		)
Common stock, 914,952 shares as of June 30, 2013 and December 31, 2012	(1,914		)	(1,914		)
Total Magnum Hunter Resources Corporation shareholders’ equity	806,280			701,513
Non-controlling interest	9,250			10,139
Total shareholders’ equity	815,530			711,652
Total liabilities and shareholders’ equity	$	2,035,920		$	2,198,632

The accompanying Notes to the Consolidated Financial Statements are an integral part of these unaudited financial statements.

F-3

MAGNUM HUNTER RESOURCES CORPORATION

UNAUDITED CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except shares and per-share data)



	Three Months Ended June 30,						Six Months Ended June 30,
	2013			2012			2013			2012
REVENUES:
Oil and gas sales	$	66,457		$	37,185		$	119,022		$	74,967
Gas transportation, gathering, processing, and marketing	14,413			4,199			30,309			5,360
Oilfield services	3,612			957			7,305			4,614
Gain (loss) on sale of assets and other revenue	(442		)	117			(419		)	(154		)
Total revenue	84,040			42,458			156,217			84,787
EXPENSES:
Lease operating expenses	20,609			10,700			32,740			21,540
Severance taxes and marketing	4,852			2,740			8,045			5,559
Exploration and abandonments	5,157			9,409			34,940			18,425
Impairment of proved oil and gas properties	16,034			—			16,034			—
Gas transportation, gathering, processing, and marketing	13,414			1,971			26,845			2,091
Oilfield services	4,066			1,567			7,401			3,567
Depletion, depreciation, amortization and accretion	37,986			22,669			67,040			42,322
General and administrative	19,601			16,796			41,907			31,639
Total expenses	121,719			65,852			234,952			125,143

OPERATING LOSS	(37,679		)	(23,394		)	(78,735		)	(40,356		)

OTHER INCOME (EXPENSE):
Interest income	94			62			205			96
Interest expense	(18,842		)	(19,432		)	(37,593		)	(24,816		)
Gain (loss) on derivative contracts, net	6,400			18,104			(1,091		)	19,207
Other income	1,466			931			2,488			1,965
Total other income (expense)	(10,882		)	(335		)	(35,991		)	(3,548		)
Loss from continuing operations before income tax	(48,561		)	(23,729		)	(114,726		)	(43,904		)
Income tax benefit	43,566			6,858			48,420			9,150
Loss from continuing operations, net of tax	(4,995		)	(16,871		)	(66,306		)	(34,754		)
(Loss) income from discontinued operations, net of tax	(2,403		)	2,416			14,208			7,517
Gain (loss) on sale of discontinued operations, net of tax	172,452			—			172,452			2,224
Net income (loss)	165,054			(14,455		)	120,354			(25,013		)
Net (income) loss attributable to non-controlling interest	386			(48		)	889			(22		)
Net income (loss) attributable to Magnum Hunter Resources Corporation	165,440			(14,503		)	121,243			(25,035		)
Dividends on preferred stock	(14,129		)	(8,205		)	(27,617		)	(12,860		)
Net income (loss) attributable to common shareholders	$	151,311		$	(22,708	)	$	93,626		$	(37,895	)
Weighted average number of common shares outstanding, basic and diluted	169,690,633			151,464,372			169,657,806			142,293,282
Loss from continuing operations per share, basic and diluted	$	(0.11	)	$	(0.17	)	$	(0.55	)	$	(0.34	)
Income from discontinued operations per share, basic and diluted	1.00			0.02			1.10			0.07
Net income (loss) per common share, basic and diluted	$	0.89		$	(0.15	)	$	0.55		$	(0.27	)

Amounts attributable to Magnum Hunter Resources Corporation:
Loss from continuing operations, net of tax	$	(4,609	)	$	(16,919	)	$	(65,417	)	$	(34,776	)
Income from discontinued operations, net of tax	170,049			2,416			186,660			9,741
Net income (loss)	$	165,440		$	(14,503	)	$	121,243		$	(25,035	)

The accompanying Notes to the Consolidated Financial Statements are an integral part of these unaudited financial statements.

F-4

MAGNUM HUNTER RESOURCES CORPORATION

UNAUDITED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(In thousands, except shares and per-share data)



	Three Months Ended June 30,						Six Months Ended June 30,
	2013			2012			2013			2012
Net income (loss)	$	165,054		$	(14,455	)	$	120,354		$	(25,013	)
Foreign currency translation loss	(7,070		)	(4,119		)	(11,799		)	(617		)
Unrealized gain (loss) on available for sale investments	4,466			(189		)	4,449			(265		)
Comprehensive income (loss)	162,450			(18,763		)	113,004			(25,895		)
Comprehensive income (loss) attributable to non-controlling interests	386			(48		)	889			(22		)
Comprehensive income (loss) attributable to Magnum Hunter Resources Corporation	$	162,836		$	(18,811	)	$	113,893		$	(25,917	)

The accompanying Notes to the Consolidated Financial Statements are an integral part of these unaudited financial statements.

F-5

MAGNUM HUNTER RESOURCES CORPORATION

UNAUDITED CONSOLIDATED STATEMENT OF SHAREHOLDERS' EQUITY

(In thousands)



	Number of Shares of Series D Preferred Stock	Number of Shares of Series E Preferred Stock	Number of Shares of Common Stock	Number of Shares of Exchangeable Common Stock		Series D Preferred Stock		Series E Preferred Stock		Common Stock		Exchangeable Common Stock			Additional Paid in Capital			Accumulated Deficit			Accumulated Other Comprehensive Income			Treasury Stock			Non - controlling Interest			Total Shareholders’ Equity
BALANCE, January 1, 2013	4,209	4	170,033	506		$	210,441	$	94,371	$	1,700	$	5		$	715,033		$	(307,484	)	$	(8,889	)	$	(3,664	)	$	10,139		$	711,652
Share based compensation	—	—	132	—		—		—		1		—			8,698			—			—			—			—			8,699
Sold shares of Series D Preferred Stock for cash	216	—	—	—		10,803		—		—		—			(1,212		)	—			—			—			—			9,591
Dividends on preferred stock	—	—	—	—		—		—		—		—			—			(27,617		)	—			—			—			(27,617		)
Issued shares of common stock upon exchange of MHR Exchangeco Corporation's exchangeable shares	—	—	506	(506	)	—		—		5		(5		)	—			—			—			—			—			—
Sold shares of Series E Preferred Stock for cash	—	—	—	—		—		698		—		—			(108		)	—			—			—			—			590
Fees on equity issuance	—	—	—	—		—		—		—		—			(109		)	—			—			—			—			(109		)
Depositary shares representing Series E Preferred Stock returned from escrow	—	—	—	—		—		—		—		—			—			—			—			(280		)	—			(280		)
Net income	—	—	—	—		—		—		—		—			—			121,243			—			—			(889		)	120,354
Foreign currency translation	—	—	—	—		—		—		—		—			—			—			(11,799		)	—			—			(11,799		)
BALANCE, Unrealized gain on available for sale securities	—	—	—	—		—		—		—		—			—			—			4,449			—			—			4,449
BALANCE, June 30, 2013	4,425	4	170,671	—		$	221,244	$	95,069	$	1,706	$	—		$	722,302		$	(213,858	)	$	(16,239	)	$	(3,944	)	$	9,250		$	815,530

The accompanying Notes to the Consolidated Financial Statements are an integral part of these unaudited financial statements.

F-6

MAGNUM HUNTER RESOURCES CORPORATION

UNAUDITED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)



	Six Months Ended June 30,
	2013			2012
Cash flows from operating activities
Net income	$	120,354		$	(25,013	)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Depletion, depreciation, amortization and accretion	73,078			56,860
Exploration and abandonments	34,168			17,693
Impairment of proved oil and gas properties	16,034			—
Impairment of other operating assets	263			—
Share based compensation	8,699			12,539
Cash paid for plugging wells	—			(101		)
Gain on sale of assets	(206,082		)	(3,369		)
Unrealized (gain) loss on derivative contracts	786			(13,469		)
Unrealized loss on investments	1,152			265
Amortization and write-off of deferred financing costs and discount on Senior Notes included in interest expense	2,758			10,086
Deferred tax benefit	(6,475		)	(3,811		)
Changes in operating assets and liabilities:
Accounts receivable, net	7,760			(2,530		)
Inventory	(459		)	(1,231		)
Prepaid expenses and other current assets	(802		)	(991		)
Accounts payable	24,099			(10,340		)
Revenue payable	(1,204		)	3,356
Accrued liabilities	(261		)	9,221
Net cash provided by operating activities	73,868			49,165
Cash flows from investing activities
Capital expenditures and advances	(277,492		)	(224,925		)
Cash paid in acquisitions	—			(434,322		)
Change in restricted cash	1,500			—
Change in deposits and other long-term assets	154			(256		)
Proceeds from sales of assets	380,036			783
Net cash provided by (used in) investing activities	104,198			(658,720		)
Cash flows from financing activities
Net proceeds from sale of common shares	—			148,675
Net proceeds from sale of preferred shares	10,181			50,883
Fees on preferred shares issued in acquisition	(109		)	—
Proceeds from sale of Series A convertible preferred units in Eureka Hunter Holdings, LLC	19,600			127,393
Proceeds from exercise of warrants and options	—			1,197
Preferred stock dividend paid	(10,424		)	(9,531		)
Principal repayments of debt	(327,076		)	(466,209		)
Proceeds from borrowings on debt	105,991			341,684
Proceeds from issuing Senior Notes	—			443,971
Payment of deferred financing costs	(701		)	(18,709		)
Change in other long-term liabilities	(52		)	145
Net cash provided by (used in) financing activities	(202,590		)	619,499
Effect of exchange rate changes on cash	(357		)	(33		)
Net increase (decrease) in cash and cash equivalents	(24,881		)	9,911
Cash and cash equivalents, beginning of period	57,623			14,851
Cash and cash equivalents, end of period	$	32,742		$	24,762

Supplemental disclosure of cash flow information
Cash paid for interest	$	34,448		$	10,434
Non-cash transactions
Common stock issued for acquisitions	$	—		$	1,902
Non-cash consideration received from sale of assets	$	42,300		$	7,087
Change in accrued capital expenditures	$	(42,774	)	$	25,505
Non-cash additions to asset retirement obligation	$	1,896		$	2,055
Eureka Hunter Holdings, LLC Series A common units issued for acquisition	$	—		$	12,453
Eureka Hunter Holdings, LLC Series A convertible preferred unit dividends paid in kind	$	2,253		$	—

The accompanying Notes to the Consolidated Financial Statements are an integral part of these unaudited financial statements.

F-7

MAGNUM HUNTER RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

NOTE 1—ORGANIZATION AND NATURE OF OPERATIONS

Magnum Hunter Resources Corporation, a Delaware corporation, operating directly and indirectly through its subsidiaries (together with its subsidiaries, the “Company”, “Magnum Hunter”, "we," "us," or "our"), 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 services activities.

NOTE 2 — LIQUIDITY

At June 30, 2013, the Company had (i) cash and cash equivalents of $32.7 million, of which $8.2 million was held by Eureka Hunter Holdings, LLC ("Eureka Hunter Holdings") or its subsidiaries, which are unrestricted subsidiaries under our MHR Senior Revolving Credit Facility, as defined in "Note 8 - Long-Term Debt," and was only available for use by Eureka Hunter Holdings or its subsidiaries; (ii) a working capital deficit of $1.1 million; and (iii) $264.8 million of borrowing availability under the MHR Senior Revolving Credit Facility.

The Company utilizes credit agreements, as described in "Note 8 – Long-Term Debt," to fund a portion of operating and capital needs. The Company had no outstanding debt under the MHR Senior Revolving Credit Facility at June 30, 2013, with an available borrowing base at that date of $265.0 million. On April 24, 2013, the Company sold a wholly-owned subsidiary, Eagle Ford Hunter, Inc. ("Eagle Ford Hunter"), for a total purchase price of $422.1 million, paid to us in the form of $379.8 million in (cash based on customary initial closing adjustments) and $42.3 million in Penn Virginia Corporation ("Penn Virginia") common stock, valued based on the closing market price of the stock of $4.23 as of April 24, 2013, resulting in a gain of $172.5 million, net of tax. See "Note 6 - Divestitures and Discontinued Operations" for information regarding the sale of Eagle Ford Hunter to Penn Virginia in April 2013 and the Penn Virginia stock we received as partial consideration for such sale. Of the cash proceeds, $325.0 million was used to pay off the MHR Senior Revolving Credit Facility. As a result of the sale, the borrowing base under the Senior Revolving Credit Facility was adjusted down to $265.0 million.

For the six months ended June 30, 2013, the Company had net income attributable to common shareholders of $93.6 million and operating loss from continuing operations of $78.7 million, including non-cash charges of $29.5 million in leasehold impairment expense related to leases in the Williston Basin region that expired in the quarter ended June 30, 2013, or are expected to expire during the remainder of 2013 and that we do not plan to develop, and $4.7 million in lease abandonment expense.

As of June 30, 2013, the Company was in compliance with all of our covenants, as amended or waived, contained in our credit agreements as described in "Note 8 – Long-Term Debt."

As of June 30, 2013, we had $600.0 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 would be registered and generally freely transferable under the Securities Act of 1933. In addition, we agreed to file, under certain circumstances, a shelf registration statement to cover re-sales of the Senior Notes. On May 16, 2013, we began to accrue penalty interest at the rate of 0.25% per annum, in addition to the stated per annum interest rate, on the outstanding principal amount of the Senior Notes, as a result of our failure to complete the exchange offer for the Senior Notes by May 16, 2013. We were unable to complete the exchange offer by this date because of our failure to timely file our annual report on Form 10-K for the year ended December 31, 2012 and our quarterly report on Form 10-Q for the quarter ended March 31, 2013 within the time frame requirements of the SEC. The amount of penalty interest will increase by 0.25% per annum each subsequent 90-day period following the May 16, 2013 required exchange offer completion date, until the exchange offer is completed, up to a maximum penalty interest amount of 1.00% per annum. We plan to file a registration statement with the SEC for the exchange offer as promptly as practicable following the filing of this quarterly report on Form 10-Q, and, once the registration statement has been declared effective by the SEC, to commence and complete the exchange offer promptly thereafter.

The late filings of our 2012 Form 10-K and first quarter 2013 Form 10-Q periodic reports constituted a “default” under our Senior Notes indenture, which resulted in the unavailability of certain exceptions to restrictive covenants contained therein, including in respect of our ability to make certain restricted payments, including the payment of dividends on our preferred stock. As a result, we were not permitted to pay dividends on our 10.25% Series C Cumulative Perpetual Preferred Stock ("Series C Preferred Stock"), 8.0% Series D Cumulative Preferred Stock ("Series D Preferred Stock") and 8.0% Series E Cumulative Convertible Preferred Stock

F-8

("Series E Preferred Stock") for the months of April, May, June and July 2013 on our normal end-of-the month dividend payment dates. As of August 7, 2013, we had a total of $8.9 million of preferred dividends in arrears related to the three-month period ended June 30, 2013, and $2.9 million of preferred dividends in arrears for July 2013.

On July 29, 2013, following the filing of our 2012 Form 10-K and first quarter 2013 Form 10-Q, the Company announced that it had declared cash dividends on the Company's Series C Preferred Stock, Series D Preferred Stock, and Series E Preferred Stock, for the months of April, May, June, July and August 2013, referred to as the "Declared Accumulated Dividend." The Declared Accumulated Dividend is payable on September 3, 2013, to holders of record at the close of business on August 15, 2013. The Declared Accumulated Dividend represented (i) all accumulated accrued and unpaid dividends on the Company's preferred stock for the months of April, May, June, July and August 2013, and (ii) the to-be-accrued dividends on the preferred stock for the remainder of August 2013.

We believe that cash flows from operations, borrowings under our MHR Senior Revolving Credit Facility and other debt agreements, continued liquidation of our shares of Penn Virginia common stock, and anticipated non-core asset sales will finance substantially all of our capital needs through 2013 and well into 2014. 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 to fund potential acquisitions, provide working capital or for other liquidity needs, if such financing is available and on acceptable terms. However, as a result of our failure to timely file our annual report on Form 10-K for the year ended December 31, 2012 and our quarterly report on Form 10-Q for the quarter ended March 31, 2013 within the time frame requirements of the SEC, we may be limited by the requirement that we use more restrictive forms of registration statements 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.

Until we have timely filed all our required SEC reports for a period of twelve months (which period we expect to expire in August 2014, assuming we remain timely in the filing of our SEC reports during that period), 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. We had conducted ATM offerings on a regular basis with respect to our preferred stock prior to our late SEC filings. In the future, we may use Form S-1 to register a sale of our 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.

NOTE 3 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Principles of Consolidation and Presentation

The accompanying unaudited interim financial statements of Magnum Hunter have been prepared in accordance with accounting principles generally accepted in the United States of America and the rules of the SEC, for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X and should be read in conjunction with the audited financial statements and notes thereto contained in the Company’s annual report on Form 10-K for the year ended December 31, 2012. In the opinion of management, all adjustments, consisting of normal recurring adjustments, necessary for a fair statement of the financial position and the results of operations for the interim periods presented have been reflected herein. The results of operations for interim periods are not necessarily indicative of the results to be expected for the full year. The year-end balance sheet data were derived from audited financial statements, but do not include all disclosures required by accounting principles generally accepted in the United States of America. Notes to the consolidated financial statements that would substantially duplicate the disclosures contained in the audited consolidated financial statements as reported in our 2012 annual report on Form 10-K have been omitted.

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 Eagle Ford Hunter, Inc. ("Eagle Ford Hunter") on April 24, 2013, and our sale of Hunter Disposal, LLC ("Hunter Disposal"), on February 17, 2012, the gain on sale and all prior operating income and expense for these entities were reclassified as discontinued operations for all periods presented. The previously filed June 30, 2013 Form 10-Q financial results for the comparative three and six month periods ended June 30, 2012 were subsequently adjusted to reflect the tax effects of the Eagle Ford Hunter sale, which were insignificant.

F-9

Discontinued Operations

Gain or loss on sold assets may be considered discontinued operations at the time the determination is made to reclassify the assets on the balance sheet as assets held for sale. However, income provided by assets held for sale may not be shown as discontinued operations if significant cash flows exist from any retained assets or if the Company has continued involvement in the same area.

During the three month period ended June 30, 2013, we sold 100% of the capital stock of our subsidiary, Eagle Ford Hunter. The Company established that Eagle Ford Hunter should be classified as held for sale as of the quarter ended March 31, 2013; however, since the Company expected to have significant remaining operations in South Texas under a new subsidiary, Shale Hunter, LLC ("Shale Hunter"), management determined that discontinued operations presentation for Eagle Ford Hunter was not applicable at March 31, 2013. Our mid-year reserves update showed that the reserves in the Shale Hunter properties had decreased below our threshold of significance for continuing operations and expected cash flows from the former Eagle Ford Hunter properties, thus, the criteria for discontinued operations were met at June 30, 2013. At June 30, 2013, income from operations of Eagle Ford Hunter, for all periods presented, and gain related to the sale of Eagle Ford Hunter were reclassified as discontinued operations. See "Note 6 - Divestitures and Discontinued Operations."

During the three month period ended March 31 2012, we sold our subsidiary, Hunter Disposal, and therefore reflected the gain on sale as well as current and prior operating results as discontinued operations. See "Note 6 - Divestitures and Discontinued Operations."

Non-Controlling Interest in Consolidated Subsidiaries

We have consolidated PRC Williston, LLC ("PRC Williston") in which we own 87.5% and Eureka Hunter Holdings in which we owned 58.33% and 61.0% as of June 30, 2013 and December 31, 2012, respectively. Eureka Hunter Holdings owns, directly or indirectly, 100% of the equity interests of Eureka Hunter Pipeline, LLC ("Eureka Hunter Pipeline"), TransTex Hunter, LLC ("TransTex Hunter"), and Eureka Hunter Land, LLC.

Net Income or Loss per 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 based on income from continuing operations and also considers the impact to net income and common shares for the potential dilution from stock options, stock purchase warrants and any outstanding convertible securities.

The Company has issued potentially dilutive instruments in the form of common stock options, common stock purchase warrants, Series E Preferred Stock, and restricted common stock granted and not yet issued. We did not include the dilutive securities in our calculation of diluted loss per share during any of the periods presented herein, because to include them would have been anti-dilutive due to our loss from continuing operations during those periods.

The following table summarizes the potentially dilutive securities outstanding as of June 30, 2013 and 2012:



	June 30,
	2013	2012
	(in thousands)
Dilutive:
Common stock options	1,962	7,294
Warrants	—	126
Restricted shares granted, not yet issued	—	19
Total dilutive	1,962	7,439
Anti-dilutive:
Common stock options	16,834	8,423
Warrants	13,376	13,392
Series E Preferred Stock	11,169	—
Total anti-dilutive	41,380	21,815

F-10

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 June 30, 2013, 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 June 30, 2013 and December 31, 2012. See "Note 4 – Fair Value of Financial Instruments."

Inventory

The Company’s materials inventory is primarily frac sand used in the completion process of hydraulic fracturing. Frac sand is acquired for use in future well completion 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 are recorded as a reduction to the carrying value of the inventory on the Company’s consolidated balance sheets, and as an increase to lease operating expense in the accompanying consolidated statements of operations. Commodity inventories are carried at the lower of average cost or market, on a first-in, first-out basis. The Company’s commodity inventories consist of oil held in storage and gas pipeline fill volumes. Any valuation allowances are recorded as reductions to the carrying values of the commodity inventories included in the Company’s consolidated balance sheets and as charges to lease operating expense in the consolidated statements of operations.

The following table sets forth our materials and supplies inventory as of June 30, 2013 and December 31, 2012:



	June 30, 2013		December 31, 2012
	(in thousands)
Supplies and materials	$	11,635	$	1,096
Commodities	1,453		8,066
Inventory	$	13,088	$	9,162

Supplies included in other long term assets	$	192	$	3,464

Oil and Gas Properties

The Company utilizes 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 or leases acquired are not prospective or expire, 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.

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 has goodwill of $30.6 million related to our midstream segment as a result of our acquisition of the assets of TransTex Gas Services, LP in April 2012.

Goodwill is assessed for impairment whenever events or circumstances indicate that impairment of the carrying value of goodwill is likely, but no less than annually. If the carrying value of goodwill is determined to be impaired, it is reduced for the impaired value with a corresponding charge to pretax earnings in the period in which it is determined to be impaired. The Company performed its annual assessment of goodwill impairment in April 2013 and determined that no impairment of goodwill existed at that time.

F-11

Intangible Assets

Intangible assets consist primarily of the fair value of the acquired gas gathering and processing contracts and customer relationships in the TransTex Gas Services, LP assets acquisition completed in 2012. The fair value of the intangible assets was determined using a discounted cash flow model with a discount rate of 13%. These assets are being amortized over a weighted average term of 8.5 years. At June 30, 2013, our intangible assets were not impaired.

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. As the Company considers undistributed earnings in Canada to be indefinitely reinvested in Canada, there is no tax effect of the translation.

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 Abandonments

Exploration and abandonments include charges for capitalized leasehold costs associated with unproved properties that the Company has chosen not to develop and therefore has allowed or expects to allow leases to expire. The balance of exploration expense consists primarily of geological and geophysical costs. The following table provides the Company's exploration and abandonment expense from continuing operations for the three and six months ended June 30, 2013 and 2012.



	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2013		2012		2013		2012
	(in thousands)				(in thousands)
Leasehold impairments	$	4,817	$	—	$	29,474	$	4,885
Leasehold abandonment	—		9,024		4,695		12,810
Other	340		385		771		730
Total	$	5,157	$	9,409	$	34,940	$	18,425

Impairment of Proved Oil and Gas Properties

Proved oil and natural gas properties are reviewed for impairment on a field-by-field basis when events and circumstances indicate a possible decline in the recoverability of the carrying amount of such property. We estimate the expected future cash flows of our oil and natural gas properties and compare these undiscounted cash flows to the carrying amount of the oil and natural gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, we will write down the carrying amount of the oil and natural gas properties to fair value. The factors used to determine fair value include, but are not limited to, estimates of reserves, future commodity prices, future lease operating expense, future production estimates, estimated future capital expenditures and discount rates commensurate with the risk associated with realizing the projected cash flows.

During the six months ended June 30, 2013, changes in production estimates and lease operating costs provided indications of possible impairment of the Company's proved properties in the Williston and Appalachian Basins. As a result of management's assessments during the second quarter of 2013, the Company recognized pretax noncash impairment charges of $16.0 million to reduce the

F-12

carrying value of these properties to their estimated fair values. The Company calculated the estimated fair value as of June 30, 2013 using a discounted cash flow model. The expected future net cash flows were discounted using an annual rate of 10 percent to determine estimated fair value.

Recently Issued Accounting Standards

Accounting standards-setting organizations frequently issue new or revised accounting rules. We regularly review all new pronouncements to determine their impact, if any, on our financial statements.

In July 2013, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") 2013-11, Presentation of Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists, an amendment to FASB Accounting Standards Codification ("ASC") Topic 740, Income Taxes ("FASB ASC Topic 740"). This update clarifies that an unrecognized tax benefit, or a portion of an unrecognized tax benefit, should be presented in the financial statements as a reduction to a deferred tax asset for a net operating loss carryforward, a similar tax loss, or a tax credit carryforward if such settlement is required or expected in the event the uncertain tax position is disallowed. In situations where a net operating loss carryforward, a similar tax loss, or a tax credit carryforward is not available at the reporting date under the tax law of the applicable jurisdiction or the tax law of the jurisdiction does not require, and the entity does not intend to use, the deferred tax asset for such purpose, the unrecognized tax benefit should be presented in the financial statements as a liability and should not be combined with deferred tax assets. This ASU is effective prospectively for fiscal years, and interim periods within those years, beginning after December 15, 2013. Retrospective application is permitted. We are currently evaluating the impact of this ASU on our consolidated financial statements and financial statement disclosures.

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

We used the following fair value measurements for certain of our assets and liabilities at June 30, 2013 and December 31, 2012:

Level 1 Classification:

Available for Sale Securities

At June 30, 2013 and December 31, 2012, the Company held common and preferred stock of publicly traded companies with quoted prices in an active market. Accordingly, the fair market value measurements of these securities have been classified as Level 1.

Level 2 Classification:

Commodity Derivative Instruments

At June 30, 2013 and December 31, 2012, 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. The estimated fair value amounts 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 June 30, 2013 and December 31, 2012, 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 the counterparties are believed to have minimal credit risk. Although the Company is exposed to credit risk to the extent of

F-13

nonperformance by the counterparties in 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 June 30, 2013 and 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. See "Note 11 - Redeemable Preferred Stock" for additional information.

The fair value of the bifurcated conversion feature was valued using the “with and without” analysis in a simulation model. The key inputs used in the model to determine fair value at June 30, 2013 were a volatility of 26%, credit spread of 15.06%, and a total enterprise value of Eureka Hunter Holdings of $499.0 million.

Convertible Security Embedded Derivative

The key inputs used in the Black-Scholes option pricing model were as follows:



	June 30, 2013
Life	3.6
Risk-free interest rate	1.17		%
Estimated volatility	40		%
Dividend	—
GreenHunter stock price at end of period	$	0.80

The following table presents a reconciliation of the financial derivative asset and liability measured at fair value using significant unobservable inputs for the six month period ended June 30, 2013:



	Preferred Stock Embedded Derivative Liability			Convertible Security Embedded Derivative Asset
	(in thousands)
Fair value at December 31, 2012	$	(43,548	)	$	264
Issuance of derivative liability	(6,960		)	—
Increase (decrease) in fair value recognized in other income (expense)	(5,440		)	(211		)
Fair value as of June 30, 2013	$	(55,948	)	$	53

F-14

The following tables present recurring financial assets and liabilities which are carried at fair value at June 30, 2013 and December 31, 2012:



	Fair Value Measurements on a Recurring Basis
	June 30, 2013
	(in thousands)
Assets	Level 1		Level 2		Level 3
Available for sale securities	$	48,652	$	—	$	—
Commodity derivative assets	—		4,700		—
Convertible security derivative assets	—		—		53
Total assets at fair value	$	48,652	$	4,700	$	53
Liabilities
Commodity derivative liabilities	$	—	$	2,429	$	—
Convertible preferred stock derivative liabilities	—		—		55,948
Total liabilities at fair value	$	—	$	2,429	$	55,948



	Fair Value Measurements on a Recurring Basis
	December 31, 2012
	(in thousands)
Assets	Level 1		Level 2		Level 3
Available for sale securities	$	1,958	$	—	$	—
Commodity derivative assets	—		4,882		—
Convertible security derivative assets	—		—		264
Total assets at fair value	$	1,958	$	4,882	$	264
Liabilities
Commodity derivative liabilities	$	—	$	7,477	$	—
Convertible preferred stock derivative liabilities	—		—		43,548
Total liabilities at fair value	$	—	$	7,477	$	43,548

Other Fair Value Measurements

The carrying value of our MHR Senior Revolving Credit Facility approximates fair value as it is subject to short-term floating interest rates that approximate the rates available to us for those periods. The fair value hierarchy for our MHR Senior Revolving Credit Facility is Level 1.

The fair value of our Senior Notes is based on quoted market prices available to us at these dates. The estimated fair value of our Senior Notes as of June 30, 2013 and December 31, 2012 was $622.3 million and $613.5 million, respectively. The fair value hierarchy for our Senior Notes is Level 2 (quoted prices for identical assets in active markets).

The fair value of Eureka Hunter Pipeline's second lien term loan 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 the Company’s default or repayment risk. The credit spread (premium or discount) is determined by comparing the Company’s 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. The fair value of all fixed-rate notes and the credit facility is based on interest rates currently available to the Company. Eureka Hunter Pipeline's second lien term loan is valued using an income approach and classified as Level 3 in the fair value hierarchy.

F-15

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:



		June 30, 2013				December 31, 2012
	Fair Value Hierarchy Level	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
		(in thousands)
Senior Notes ⁽¹⁾	2	$	597,209	$	622,320	$	597,212	$	613,500
MHR Senior Revolving Credit Facility ⁽²⁾	1	$	—	$	—	$	225,000	$	225,000
Eureka Hunter Pipeline, LLC second lien term loan ⁽³⁾	3	$	50,000	$	57,143	$	50,000	$	58,550
Equipment notes payable ⁽³⁾	3	$	22,462	$	21,571	$	18,548	$	17,450


^1.	The fair value of our Senior Notes is based on quoted market prices available to us for those periods.


^2.	The carrying value of the MHR Senior Revolving Credit Facility approximates fair value as it is subject to short-term floating interest rates that approximate the rates available to us at such date.


^3.	The fair value of each of (a) Eureka Hunter Pipeline's second lien term loan and (b) the equipment notes 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.

Fair Value on a Non-Recurring Basis

The Company follows the provisions of ASC 820-10 for non-financial assets and liabilities measured at fair value on a non-recurring basis. As it relates to Magnum Hunter, ASC 820-10 applies to certain non-financial 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 ARO is presented in "Note 7 - Asset Retirement Obligations."

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 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, an early termination payment obligation thereunder, and/or otherwise materially adversely affect our business, financial condition and results of operations.

F-16

As of June 30, 2013, we had the following derivative instruments in place:



			Weighted Average
Natural Gas	Period	MMBTU/day	Price per MMBTU
Collars	Jul 2013 - Dec 2013	12,500	$4.50 - $5.96
Swaps	Jul 2013 - Dec 2013	25,500	$3.64
	Jan 2014 - Dec 2014	5,000	$4.26
Ceilings purchased (call)	Jul 2013 - Dec 2013	10,000	$6.00
	Jan 2014 - Dec 2014	10,000	$6.15
Ceilings sold (call)	Jan 2014 - Dec 2014	26,000	$5.47
Floors purchased (put)	Jul 2013 - Dec 2013	10,000	$4.25
Floors sold (put)	Jan 2014 - Dec 2014	10,000	$3.75
			Weighted Average
Crude Oil	Period	Bbls/day	Price per Bbl
Collars	Jul 2013 - Dec 2013	2,763	$81.38 - $97.61
	Jan 2014 - Dec 2014	663	$85.00 - $91.25
	Jan 2015 - Dec 2015	259	$85.00 - $91.25
Three-way collars (1)	Jul 2013 - Dec 2013	2,000	$60.63 - $80.00 - $100.00
	Jan 2014 - Dec 2014	4,000	$64.94 - $85.00 - $102.50
Three-way collars (2)	Jul 2013 - Dec 2013	763	$65.00 - $91.25 - $101.25
Swaps	Jul 2013 - Dec 2013	5,450	$92.72
Ceilings purchased (call)	Jul 2013 - Dec 2013	2,250	$100.00
Ceilings sold (call)	Jan 2015 - Dec 2015	1,570	$120.00
Floors purchased (put)	Jul 2013 - Dec 2013	1,750	$90.00
Floors sold (put)	Jul 2013 - Dec 2013	5,438	$76.03
	Jan 2014 - Dec 2014	663	$65.00
	Jan 2015 - Dec 2015	259	$70.00
(1) These three-way collars are a combination of three options: a sold call, a purchased put and a sold put

(2) This three-way collar is a combination of three options: a sold call, a purchased call and a sold put

Currently, Bank of America, Bank of Montreal, KeyBank National Association, Credit Suisse Energy, LLC, UBS AG London Branch, Deutsche Bank AG London Branch, Citibank, N.A., and J. Aron & Company are the only counterparties to our commodity derivatives positions. We are exposed to credit losses in the event of nonperformance by the counterparties; 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 MHR Senior Revolving Credit Facility, and the collateral for the outstanding borrowings under our MHR Senior Revolving Credit Facility is used as collateral for our commodity derivatives with those counterparties.

At June 30, 2013, 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. See "Note 4 – Fair Value of Financial Instruments" and "Note 11 — Redeemable Preferred Stock," for more information.

At June 30, 2013, the Company also had a convertible security embedded derivative asset primarily due to the conversion feature of the promissory note received as partial consideration for the sale of Hunter Disposal. See "Note 4 – Fair Value of Financial Instruments," "Note 6 – Divestitures and Discontinued Operations" and "Note 13 – Related Party Transactions," for additional information.

F-17

The following table summarizes the fair value of our commodity derivative contracts as of the dates indicated:



		Gross Derivative Assets				Gross Derivative Liabilities
Derivatives not designated as hedging instruments	Balance Sheet Classification	June 30, 2013		December 31, 2012		June 30, 2013			December 31, 2012
		(in thousands)
Commodity
	Current assets - derivatives	$	3,152	$	4,882	$	—		$	—
	Derivatives and other long term assets	1,548		—		—			—
	Derivatives and other current liabilities	—		—		(2,254		)	(3,501		)
	Derivatives and other long term liabilities	—		—		(175		)	(3,976		)
Total commodity		$	4,700	$	4,882	$	(2,429	)	$	(7,477	)
Financial
	Derivative assets - current	$	53	$	264	$	—		$	—
	Derivative liabilities - long term	—		—		(55,948		)	(43,548		)
Total financial		$	53	$	264	$	(55,948	)	$	(43,548	)

The following table summarizes the realized and unrealized gains and losses on change in fair value of our derivative contracts as of the dates indicated:



	Three Months Ended June 30,					Six Months Ended June 30,
	2013			2012		2013			2012
	(in thousands)
Realized gain (loss)	$	(1,261	)	$	4,251	$	(305	)	$	5,738
Unrealized gain (loss)	7,661			13,853		(786		)	13,469
Net gain (loss)	$	6,400		$	18,104	$	(1,091	)	$	19,207

NOTE 6 — DIVESTITURES AND DISCONTINUED OPERATIONS

Sale of Eagle Ford Hunter

On April 24, 2013, the Company closed on the sale of all of its ownership interest in its wholly-owned subsidiary, Eagle Ford Hunter, to an affiliate of Penn Virginia for a total purchase price of approximately $422.1 million made up of a cash payment of $379.8 million (after customary initial purchase price adjustments) and 10.0 million shares of common stock of Penn Virginia valued at approximately $42.3 million (based on the closing market price of the stock as of April 24, 2013). The effective date of the sale was January 1, 2013. The Company has recognized a gain on the sale of $172.5 million, net of tax. The Company and Penn Virginia have agreed to extend the final settlement of the cash portion of the purchase price, which is to occur on or about August 22, 2013. Upon closing of the sale, $325.0 million of sale proceeds were used to pay down outstanding borrowings under the MHR Senior Revolving Credit Facility.

The Company established that Eagle Ford Hunter should be classified as held for sale as of the quarter ended March 31, 2013; however, since the Company expected to have significant remaining operations in South Texas under a new subsidiary, Shale Hunter, management determined that discontinued operations presentation for Eagle Ford Hunter was not applicable at March 31, 2013. Our mid-year reserves update showed that the reserves in the Shale Hunter properties had decreased below our threshold of significance for continuing operations and expected cash flows from the former Eagle Ford Hunter properties, thus, the criteria for discontinued operations were met at June 30, 2013. At June 30, 2013, income from operations of Eagle Ford Hunter, for all periods presented, and gain related to the sale of Eagle Ford Hunter were reclassified as discontinued operations.

F-18

Sale of Hunter Disposal

On February 17, 2012, the Company, through its wholly-owned subsidiary, Triad Hunter, LLC ("Triad Hunter"), sold 100% of its equity ownership interest in Hunter Disposal to an affiliate of GreenHunter, for total consideration of $9.3 million, comprised of cash of $2.2 million, 1,846,722 common shares of GreenHunter valued at $2.6 million based on a closing price of $1.79 per share, discounted for restrictions, 88,000 shares of GreenHunter 10% Series C Preferred Stock, valued at $1.9 million based on a stated value of $25.00 per share, and a promissory note of $2.2 million which is convertible, at the option of the Company, into 880,000 shares of GreenHunter 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 fair market 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 to reflect the effective date of the sale of December 31, 2011. GreenHunter is a related party as described in "Note 13 - Related Party Transactions."

The operating results of Eagle Ford Hunter and Hunter Disposal for the three and six months ended June 30, 2013 and 2012, have been reclassified as discontinued operations in the consolidated statements of operations as detailed in the table below:



	Three Months Ended June 30,						Nine Months Ended Six Months Ended June 30,
	2013 ⁽²⁾			2012 ⁽¹⁾			2013 ⁽²⁾			2012 ⁽¹⁾
	(in thousands)
Revenues	$	7,308		$	16,496		$	33,174		$	32,286
Expenses	(1,258		)	(10,223		)	(10,513		)	(20,913		)
Other income (expense)	—			—			—			1
Income tax expense (3)	(8,453		)	(3,857		)	(8,453		)	(3,857		)
Income (loss) from discontinued operations, net of tax	(2,403		)	2,416			14,208			7,517
Gain (loss) on sale of discontinued operations, net of taxes	172,452			—			172,452			2,224
Income from discontinued operations, net of taxes ⁽⁴⁾	$	170,049		$	2,416		$	186,660		$	9,741

___________________________

(1)

In the second quarter of 2012, the Company revised its disclosure of discontinued operations to include adjustments reducing the gain on sale of Hunter Disposal. The revision included a tax adjustment of $1.4 million and an adjustment to discount the value of the GreenHunter shares received by $619,000. Management concluded that this revision was not material to the related March 31, 2012 financial statements.


(2)	Includes operations of Eagle Ford Hunter from January 1, 2013 through April 24, 2013, the date of the sale.


(3)	The book income tax charge for the three and six months ended June 30, 2013 relating to discontinued operation's gain for such period was $8.5 million, which is more than offset by the Company's current year deductions. In addition, an alternative minimum tax charge of $1.3 million also arose on the Eagle Ford Hunter sale.


(4)	The gain in the three and six months ended June 30, 2013 is related to the Eagle Ford Hunter sale of approximately $207.2 million million, net of $34.7 million book income tax charge.

NOTE 7 — ASSET RETIREMENT OBLIGATIONS

The Company records a liability for the fair value of an asset’s retirement obligation in the period in which it is incurred and the corresponding cost is capitalized by increasing the carrying amount of the related long-lived asset. The liability is accreted to its then present value each period, and the capitalized cost is depreciated over the estimated economic life of the related asset. We have included estimated future costs of abandonment and dismantlement in our successful efforts amortization base and amortize these costs as a component of our depreciation, depletion, and accretion expense in the accompanying consolidated financial statements.

F-19

The following table summarizes the Company’s asset retirement obligation activities during the six month period ended June 30, 2013:



	Six Months Ended June 30, 2013
	(in thousands)
Asset retirement obligation at beginning of period	$	30,680
Liabilities incurred	90
Liabilities settled	(355		)
Accretion expense	1,136
Revisions in estimated liabilities ⁽¹⁾	1,935
Effect of foreign currency translation	(129		)
Asset retirement obligation at end of period	33,357
Less: current portion (included in other liabilities)	(3,099		)
Asset retirement obligation at end of period	$	30,258

⁽¹⁾$1.5 million of the revisions in estimated liabilities is related to change in assumptions used with respect to certain wells in Williston Basin US and Tableland Canada.

NOTE 8 — LONG-TERM DEBT

Long-term debt at June 30, 2013 and December 31, 2012 consisted of the following:



	June 30, 2013			December 31, 2012
	(in thousands)
Senior Notes payable due May 15, 2020, interest rate of 9.75%, net of unamortized net discount of $2.8 million at June 30, 2013 and December 31, 2012	$	597,209		$	597,212
Various equipment and real estate notes payable with maturity dates January 2015 - April 2021, interest rates of 4.25% - 5.70%	22,462			18,548
Eureka Hunter Pipeline, LLC second lien term loan due August 16, 2018, interest rate of 12.5%	50,000			50,000
MHR Senior Revolving Credit Facility due April 13, 2016, interest rate of 2.96% at June 30, 2013 and 3.56% at December 31, 2012	—			225,000
	$	669,671		890,760
Less: current portion	(4,353		)	(3,991		)
Total long-term debt obligations, net of current portion	$	665,318		886,769

____________________________

The following table presents the scheduled or expected approximate annual maturities of debt, gross of unamortized discount:



	(in thousands)
2013	$	2,172
2014	4,369
2015	12,145
2016	2,627
2017	1,149
Thereafter	650,000
Total	$	672,462

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.

F-20

Company’s proved crude oil and natural gas reserves, and based on such redetermination, the borrowing base may be decreased or may be increased up to a maximum commitment level of $750.0 million.

Pursuant to the Seventeenth Amendment to Second Amended and Restated Credit Agreement and as a result of the sale of Eagle Ford Hunter on April 24, 2013, the borrowing base under the MHR Senior Revolving Credit Facility was decreased from $350.0 million to $265.0 million,

Sixteenth Amendment to 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 to Penn Virginia 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 that was received by the Company upon the sale of stock of Eagle Ford Hunter.

Seventeenth Amendment to 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, the Company's wholly-owned subsidiary, to Penn Virginia 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 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) or (ii) June 17, 2013. The Company filed its 2012 Form 10-K on June 14, 2013 which included its audited financial statements for the year ended December 31, 2012, and thus delivered the annual financial statements required by the Senior Notes indenture (the "Indenture").The Company filed its Form 10-Q for the period ended March 31, 2013 on July 9, 2013. With the filing of the Form 10-Q, the Company delivered the financial statements for the first quarter of 2013 required by the Indenture. Under the Seventeenth Amendment, the lenders under the MHR Senior Revolving Credit Facility waived any event of default under the facility that had occurred 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 filing of the Company's Form 10-Q for the quarterly period ended March 31, 2013. The Seventeenth Amendment also revised Section 9.18 of the MHR Senior Revolving Credit Facility to clarify that existing maximum hedging limits apply to each of crude oil (including NGLs) and natural gas independently, with neither commodity impacting the Company's ability to hedge the other.

Eighteenth Amendment to Second Amended and Restated Credit Agreement

On August 7, 2013, pursuant to the Eighteenth Amendment to Second Amended and Restated Credit Agreement (the “Eighteenth Amendment”), the MHR Senior Revolving Credit Facility was amended as follows:

(i) While the total debt to EBITDAX covenant is deferred as described in (ii) below, implement a new total senior debt to EBITDAX covenant set at 2.00x EBITDAX;

(ii) the Company's current total debt to EBITDAX covenant is deferred for the period starting June 30, 2013 until June 30, 2014 at which time the level of debt to EBITDAX of less than 4.50x EBITDAX will be in effect, decreasing to less than 4.25x EBITDAX starting December 31, 2014;

(iii) amends the EBITDAX to interest expense covenant to no less than 2.00x for the quarters ended June 30, 2013 and ending September 30, 2013, increasing to 2.25x for the quarter ending December 31, 2013 and increasing to 2.50x starting March 31, 2014 and thereafter;

F-21

(iv) allow for up to $32 million in investments in the Company's unrestricted subsidiary Eureka Hunter Holdings provided a) the investments are made before December 31, 2013 and b) the borrowing base has availability of at least $75.0 million at the time of such investment, provided that the Company may also invest in Eureka Hunter Holdings using proceeds from the sale of its common or preferred equity (any such investments would be utilized to further expand Eureka Hunter Pipeline);

(v) reduces the Company's Senior Note basket to $600 million from $800 million;

(vi) increases the investment basket for unrestricted subsidiaries (other than Eureka Hunter Holdings) from $7.5 million to $12.5 million for the fiscal year ending December 31, 2013, thereafter the basket shall remain $7.5 million in any calendar year;

(vii) establish an acquisition and leasehold expenditures basket commencing August 1, 2013 through the Company's compliance with the financial covenants for the fiscal quarter ending June 30, 2014, which shall equal (a) $40.0 million plus (b) if at the time of and after giving effect to any such investment, availability under the borrowing base is equal to or greater than $75.0 million, (i) asset sale proceeds net of any borrowing base reduction resulting from such asset sale and (ii) the net cash proceeds from the offering of common or preferred equity securities by the Company; and

(viii) increase pricing by 50 basis points to LIBOR plus 250 to 325 basis points from LIBOR plus 200 to 275 basis points based on utilization until the Company demonstrates compliance with the financial covenants for the fiscal quarter ending June 30, 2014.

The Company had no amounts outstanding under the Senior Revolving Credit Facility as of June 30, 2013 and $225.0 million outstanding as of December 31, 2012.

At June 30, 2013, we were in compliance with all of our covenants, as amended or waived, contained in the MHR Senior Revolving Credit Facility.

The following table sets forth interest expense for the three and six month period ended June 30, 2013 and 2012, respectively:



	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2013		2012		2013		2012
	(in thousands)
Interest expense incurred on debt	$	17,149	$	9,909	$	35,043	$	14,730
Amortization and write off of deferred financing costs	1,693		9,523		2,550		10,086
Total Interest Expense	$	18,842	$	19,432	$	37,593	$	24,816

NOTE 9 — SHARE-BASED COMPENSATION

Under our amended and restated Stock Incentive Plan, our common stock, common stock options, and stock appreciation rights may be granted to directors, officers, employees and other persons who contribute to the success of Magnum Hunter. Currently, 27,500,000 shares of our common stock are authorized to be issued under the plan, and 3,815,707 shares had been issued as of June 30, 2013.

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 420,000 common stock options to members of the Board of Directors, which have a term of 10 years and vested immediately.

We recognized share-based compensation expense of $2.4 million and $8.7 million for the three and six months ended June 30, 2013 and $7.9 million and $12.5 million for the three and six months ended June 30, 2012, respectively.

F-22

A summary of common stock option activity for the six months ended June 30, 2013 and June 30, 2012 is presented below:



					Weighted Average Exercise Price per Share
	Six Months Ended June 30,
	2013		2012		2013		2012
	(in thousands)
Outstanding at beginning of period	14,847		12,566		$	6.01	$	5.64
Granted	4,363		—		$	4.16	$	—
Exercised	—		(831	)	$	—	$	1.38
Forfeited	(413	)	(403	)	$	6.61	$	7.79
Outstanding at end of period	18,796		11,332		$	5.56	$	5.88
Exercisable at end of period	11,139		7,211		$	5.72	$	5.75

A summary of the Company’s non-vested common stock options and stock appreciation rights for the six months ended June 30, 2013 and June 30, 2012 is presented below:



	Six Months Ended June 30,
	2013		2012
	(in thousands)
Non-vested at beginning of period	6,163		5,651
Granted	4,363		—
Vested	(2,677	)	(1,150	)
Forfeited	(191	)	(380	)
Non-vested at end of period	7,657		4,121

Total unrecognized compensation cost related to the non-vested common stock options was $14.3 million and $17.2 million as of June 30, 2013 and 2012, respectively. The unrecognized cost at June 30, 2013 is expected to be recognized over a weighted-average period of 1.64 years. At June 30, 2013, the weighted average remaining contract life was 6.66 years.

Total unrecognized compensation cost related to non-vested, restricted shares amounted to $165,000 and $561,000 as of June 30, 2013 and 2012, respectively. The unrecognized cost at June 30, 2013, is expected to be recognized over a weighted-average period of 0.42 years.

The assumptions used in the fair value method calculation for the six months ended June 30, 2013, are:



Weighted average fair value per option granted during the period (1)	$2.47
Assumptions: (2), (3)
Weighted average stock price volatility	77.77%
Weighted average risk free rate of return	0.70%
Weighted average expected term	4.51 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)	Our estimated future forfeiture rate is 2.45%.


(3)	The Company does not pay dividends on its common stock.

NOTE 10 —SHAREHOLDERS’ EQUITY

Common Stock

During the six months ended June 30, 2013, the Company issued 132,050 shares of the Company’s common stock in connection with share-based compensation which had fully vested to senior management and directors of the Company.

F-23

During the six months ended June 30, 2013, the Company issued 505,835 shares of the Company’s common stock upon exchange of 505,835 exchangeable shares issued by MHR Exchangeco Corporation in connection with the Company’s acquisition of NuLoch Resources, Inc. in May 2011.

Series D Preferred Stock

During the six months ended June 30, 2013, the Company issued under an at-the-market (“ATM”) sales agreement an aggregate of 216,068 shares of our Series D Preferred Stock with a liquidation preference of $50.00 per share for cumulative net proceeds of approximately $9.6 million, which included various offering expenses of approximately $200,000.

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 its liquidation preference of $50.00 per share (plus accrued and unpaid dividends) or in certain circumstances, prior to such date as a result of a change in control.

Series E Preferred Stock

Each share of our Series E Preferred Stock, 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 Series C Preferred Stock and Series D 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 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.

During the six months ended June 30, 2013, the Company issued under an ATM sales agreement an aggregate of 27,906 Depositary Shares, each representing a 1/1,000th interest in a share of the Company’s Series E Preferred Stock, liquidation preference $25,000 per share. The Depositary Shares were sold to the public at an average price of $24.24 per Depositary Share, and net proceeds to the Company were $590,000 after deducting underwriting commissions and issuance costs.

Preferred Dividends in Arrears

The indenture governing our Senior Notes and each of our credit facilities, which include our MHR Senior Revolving Credit Facility and Eureka Hunter Pipeline's revolver and term loan facilities, require us to file with the SEC and make available to certain parties specific reports and documents under the Securities Exchange Act of 1934, 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 with the SEC our Form 10-K for the fiscal year ended December 31, 2012 or our Form 10-Q for the fiscal quarter ended March 31, 2013. We have now filed both of these reports with the SEC, and have also filed with the SEC an amendment to a Form 8-K we filed in April 2013, containing certain pro forma financial information regarding our sale in April 2013 of Eagle Ford Hunter to Penn Virginia.

The late filings of our 2012 Form 10-K and first quarter 2013 Form 10-Q periodic reports constituted a “default” under our Senior Notes indenture, which resulted in the unavailability of certain exceptions to restrictive covenants contained therein, including with respect to our ability to make certain restricted payments, including the payment of dividends on our preferred stock. As a result, we were not permitted to pay dividends on our Series C Preferred Stock, Series D Preferred Stock and Series E Preferred Stock for the months of April, May, June and July 2013. As of August 7, 2013, we had a total of $8.9 million of preferred dividends in arrears related to the three month period ended June 30, 2013, and $2.9 million of preferred dividends in arrears for July 2013.

On July 29, 2013, following the filing of our 2012 Form 10-K and first quarter 2013 Form 10-Q, the Company announced that it has declared cash dividends on the Company's Series C Preferred Stock, Series D Preferred Stock, and Series E Preferred Stock, for the months of April, May, June, July and August 2013, referred to as the "Declared Accumulated Dividend." The Declared Accumulated Dividend is payable on September 3, 2013, to holders of record at the close of business on August 15, 2013.

The Declared Accumulated Dividend represented (i) all accumulated accrued and unpaid dividends on the Company's preferred stock for the months of April, May, June, July and August 2013 and (ii) the to-be-accrued dividends on the preferred stock for the remainder of August 2013.

F-24

Preferred Dividends Incurred

A summary of the Company's preferred dividends expense for the three and six months ended June 30, 2013 and 2012 is presented below:



	For the three months				For the six months
	ended June 30,				ended June 30,
	2013		2012		2013		2012
	(in thousands)				(in thousands)
Dividend on Eureka Hunter Holdings Series A Preferred Units	$	3,556	$	2,426	$	6,670	$	2,446
Accretion of the carrying value of the Eureka Hunter Holdings Series A Preferred Units	1,696		842		3,164		1,030
Dividend on Series C Preferred Stock	2,562		2,562		5,124		5,124
Dividend on Series D Preferred Stock	4,424		2,375		8,807		4,260
Dividend on Series E Preferred Stock	1,890		—		3,852		—
Total dividends on Preferred Stock	$	14,129	$	8,205	$	27,617	$	12,860

Accretion of the difference between the carrying value and the redemption value of the Eureka Hunter Holdings Series A Convertible Preferred Units is included in dividends on preferred stock.

NOTE 11 — REDEEMABLE PREFERRED STOCK

Eureka Hunter Holdings 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 ("ArcLight"). Pursuant to this Unit Purchase Agreement, Ridgeline committed, subject to certain conditions, to purchase up to $200.0 million of Series A Convertible Preferred Units, representing membership interests of Eureka Hunter Holdings (the “Series A Preferred Units”), of which $171.8 million had been contributed as of June 30, 2013.

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 June 30, 2013 represent 39.9% of the ownership of Eureka Hunter Holdings on a basis as converted to Class A Common Units of Eureka Hunter Holdings.

During the six months ended June 30, 2013, Eureka Hunter Holdings issued 229,434 Series A Preferred Units as payment of $4.6 million in distributions paid-in-kind to holders of the Series A Preferred Units. The fair value of the embedded derivative feature on the outstanding Eureka Hunter Holdings Series A Preferred Units was determined to be $55.9 million in the aggregate at June 30, 2013.

Dividend expense included accretion of the Eureka Hunter Holdings Series A Preferred Units of $1.7 million and $3.2 million for the three and six months ended June 30, 2013, and $842,000 and $1.0 million for the three and six months ended June 30, 2012.

F-25

NOTE 12 — TAXES

The Company's income tax benefit associated with continuing operations for the three and six months ended June 30, 2013 and 2012 was:



	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2013		2012		2013		2012
	(in thousands)				(in thousands)
Deferred tax benefit	43,566		6,858		48,420		9,150
Income tax benefit	$	43,566	$	6,858	$	48,420	$	9,150

We recognize deferred income taxes for the future tax consequences attributable to differences between the financial statement carrying amounts of the existing assets and liabilities and their respective tax basis and net operating loss and credit carryforwards. Income tax expense for the six months ended June 30, 2013 included a U. S. valuation allowance of $83.3 million and income tax benefit of $48.4 million for U.S. and Canada. The valuation allowance will continue to be recognized until the realization of future deferred tax benefits is more likely than not to be utilized. The Company files income tax returns in the U.S., various states and Canada. As of June 30, 2013, no adjustments have been proposed by any tax jurisdiction that would have a significant impact on the Company's liquidity, future results of operations or financial position.

On April 24, 2013, the Company sold all of its ownership interest in its wholly-owned subsidiary, Eagle Ford Hunter, to an affiliate of Penn Virginia, and recognized a book gain of $172.5 million. However, taking into consideration the Company's 2013 capital expenditure budget, the Company expects to continue to realize losses on continuing operations for the remainder of 2013. Management believes it is more likely than not that the Company will not realize the benefit of net operating losses in 2013. The book income tax charge for the six months ended June 30, 2013 relating to discontinued operation's gain for such period was $8.5 million, which is more than offset by the Company's current year deductions. In addition, the Company expects to pay an alternative minimum tax of $1.3 million related to the Eagle Ford Hunter sale.

NOTE 13 — RELATED-PARTY TRANSACTIONS

The following table sets forth the related party transaction activities for the three and six months ended June 30, 2013 and 2012, respectively:



		Three Months Ended				Six Months Ended
		June 30,				June 30,
		2013		2012		2013		2012
GreenHunter
	Salt water disposal ⁽¹⁾	$	589,985	$	—	$	1,445,510	$	—
	Equipment rental ⁽¹⁾	98,306		316,000		72,783		631,000
	Interest Income from Note Receivable ⁽²⁾	53,931		56,611		107,708		81,889
	Dividends received from Series C shares	36,667		55,000		91,667		81,278
	Loss on investments ⁽²⁾	208,480		65,280		677,007		121,087
Pilatus Hunter, LLC
	Airplane rental expenses ⁽³⁾	20,100		64,125		67,350		81,225
Executive of the Company
	Corporate apartment rental ⁽⁴⁾	—		4,000		—		18,000

F-26

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. Prepaid expenses from GreenHunter were $55,800 and $0 at June 30, 2013 and December 31, 2012, respectively. The Company had net accounts payable to GreenHunter of $546,038 and $0 at June 30, 2013 and December 31, 2012, respectively.

⁽²⁾ On February 17, 2012, the Company sold its wholly-owned subsidiary, Hunter Disposal to GreenHunter Water, LLC ("GreenHunter Water"), a wholly-owned subsidiary of GreenHunter. The Company recognized an embedded derivative asset resulting from the conversion option on the convertible promissory note it received as partial consideration for the sale. The fair market value of the derivative asset was $53,000, and $264,000 at June 30, 2013 and December 31, 2012, respectively. See "Note - 4 Fair Value of Financial Instruments." The Company has recorded interest income as a result of the note receivable from GreenHunter. Also as a result of this transaction, the Company has an equity method investment in GreenHunter. that is included in derivatives and other long term assets and an available for sale investment in GreenHunter included in investments.

⁽³⁾ The Company rented an airplane for business use for certain members of Company management at various times from Pilatus Hunter, LLC, an entity 100% owned by Mr. Evans. Airplane rental expenses are recorded in general and administrative expense.

NOTE 14 — COMMITMENTS AND CONTINGENCIES

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. On June 18, 2013, Mark Respler filed another shareholder derivative suit in the District of Delaware on behalf of the Company against the Company's directors and senior officers. On June 27, 2013, Timothy Bassett filed another shareholder derivative suit in the Southern District of Texas 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 plaintiffs. The Derivative Cases are in their preliminary stages. The individual defendants intend to vigorously defend the Derivative Cases. It is possible that additional shareholder derivative suits could be filed over these events.

The Company also received a letter on April 26, 2013, 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.

The Company believes that these claims are covered by the terms of its directors' and officers' insurance policies, and that the coverage available under these insurance policies will be adequate to cover the costs of these claims, including professional fees and other

F-27

defense costs. However, we cannot provide any assurances regarding the foregoing, and we refer you to the risk factors contained in our annual report on Form 10-K for the year ended December 31, 2012, including the risk factor entitled "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."

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 western West Virginia. Costs to acquire and install the rig and components were $14.6 million, of which $1.1 million remains due in equal installments over twelve months beginning once certain operating performance criteria have been met.

F-28

NOTE 15 — SEGMENT REPORTING

United States ("U.S.") Upstream, Canadian Upstream, Midstream and Oilfield Services represent the operating segments of the Company. The factors used to identify these reportable segments are based on the nature of the operations, nationality, operating strategies and management expertise involved in each. The Upstream segments are organized and operate to explore for and produce crude oil and natural gas within the geographic boundaries of the U.S. and Canada. The Midstream segment operates a network of pipelines and compression stations that gather natural gas and NGLs for transportation to market. The Oilfield Services segment provides drilling services to other oil and gas exploration and production companies. Midstream and Oilfield Services customers are our subsidiaries and other third-party oil and gas companies.

The following tables set forth operating activities by segment for the three and six months ended June 30, 2013 and 2012, respectively.



	As of and for the Three Months Ended June 30, 2013
	(in thousands)
	U.S. Upstream			Canadian Upstream			Midstream and Marketing			Oilfield Services			Corporate Unallocated			Inter-segment Eliminations			Total
Revenues
Oil and gas sales	$	57,923		$	8,534		$	—		$	—		$	—		$	—		$	66,457
Gas transportation, gathering, processing, and marketing	439			—			16,151			—			—			(2,177		)	14,413
Oilfield services	—			—			—			3,693			—			(81		)	3,612
Gain (loss) on sale of assets and other revenue	(439		)	—			—			(3		)	—			—			(442		)
Total revenue	57,923			8,534			16,151			3,690			—			(2,258		)	84,040
Expenses
Lease operating expenses	20,882			1,904			—			—			—			(2,177		)	20,609
Severance taxes and marketing	4,446			406			—			—			—			—			4,852
Exploration and abandonments	3,546			1,611			—			—			—			—			5,157
Impairment of proved oil & gas properties	15,920			114			—			—			—			—			16,034
Gas transportation, gathering, processing, and marketing	—			—			13,414			—			—			—			13,414
Oilfield services	—			—			—			4,147			—			(81		)	4,066
Depletion, depreciation, amortization and accretion	27,590			6,593			3,282			521			—			—			37,986
General and administrative	4,783			1,173			2,053			107			11,485			—			19,601
Total expenses	77,167			11,801			18,749			4,775			11,485			(2,258		)	121,719
Interest income	80			776			—			—			1,550			(2,312		)	94
Interest expense	(2,213		)	(825		)	(1,199		)	(142		)	(16,775		)	2,312			(18,842		)
Gain (loss) on derivative contracts,(net)	(167		)	—			(5,169		)	—			11,736			—			6,400
Other income (expense)	1,592			—			(226		)	—			100			—			1,466
Total other income (expense)	(708		)	(49		)	(6,594		)	(142		)	(3,389		)	—			(10,882		)
Loss from continuing operations before income tax	(19,952		)	(3,316		)	(9,192		)	(1,227		)	(14,874		)	—			(48,561		)
Income tax benefit	913			708			—			—			41,945			—			43,566
Net loss from continuing operations	(19,039		)	(2,608		)	(9,192		)	(1,227		)	27,071			—			(4,995		)
Income from discontinued operations, net of tax	6,050			—			—			—			(8,453		)	—			(2,403		)
Gain on sale of discontinued operations, net of tax	172,452			—			—			—			—			—			172,452
Net income (loss)	$	159,463		$	(2,608	)	$	(9,192	)	$	(1,227	)	$	18,618		$	—		$	165,054

Total segment assets	$	1,413,296		$	248,908		$	248,964		$	34,287		$	98,469		$	(8,004	)	$	2,035,920

F-29



	As of and for the Three Months Ended June 30, 2012
	(in thousands)
	U.S. Upstream			Canadian Upstream			Midstream and Marketing			Oilfield Services			Corporate Unallocated			Inter-segment Eliminations			Total
Revenues
Oil and gas sales	$	29,712		$	7,473		$	—		$	—		$	—		$	—		$	37,185
Gas transportation, gathering, processing, and marketing	—			—			4,199			—			—			—			4,199
Oilfield services	—			—			—			1,392			—			(435		)	957
Gain on sale of assets and other revenue	102			1			14			—			—			—			117
Total revenue	29,814			7,474			4,213			1,392			—			(435		)	42,458
Expenses
Lease operating expenses	10,581			901			—			—			—			(782		)	10,700
Severance taxes and marketing	2,180			560			—			—			—			—			2,740
Exploration and abandonments	5,831			3,578			—			—			—			—			9,409
Gas transportation, gathering and processing	—			—			1,971			—			—			—			1,971
Oilfield services	—			—			—			1,219			—			348			1,567
Depletion, depreciation, amortization and accretion	16,431			4,799			1,190			249			—			—			22,669
General and administrative	3,249			1,621			795			57			11,074			—			16,796
Total expenses	38,272			11,459			3,956			1,525			11,074			(434		)	65,852
Interest income	30			767			—			—			28			(763		)	62
Interest expense	(893		)	—			(1,725		)	(75		)	(17,502		)	763			(19,432		)
Gain (loss) on derivative contracts, (net)	105			—			(1,350		)	—			19,349			—			18,104
Other income (expense)	933			—			(2		)	—			—			—			931
Total other income (expense)	175			767			(3,077		)	(75		)	1,875			—			(335		)
Loss from continuing operations before income tax	(8,283		)	(3,218		)	(2,820		)	(208		)	(9,199		)	(1		)	(23,729		)
Income tax benefit	6,063			795			—			—			—			—			6,858
Net loss from continuing operations	(2,220		)	(2,423		)	(2,820		)	(208		)	(9,199		)	(1		)	(16,871		)
Income (loss) from discontinued operations, net of tax	2,416			—			—			—			—			—			2,416
Loss on sale of discontinued operations, net of tax	—			—			—			—			—			—			—
Net loss	$	196		$	(2,423	)	$	(2,820	)	$	(208	)	$	(9,199	)	$	(1	)	$	(14,455	)

Total segment assets	$	1,306,811		$	243,965		$	183,175		$	12,493		$	59,639		$	(469	)	$	1,805,614

F-30



	As of and for the Six Months Ended June 30, 2013
	(in thousands)
	U.S. Upstream			Canadian Upstream			Midstream and Marketing			Oilfield Services			Corporate Unallocated			Inter-segment Eliminations			Total
Oil and gas sales	$	97,711		$	21,311		$	—		$	—		$	—		$	—		$	119,022
Gas transportation, gathering, processing, and marketing	439			—			33,453			—			—			(3,583		)	30,309
Oilfield services	—			—			—			7,424			—			(119		)	7,305
Gain (loss) on sale of assets and other revenue	(416		)	—			—			(3		)	—			—			(419		)
Total revenue	97,734			21,311			33,453			7,421			—			(3,702		)	156,217
Lease operating expenses	32,724			3,637			—			—			—			(3,621		)	32,740
Severance taxes and marketing	7,429			616			—			—			—			—			8,045
Exploration and abandonments	33,279			1,661			—			—			—			—			34,940
Impairment of proved oil & gas properties	15,920			114			—			—			—			—			16,034
Gas transportation, gathering, processing, and marketing	—			—			26,845			—			—			—			26,845
Oilfield services	—			—			—			7,482			—			(81		)	7,401
Depletion, depreciation, amortization and accretion	44,186			16,026			5,969			859			—			—			67,040
General and administrative	8,526			2,143			3,290			471			27,477			—			41,907
Total expenses	142,064			24,197			36,104			8,812			27,477			(3,702		)	234,952
Interest income	181			1,540			—			—			2,804			(4,320		)	205
Interest expense	(4,167		)	(1,498		)	(2,038		)	(231		)	(33,979		)	4,320			(37,593		)
Gain (loss) on derivative contracts, (net)	(211		)	—			(5,440		)	—			4,560			—			(1,091		)
Other income (expense)	2,599			—			(211		)	—			100			—			2,488
Total other income (expense)	(1,598		)	42			(7,689		)	(231		)	(26,515		)	—			(35,991		)
Loss from continuing operations before income tax	(45,928		)	(2,844		)	(10,340		)	(1,622		)	(53,992		)	—			(114,726		)
Income tax benefit	5,767			708			—			—			41,945			—			48,420
Net loss from continuing operations	(40,161		)	(2,136		)	(10,340		)	(1,622		)	(12,047		)	—			(66,306		)
Income from discontinued operations, net of tax	22,661			—			—			—			(8,453		)	—			14,208
Gain on sale of discontinued operations, net of tax	172,452			—			—			—			—			—			172,452
Net income (loss)	$	154,952		$	(2,136	)	$	(10,340	)	$	(1,622	)	$	(20,500	)	$	—		$	120,354
																			—
Total segment assets	$	1,413,296		$	248,908		$	248,964		$	34,287		$	98,469		$	(8,004	)	$	2,035,920

F-31



	As of and for the Six Months Ended June 30, 2012
	(in thousands)
	U.S. Upstream			Canadian Upstream			Midstream and Marketing			Oilfield Services			Corporate Unallocated			Inter-segment Eliminations			Total
Oil and gas sales	$	58,441		$	16,526		$	—		$	—		$	—		$	—		$	74,967
Gas transportation, gathering, processing, and marketing	—			—			5,360			—			—			—			5,360
Oilfield services	—			—			—			6,260			—			(1,646		)	4,614
Gain (loss) on sale of assets and other revenue	104			1			17			(276		)	—			—			(154		)
Total revenue	58,545			16,527			5,377			5,984			—			(1,646		)	84,787
Lease operating expenses	20,954			2,231			—			—			—			(1,645		)	21,540
Severance taxes and marketing	4,361			1,198			—			—			—			—			5,559
Exploration and abandonments	14,845			3,580			—			—			—			—			18,425
Gas transportation, gathering, processing, and marketing	—			—			2,091			—			—			—			2,091
Oilfield services	—			—			—			3,567			—			—			3,567
Depletion, depreciation, amortization and accretion	30,598			9,618			1,658			448			—			—			42,322
General and administrative	6,215			2,313			1,107			106			21,898			—			31,639
Total expenses	76,973			18,940			4,856			4,121			21,898			(1,645		)	125,143
Interest income	31			1,536			—			—			55			(1,526		)	96
Interest expense	(1,681		)	(1		)	(3,007		)	(158		)	(21,495		)	1,526			(24,816		)
Gain (loss) on derivative contracts, (net)	105			—			(1,350		)	—			20,452			—			19,207
Other income (expense)	1,967			—			(2		)	—			—			—			1,965
Total other income (expense)	422			1,535			(4,359		)	(158		)	(988		)	—			(3,548		)
Income (loss) from continuing operations before income tax	(18,006		)	(878		)	(3,838		)	1,705			(22,886		)	(1		)	(43,904		)
Income tax benefit	8,937			213			—			—			—			—			9,150
Net income (loss) from continuing operations	(9,069		)	(665		)	(3,838		)	1,705			(22,886		)	(1		)	(34,754		)
Income from discontinued operations	7,163			—			—			354			—			—			7,517
Gain on sale of discontinued operations	—			—			—			2,224			—			—			2,224
Net income (loss)	$	(1,906	)	$	(665	)	$	(3,838	)	$	4,283		$	(22,886	)	$	(1	)	$	(25,013	)

Total segment assets	$	1,306,811		$	243,965		$	183,175		$	12,493		$	59,639		$	(469	)	$	1,805,614

F-32

NOTE 16 — CONDENSED CONSOLIDATING GUARANTOR FINANCIAL STATEMENTS

During the third quarter of 2013, but subsequent to the issuance of the Company's financial statements as of June 30, 2013 as filed on Form 10-Q, the Company revised its condensed consolidating balance sheets as of June 30, 2013 and December 31, 2012 and statements of operations for the three and six months ended June 30, 2013 to reflect Shale Hunter as a guarantor and Eagle Ford Hunter as a non guarantor under both the currently effective universal shelf registration statement of the Company on Form S-3 and our senior notes. The impact of this revision to the Guarantor Subsidiaries and Non Guarantor Subsidiaries columns of the balance sheet is an increase and decrease, respectively, in total assets of $40.5 million at June 30, 2013 and decrease and increase, respectively, of $264.1 million at December 31, 2012. The impact of this revision to the Guarantor Subsidiaries and Non Guarantor Subsidiaries columns of the statements of operations was a decrease and an increase, respectively, in loss attributable to common shareholders of $769,000 for the six months ended June 30, 2013.

Effective Universal Shelf Registration Statement

Certain of the Company's wholly-owned subsidiaries, Eagle Ford Hunter (up to April 24, 2013, when it was sold to Penn Virginia), Triad Hunter, 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, on a joint and several basis, the obligations of the Company under any debt securities that the Company may issue from time to time pursuant to a currently effective universal shelf registration statement of the Company on Form S-3, which issuances of debt securities cannot be made until the Company again becomes eligible to use the Form S-3 registration statement.

These condensed consolidating guarantor financial statements have been revised to reflect Eagle Ford Hunter as a non-guarantor as the subsidiary was no longer a guarantor upon the closing of the sale on April 24,2013.

Condensed consolidating financial information for Magnum Hunter, the Guarantor Subsidiaries and the other subsidiaries of the Company (the “Non Guarantor Subsidiaries”) as of June 30, 2013 and December 31, 2012, and for the three and six months ended June 30, 2013 and 2012, are as follows:

Magnum Hunter Resources Corporation and Subsidiaries Condensed Consolidating Balance Sheets

(in thousands)



	As of June 30, 2013
	Magnum Hunter Resources Corporation		Guarantor Subsidiaries		Non Guarantor Subsidiaries		Eliminations			Magnum Hunter Resources Corporation Consolidated
ASSETS
Current assets	$	70,615	$	65,479	$	45,810	$	(8,004	)	$	173,900
Intercompany accounts receivable	756,306		—		—		(756,306		)	—
Property and equipment (using successful efforts method of accounting)	7,476		1,213,016		577,248		—			1,797,740
Investment in subsidiaries	681,755		102,097		92,967		(876,819		)	—
Other assets	20,378		1,846		42,056		—			64,280
Total Assets	$	1,536,530	$	1,382,438	$	758,081	$	(1,641,129	)	$	2,035,920

LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities	$	28,161	$	120,970	$	33,930	$	(8,043	)	$	175,018
Intercompany accounts payable	—		725,035		31,235		(756,270		)	—
Long-term liabilities	602,089		78,608		143,404		—			824,101
Redeemable preferred stock	100,000		—		121,271		—			221,271
Shareholders’ equity	806,280		457,825		428,241		(876,816		)	815,530
Total Liabilities and Shareholders’ Equity	$	1,536,530	$	1,382,438	$	758,081	$	(1,641,129	)	$	2,035,920

F-33

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	$	48,320	$	124,041	$	(31,209	)	$	204,319
Intercompany accounts receivable	803,834		—		—		(803,834		)	—
Property and equipment (using successful efforts method of accounting)	9,596		1,148,714		766,103		—			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	$	1,303,717	$	1,036,208	$	(1,802,595	)	$	2,198,632

LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities	$	28,503	$	109,536	$	135,994	$	(30,377	)	$	243,656
Intercompany accounts payable	—		611,932		191,902		(803,834		)	—
Long-term liabilities	831,286		83,192		127,968		—			1,042,446
Redeemable preferred stock	100,000		—		100,878		—			200,878
Shareholders’ equity	701,513		499,057		479,466		(968,384		)	711,652
Total Liabilities and Shareholders’ Equity	$	1,661,302	$	1,303,717	$	1,036,208	$	(1,802,595	)	$	2,198,632

F-34

Magnum Hunter Resources Corporation and Subsidiaries Condensed Consolidating Statements of Operations

(in thousands)



	Three Months Ended June 30, 2013
	Magnum Hunter Resources Corporation			Guarantor Subsidiaries			Non Guarantor Subsidiaries			Eliminations			Magnum Hunter Resources Corporation Consolidated
Revenues	$	(960	)	$	56,476		$	30,782		$	(2,258	)	$	84,040
Expenses	15,604			72,750			46,505			(2,258		)	132,601
Loss from continuing operations before equity in net income of subsidiary	(16,564		)	(16,274		)	(15,723		)	—			(48,561		)
Equity in net income of subsidiary	(29,192		)	(113		)	(1,582		)	30,887			—
Income (loss) from continuing operations before income taxes	(45,756		)	(16,387		)	(17,305		)	30,887			(48,561		)
Income tax benefit	41,945			913			708			—			43,566
Income (loss) from continuing operations, net of tax	(3,811		)	(15,474		)	(16,597		)	30,887			(4,995		)
Income from discontinued operations, net of tax	(8,453		)	—			6,050			—			(2,403		)
Gain on sale of discontinued operations, net of tax	172,452			—			—			—			172,452
Net income (loss)	160,188			(15,474		)	(10,547		)	30,887			165,054
Net loss attributable to non-controlling interest	—			—			—			386			386
Net income (loss) attributable to Magnum Hunter Resources Corporation	160,188			(15,474		)	(10,547		)	31,273			165,440
Dividends on preferred stock	(8,877		)	—			(5,252		)	—			(14,129		)
Net income (loss) attributable to common shareholders	$	151,311		$	(15,474	)	$	(15,799	)	$	31,273		$	151,311
	Three Months Ended June 30, 2012
	Magnum Hunter Resources Corporation			Guarantor Subsidiaries			Non Guarantor Subsidiaries			Eliminations			Magnum Hunter Resources Corporation Consolidated
Revenues	$	252		$	26,742		$	15,898		$	(434	)	$	42,458
Expenses	7,168			35,276			24,177			(434		)	66,187
Loss from continuing operations before equity in net income of subsidiary	(6,916		)	(8,534		)	(8,279		)	—			(23,729		)
Equity in net income of subsidiary	(8,963		)	—			(3,607		)	12,570			—
Income (loss) from continuing operations before income taxes	(15,879		)	(8,534		)	(11,886		)	12,570			(23,729		)
Income tax benefit	—			2,206			4,652			—			6,858
Income (loss) from continuing operations, net of tax	(15,879		)	(6,328		)	(7,234		)	12,570			(16,871		)
Income from discontinued operations, net of tax	—			—			2,416			—			2,416
Gain on sale of discontinued operations, net of tax	—			—			—			—			—
Net income (loss)	(15,879		)	(6,328		)	(4,818		)	12,570			(14,455		)
Net loss attributable to non-controlling interest	—			—			—			(48		)	(48		)
Net income (loss) attributable to Magnum Hunter Resources Corporation	(15,879		)	(6,328		)	(4,818		)	12,522			(14,503		)
Dividends on preferred stock	(4,937		)	—			(3,268		)	—			(8,205		)
Net income (loss) attributable to common shareholders	$	(20,816	)	$	(6,328	)	$	(8,086	)	$	12,522		$	(22,708	)

F-35

Magnum Hunter Resources Corporation and Subsidiaries Condensed Consolidating Statements of Operations

(in thousands)



	Six Months Ended June 30, 2013
	Magnum Hunter Resources Corporation			Guarantor Subsidiaries			Non Guarantor Subsidiaries			Eliminations			Magnum Hunter Resources Corporation Consolidated
Revenues	$	(1,134	)	$	93,696		$	67,357		$	(3,702	)	$	156,217
Expenses	55,237			133,777			85,631			(3,702		)	270,943
Loss from continuing operations before equity in net income of subsidiary	(56,371		)	(40,081		)	(18,274		)	—			(114,726		)
Equity in net income of subsidiary	(38,163		)	(642		)	(9,387		)	48,192			—
Income (loss) from continuing operations before income taxes	(94,534		)	(40,723		)	(27,661		)	48,192			(114,726		)
Income tax benefit	41,945			5,767			708			—			48,420
Income (loss) from continuing operations, net of tax	(52,589		)	(34,956		)	(26,953		)	48,192			(66,306		)
Income from discontinued operations, net of tax	(8,453		)	—			22,661			—			14,208
Gain on sale of discontinued operations, net of tax	172,452			—			—			—			172,452
Net income (loss)	111,410			(34,956		)	(4,292		)	48,192			120,354
Net loss attributable to non-controlling interest	—			—			—			889			889
Net income (loss) attributable to Magnum Hunter Resources Corporation	111,410			(34,956		)	(4,292		)	49,081			121,243
Dividends on preferred stock	(17,783		)	—			(9,834		)	—			(27,617		)
Net income (loss) attributable to common shareholders	$	93,627		$	(34,956	)	$	(14,126	)	$	49,081		$	93,626
	Six Months Ended June 30, 2012
	Magnum Hunter Resources Corporation			Guarantor Subsidiaries			Non Guarantor Subsidiaries			Eliminations			Magnum Hunter Resources Corporation Consolidated
Revenues	$	461		$	52,889		$	33,082		$	(1,645	)	$	84,787
Expenses	23,943			70,232			36,161			(1,645		)	128,691
Income (loss) from continuing operations before equity in net income of subsidiary	(23,482		)	(17,343		)	(3,079		)	—			(43,904		)
Equity in net income of subsidiary	(5,028		)	—			(5,882		)	10,910			—
Income (loss) from continuing operations before income taxes	(28,510		)	(17,343		)	(8,961		)	10,910			(43,904		)
Income tax benefit (expense)	—			5,080			4,070			—			9,150
Income (loss) from continuing operations, net of tax	(28,510		)	(12,263		)	(4,891		)	10,910			(34,754		)
Income from discontinued operations, net of tax	—			—			7,517			—			7,517
Gain on sale of discontinued operations, net of tax	—			2,224			—			—			2,224
Net income (loss)	(28,510		)	(10,039		)	2,626			10,910			(25,013		)
Net loss attributable to non-controlling interest	—			—			—			(22		)	(22		)
Net income (loss) attributable to Magnum Hunter Resources Corporation	(28,510		)	(10,039		)	2,626			10,888			(25,035		)
Dividends on preferred stock	(9,384		)	—			(3,476		)	—			(12,860		)
Net income (loss) attributable to common shareholders	$	(37,894	)	$	(10,039	)	$	(850	)	$	10,888		$	(37,895	)

F-36

Magnum Hunter Resources Corporation and Subsidiaries

Condensed Consolidating Statements of Comprehensive Income (Loss)

(in thousands)



	Three Months Ended June 30, 2013
	Magnum Hunter Resources Corporation		Guarantor Subsidiaries			Non Guarantor Subsidiaries			Eliminations		Magnum Hunter Resources Corporation Consolidated
Net income (loss)	$	160,188	$	(15,474	)	$	(10,547	)	$	30,887	$	165,054
Foreign currency translation loss	—		—			(7,070		)	—		(7,070		)
Unrealized gain (loss) on available for sale securities	4,700		(234		)	—			—		4,466
Comprehensive income (loss)	164,888		(15,708		)	(17,617		)	30,887		162,450
Comprehensive income (loss) attributable to non-controlling interest	—		—			—			386		386
Comprehensive income (loss) attributable to Magnum Hunter Resources Corporation	$	164,888	$	(15,708	)	$	(17,617	)	$	31,273	162,836



	Three Months Ended June 30, 2012
	Magnum Hunter Resources Corporation			Guarantor Subsidiaries			Non Guarantor Subsidiaries			Eliminations			Magnum Hunter Resources Corporation Consolidated
Net income (loss)	$	(15,879	)	$	(6,328	)	$	(4,818	)	$	12,570		$	(14,455	)
Foreign currency translation loss	—			—			(4,119		)	—			(4,119		)
Unrealized gain (loss) on available for sale securities	—			(188		)	—			—			(188		)
Comprehensive income (loss)	(15,879		)	(6,516		)	(8,937		)	12,570			(18,762		)
Comprehensive income (loss) attributable to non-controlling interest	—			—			—			(48		)	(48		)
Comprehensive income (loss) attributable to Magnum Hunter Resources Corporation	$	(15,879	)	(6,516		)	(8,937		)	12,522			$	(18,810	)

F-37

Magnum Hunter Resources Corporation and Subsidiaries

Condensed Consolidating Statements of Comprehensive Income (Loss)

(in thousands)



	Six Months Ended June 30, 2013
	Magnum Hunter Resources Corporation		Guarantor Subsidiaries			Non Guarantor Subsidiaries			Eliminations		Magnum Hunter Resources Corporation Consolidated
Net income (loss)	$	111,410	$	(34,956	)	$	(4,292	)	$	48,192	$	120,354
Foreign currency translation loss	—		—			(11,799		)	—		(11,799		)
Unrealized gain (loss) on available for sale securities	4,700		(251		)	—			—		4,449
Comprehensive income (loss)	116,110		(35,207		)	(16,091		)	48,192		113,004
Comprehensive income (loss) attributable to non-controlling interest	—		—			—			889		889
Comprehensive income (loss) attributable to Magnum Hunter Resources Corporation	$	116,110	$	(35,207	)	$	(16,091	)	$	49,081	$	113,893



	Six Months Ended June 30, 2012
	Magnum Hunter Resources Corporation			Guarantor Subsidiaries			Non Guarantor Subsidiaries			Eliminations			Magnum Hunter Resources Corporation Consolidated
Net income (loss)	$	(28,510	)	$	(10,039	)	$	2,626		$	10,910		$	(25,013	)
Foreign currency translation loss	—			—			(617		)	—			(617		)
Unrealized gain (loss) on available for sale securities	—			(265		)	—			—			(265		)
Comprehensive income (loss)	(28,510		)	(10,304		)	2,009			10,910			(25,895		)
Comprehensive income (loss) attributable to non-controlling interest	—			—			—			(22		)	(22		)
Comprehensive income (loss) attributable to Magnum Hunter Resources Corporation	$	(28,510	)	$	(10,304	)	$	2,009		$	10,888		$	(25,917	)

F-38

Magnum Hunter Resources Corporation and Subsidiaries Condensed Consolidating Statements of Cash Flows

(in thousands)



	Six Months Ended June 30, 2013
	Magnum Hunter Resources Corporation			Guarantor Subsidiaries			Non Guarantor Subsidiaries			Eliminations		Magnum Hunter Resources Corporation Consolidated
Cash flow from operating activities	$	(156,721	)	$	135,532		$	95,057		$	—	$	73,868
Cash flow from investing activities	371,970			(137,404		)	(130,368		)	—		104,198
Cash flow from financing activities	(224,493		)	(40		)	21,943			—		(202,590		)

Effect of exchange rate changes on cash	—			—			(357		)	—		(357		)
Net increase (decrease) in cash	(9,244		)	(1,912		)	(13,725		)	—		(24,881		)
Cash at beginning of period	26,872			(4,462		)	35,213			—		57,623

Cash at end of period	$	17,628		$	(6,374	)	$	21,488		$	—	$	32,742



	Six Months Ended June 30, 2012
	Magnum Hunter Resources Corporation			Guarantor Subsidiaries			Non Guarantor Subsidiaries			Eliminations		Magnum Hunter Resources Corporation Consolidated
Cash flow from operating activities	$	(478,862	)	$	469,230		$	58,797		$	—	$	49,165
Cash flow from investing activities	(361		)	(465,767		)	(192,592		)	—		(658,720		)
Cash flow from financing activities	475,668			(1,864		)	145,695			—		619,499

Effect of exchange rate changes on cash	—			—			(33		)	—		(33		)
Net increase (decrease) in cash	(3,555		)	1,599			11,867			—		9,911
Cash at beginning of period	18,758			(445		)	(3,462		)	—		14,851

Cash at end of period	$	15,203		$	1,154		$	8,405		$	—	$	24,762

F-39

Senior Notes

Certain of the Company’s subsidiaries, including Alpha Hunter Drilling, LLC, Bakken Hunter, LLC, Eagle Ford Hunter (up to April 24, 2013, when it was sold to Penn Virginia), 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, Williston Hunter, Inc., Williston Hunter ND, LLC, and Virco, (collectively, "Guarantor Subsidiaries"), have guaranteed, on a joint and several, and 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 June 30, 2013 and December 31, 2012, and for the three and six months ended June 30, 2013 and 2012, are as follows:

Magnum Hunter Resources Corporation and Subsidiaries

Condensed Consolidating Balance Sheets

(in thousands)



	As of June 30, 2013
	Magnum Hunter Resources Corporation		PRC Williston, LLC			Wholly-Owned Guarantor Subsidiaries		Non Guarantor Subsidiaries		Eliminations			Magnum Hunter Resources Corporation Consolidated
ASSETS
Current assets	$	70,615	$	1,200		$	78,806	$	31,283	$	(8,004	)	$	173,900
Intercompany accounts receivable	756,306		—			—		—		(756,306		)	—
Property and equipment (using successful efforts method of accounting)	7,476		16,569			1,354,529		419,166		—			1,797,740
Investment in subsidiaries	681,755		—			102,097		92,967		(876,819		)	—
Other assets	20,378		—			1,906		41,996		—			64,280
Total Assets	$	1,536,530	$	17,769		$	1,537,338	$	585,412	$	(1,641,129	)	$	2,035,920

LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities	$	28,161	$	2,814		$	133,067	$	19,019	$	(8,043	)	$	175,018
Intercompany accounts payable	—		59,872			630,633		65,765		(756,270		)	—
Long-term liabilities	602,089		1,338			96,743		123,931		—			824,101
Redeemable preferred stock	100,000		—			—		121,271		—			221,271
Shareholders' equity (deficit)	806,280		(46,255		)	676,895		255,426		(876,816		)	815,530
Total Liabilities and Shareholders' Equity	$	1,536,530	$	17,769		$	1,537,338	$	585,412	$	(1,641,129	)	$	2,035,920

F-40

Magnum Hunter Resources Corporation and Subsidiaries

Condensed Consolidating Balance Sheets

(in thousands)



	As of December 31, 2012
	Magnum Hunter Resources Corporation		PRC Williston, LLC			Wholly-Owned Guarantor Subsidiaries		Non Guarantor Subsidiaries		Eliminations			Magnum Hunter Resources Corporation Consolidated
ASSETS
Current assets	$	63,167	$	703		$	60,552	$	111,126	$	(31,229	)	$	204,319
Intercompany accounts receivable	803,834		—			—		—		(803,834		)	—
Property and equipment (using successful efforts method of accounting)	9,596		18,257			1,276,467		620,093		—			1,924,413
Investment in subsidiaries	763,856		—			101,341		102,354		(967,551		)	—
Other assets	20,849		—			5,451		43,600		—			69,900
Total Assets	$	1,661,302	$	18,960		$	1,443,811	$	877,173	$	(1,802,614	)	$	2,198,632

LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities	$	28,503	$	2,291		$	117,511	$	125,727	$	(30,376	)	$	243,656
Intercompany accounts payable	—		58,966			508,254		236,636		(803,856		)	—
Long-term liabilities	831,286		1,274			97,271		112,615		—			1,042,446
Redeemable preferred stock	100,000		—			—		100,878		—			200,878
Shareholders' equity (deficit)	701,513		(43,571		)	720,775		301,317		(968,382		)	711,652
Total Liabilities and Shareholders' Equity	$	1,661,302	$	18,960		$	1,443,811	$	877,173	$	(1,802,614	)	$	2,198,632

F-41

Magnum Hunter Resources Corporation and Subsidiaries

Condensed Consolidating Statements of Operations

(in thousands)



	Three Months Ended June 30, 2013
	Magnum Hunter Resources Corporation			PRC Williston, LLC			Wholly-Owned Guarantor Subsidiaries			Non Guarantor Subsidiaries			Eliminations			Magnum Hunter Resources Corporation Consolidated
Revenues	$	(960	)	$	1,687		$	70,634		$	14,937		$	(2,258	)	$	84,040
Expenses	15,604			4,028			89,439			25,788			(2,258		)	132,601
Loss from continuing operations before equity in net income of subsidiaries	(16,564		)	(2,341		)	(18,805		)	(10,851		)	—			(48,561		)
Equity in net income of subsidiaries	(29,192		)	—			(113		)	(1,582		)	30,887			—
Loss from continuing operations before income tax	(45,756		)	(2,341		)	(18,918		)	(12,433		)	30,887			(48,561		)
Income tax benefit	41,945			—			913			708			—			43,566
Loss from continuing operations	(3,811		)	(2,341		)	(18,005		)	(11,725		)	30,887			(4,995		)
Income from discontinued operations, net of tax	(8,453		)	—			—			6,050			—			(2,403		)
Gain on sale of discontinued operations, net of tax	172,452			—			—			—			—			172,452
Net income (loss)	160,188			(2,341		)	(18,005		)	(5,675		)	30,887			165,054
Net loss attributable to non-controlling interest	—			—			—			—			386			386
Net loss attributable to Magnum Hunter Resources Corporation	160,188			(2,341		)	(18,005		)	(5,675		)	31,273			165,440
Dividends on preferred stock	(8,877		)	—			—			(5,252		)	—			(14,129		)
Net income (loss) attributable to common shareholders	$	151,311		$	(2,341	)	$	(18,005	)	$	(10,927	)	$	31,273		$	151,311
	Three Months Ended June 30, 2012
	Magnum Hunter Resources Corporation			PRC Williston, Inc.			Wholly-Owned Guarantor Subsidiaries			Non Guarantor Subsidiaries			Eliminations			Magnum Hunter Resources Corporation Consolidated
Revenues	$	252		$	2,102		$	28,865		$	11,673		$	(434	)	$	42,458
Expenses	7,168			1,723			37,613			20,117			(434		)	66,187
Income (loss) from continuing operations before equity in net income of subsidiaries	(6,916		)	379			(8,748		)	(8,444		)	—			(23,729		)
Equity in net income of subsidiaries	(8,963		)	—			—			(3,607		)	12,570			—
Income (loss) from continuing operations before income tax	(15,879		)	379			(8,748		)	(12,051		)	12,570			(23,729		)
Income tax benefit	—			—			2,206			4,652			—			6,858
Income (loss) from continuing operations	(15,879		)	379			(6,542		)	(7,399		)	12,570			(16,871		)
Income from discontinued operations, net of tax	—			—			—			2,416			—			2,416
Gain on sale of discontinued operations, net of tax	—			—			—			—			—			—
Net income (loss)	(15,879		)	379			(6,542		)	(4,983		)	12,570			(14,455		)
Net loss attributable to non-controlling interest	—			—			—			—			(48		)	(48		)
Net income (loss) attributable to Magnum Hunter Resources Corporation	(15,879		)	379			(6,542		)	(4,983		)	12,522			(14,503		)
Dividends on preferred stock	(4,937		)	—			—			(3,268		)	—			(8,205		)
Net income (loss) attributable to common shareholders	$	(20,816	)	$	379		$	(6,542	)	$	(8,251	)	$	12,522		$	(22,708	)

F-42

Magnum Hunter Resources Corporation and Subsidiaries

Condensed Consolidating Statements of Operations

(in thousands)



	Six Months Ended June 30, 2013
	Magnum Hunter Resources Corporation			PRC Williston, Inc.			Wholly-Owned Guarantor Subsidiaries			Non Guarantor Subsidiaries			Eliminations			Magnum Hunter Resources Corporation Consolidated
Revenues	$	(1,134	)	$	3,295		$	123,162		$	34,596		$	(3,702	)	$	156,217
Expenses	55,237			5,981			166,453			46,974			(3,702		)	270,943
Loss from continuing operations before equity in net income of subsidiaries	(56,371		)	(2,686		)	(43,291		)	(12,378		)	—			(114,726		)
Equity in net income of subsidiaries	(38,163		)	—			(642		)	(9,387		)	48,192			—
Loss from continuing operations before income tax	(94,534		)	(2,686		)	(43,933		)	(21,765		)	48,192			(114,726		)
Income tax benefit	41,945			—			5,767			708			—			48,420
Loss from continuing operations	(52,589		)	(2,686		)	(38,166		)	(21,057		)	48,192			(66,306		)
Income from discontinued operations, net of tax	(8,453		)	—			—			22,661			—			14,208
Gain on sale of discontinued operations, net of tax	172,452			—			—			—			—			172,452
Net income (loss)	111,410			(2,686		)	(38,166		)	1,604			48,192			120,354
Net income attributable to non-controlling interest	—						—			—			889			889
Net loss attributable to Magnum Hunter Resources Corporation	111,410			(2,686		)	(38,166		)	1,604			49,081			121,243
Dividends on preferred stock	(17,783		)	—			—			(9,834		)	—			(27,617		)
Net income (loss) attributable to common shareholders	$	93,627		$	(2,686	)	$	(38,166	)	$	(8,230	)	$	49,081		$	93,626
	Six Months Ended June 30, 2012
	Magnum Hunter Resources Corporation			PRC Williston, Inc.			Wholly-Owned Guarantor Subsidiaries			Non Guarantor Subsidiaries			Eliminations			Magnum Hunter Resources Corporation Consolidated
Revenues	$	461		$	4,189		$	59,606		$	22,176		$	(1,645	)	$	84,787
Expenses	23,943			4,015			75,251			27,127			(1,645		)	128,691
Income (loss) from continuing operations before equity in net income of subsidiaries	(23,482		)	174			(15,645		)	(4,951		)	—			(43,904		)
Equity in net income of subsidiaries	(5,028		)	—			—			(5,882		)	10,910			—
Income (loss) from continuing operations before income tax	(28,510		)	174			(15,645		)	(10,833		)	10,910			(43,904		)
Income tax benefit	—			—			5,080			4,070			—			9,150
Income (loss) from continuing operations	(28,510		)	174			(10,565		)	(6,763		)	10,910			(34,754		)
Income from discontinued operations, net of tax	—			—			—			7,517			—			7,517
Gain on sale of discontinued operations, net of tax	—			—			2,224			—			—			2,224
Net income (loss)	(28,510		)	174			(8,341		)	754			10,910			(25,013		)
Net loss attributable to non-controlling interest	—			—			—			—			(22		)	(22		)
Net income (loss) attributable to Magnum Hunter Resources Corporation	(28,510		)	174			(8,341		)	754			10,888			(25,035		)
Dividends on preferred stock	(9,384		)	—			—			(3,476		)	—			(12,860		)
Net income (loss) attributable to common shareholders	$	(37,894	)	$	174		$	(8,341	)	$	(2,722	)	$	10,888		$	(37,895	)

F-43

Magnum Hunter Resources Corporation and Subsidiaries

Condensed Consolidating Statements of Comprehensive Income (Loss)

(in thousands)



	Three Months Ended June 30, 2013
	Magnum Hunter Resources Corporation		PRC Williston, LLC			Wholly-Owned Guarantor Subsidiaries			Non Guarantor Subsidiaries			Eliminations		Magnum Hunter Resources Corporation Consolidated
Net income (loss)	$	160,188	$	(2,341	)	$	(18,005	)	$	(5,675	)	$	30,887	165,054
Foreign currency translation loss	—		—			—			(7,070		)	—		(7,070	)
Unrealized gain (loss) on available for sale securities	4,700		—			(234		)	—			—		4,466
Comprehensive income (loss)	164,888		(2,341		)	(18,239		)	(12,745		)	30,887		162,450
Comprehensive income (loss) attributable to non-controlling interest	—		—			—			—			386		386
Comprehensive income (loss) attributable to Magnum Hunter Resources Corporation	$	164,888	$	(2,341	)	$	(18,239	)	$	(12,745	)	$	31,273	162,836



	Three Months Ended June 30, 2012
	Magnum Hunter Resources Corporation			PRC Williston, LLC		Wholly-Owned Guarantor Subsidiaries			Non Guarantor Subsidiaries			Eliminations			Magnum Hunter Resources Corporation Consolidated
Net income (loss)	$	(15,879	)	$	379	$	(6,542	)	$	(4,983	)	$	12,570		(14,455	)
Foreign currency translation loss	—			—		—			(4,119		)	—			(4,119	)
Unrealized gain (loss) on available for sale securities	—			—		(188		)	—			—			(188	)
Comprehensive income (loss)	(15,879		)	379		(6,730		)	(9,102		)	12,570			(18,762	)
Comprehensive income (loss) attributable to non-controlling interest	—			—		—			—			(48		)	(48	)
Comprehensive income (loss) attributable to Magnum Hunter Resources Corporation	$	(15,879	)	379		(6,730		)	(9,102		)	12,522			(18,810	)

F-44

Magnum Hunter Resources Corporation and Subsidiaries

Condensed Consolidating Statements of Comprehensive Income (Loss)

(in thousands)



	Six Months Ended June 30, 2013
	Magnum Hunter Resources Corporation		PRC Williston, LLC			Wholly-Owned Guarantor Subsidiaries			Non Guarantor Subsidiaries			Eliminations		Magnum Hunter Resources Corporation Consolidated
Net income (loss)	$	111,410	$	(2,686	)	$	(38,166	)	$	1,604		$	48,192	$	120,354
Foreign currency translation loss	—		—			—			(11,799		)	—		(11,799		)
Unrealized gain (loss) on available for sale securities	4,700		—			(251		)	—			—		4,449
Comprehensive income (loss)	116,110		(2,686		)	(38,417		)	(10,195		)	48,192		113,004
Comprehensive income (loss) attributable to non-controlling interest	—		—			—			—			889		889
Comprehensive income (loss) attributable to Magnum Hunter Resources Corporation	$	116,110	$	(2,686	)	$	(38,417	)	$	(10,195	)	$	49,081	$	113,893



	Six Months Ended June 30, 2012
	Magnum Hunter Resources Corporation			PRC Williston, LLC		Wholly-Owned Guarantor Subsidiaries			Non Guarantor Subsidiaries			Eliminations			Magnum Hunter Resources Corporation Consolidated
Net income (loss)	$	(28,510	)	$	174	$	(8,341	)	$	754		$	10,910		$	(25,013	)
Foreign currency translation loss	—			—		—			(617		)	—			(617		)
Unrealized gain (loss) on available for sale securities	—			—		(265		)	—			—			(265		)
Comprehensive income (loss)	(28,510		)	174		(8,606		)	137			10,910			(25,895		)
Comprehensive income (loss) attributable to non-controlling interest	—			—		—			—			(22		)	(22		)
Comprehensive income (loss) attributable to Magnum Hunter Resources Corporation	$	(28,510	)	$	174	$	(8,606	)	$	137		$	10,888		$	(25,917	)

F-45

Magnum Hunter Resources Corporation and Subsidiaries

Condensed Consolidating Statements of Cash Flows

(in thousands)



	Six Months Ended June 30, 2013
	Magnum Hunter Resources Corporation			PRC Williston, LLC			Wholly-Owned Guarantor Subsidiaries			Non Guarantor Subsidiaries			Eliminations		Magnum Hunter Resources Corporation Consolidated
Cash flow from operating activities	$	(156,721	)	$	(134	)	$	146,932		$	83,791		$	—	$	73,868
Cash flow from investing activities	371,970			184			(152,127		)	(115,829		)	—		104,198
Cash flow from financing activities	(224,493		)	—			4,051			17,852			—		(202,590		)

Effect of exchange rate changes on cash	—			—			—			(357		)	—		(357		)
Net increase (decrease) in cash	(9,244		)	50			(1,144		)	(14,543		)	—		(24,881		)
Cash at beginning of period	26,872			—			(4,187		)	34,938			—		57,623

Cash at end of period	$	17,628		$	50		$	(5,331	)	$	20,395		$	—	$	32,742



	Six Months Ended June 30, 2012
	Magnum Hunter Resources Corporation			PRC Williston, LLC			Wholly-Owned Guarantor Subsidiaries			Non Guarantor Subsidiaries			Eliminations		Magnum Hunter Resources Corporation Consolidated
Cash flow from operating activities	$	(478,862	)	$	48		$	470,683		$	57,296		$	—	$	49,165
Cash flow from investing activities	(361		)	(48		)	(467,835		)	(190,476		)	—		(658,720		)
Cash flow from financing activities	475,668			—			(1,628		)	145,459			—		619,499

Effect of exchange rate changes on cash	—			—			—			(33		)	—		(33		)
Net increase (decrease) in cash	(3,555		)	—			1,220			12,246			—		9,911
Cash at beginning of period	18,758			—			(546		)	(3,361		)	—		14,851

Cash at end of period	$	15,203		$	—		$	674		$	8,885		$	—	$	24,762

F-46

NOTE 17 — SUBSEQUENT EVENTS

Filing of Quarterly Report on Form 10-Q

On July 9, 2013, we filed with the SEC our quarterly report on Form 10-Q for the quarterly period ended March 31, 2013.

Issuance of Series A Preferred Units of Eureka Hunter Holdings

On July 25, 2013, Eureka Hunter Holdings issued 88,901 of Series A Preferred Units with a redemption value of $1.8 million for dividends paid-in-kind. The balance of the dividend payable for the quarter ended June 30, 2013 of $1.8 million was paid in cash on July 30, 2013.

The Series A Preferred Units outstanding at August 9, 2013 represent 39.9% of the ownership of Eureka Hunter Holdings on a basis as converted to Class A Common Units of Eureka Hunter Holdings.

Declared Accumulated Dividend

On July 29, 2013, the Company announced that it had declared cash dividends on the Company's Series C Preferred Stock, Series D Preferred Stock, and Series E Preferred Stock, for the months of April, May, June, July and August 2013, referred to as the "Declared Accumulated Dividend." The Declared Accumulated Dividend is payable on September 3, 2013, to holders of record at the close of business on August 15, 2013.

Eighteenth Amendment to Second Amended and Restated Credit Agreement

(i) While the total debt to EBITDAX covenant is deferred as described in (ii) below, implement a new total senior debt to EBITDAX covenant set at 2.00x EBITDAX;

(iv) allow for up to $32 million in investments in the Company's unrestricted subsidiary Eureka Hunter Holdings, LLC provided a) the investments are made before December 31, 2013 and b) the borrowing base has availability of at least $75.0 million at the time of such investment, provided that the Company may also invest in Eureka Hunter Holdings using proceeds from the sale of its common or preferred equity (these proceeds should be utilized to further expand Eureka Hunter Pipeline);

(v) reduces the Company's Senior Note basket to $600 million from $800 million;

F-47

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

PRC WILLISTON, LLC

BALANCE SHEETS

(In thousands)



	June 30,			December 31,
	2013			2012
	(unaudited)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	50		$	—
Accounts receivable	889			703
Inventory	261			—
Total current assets	1,200			703

PROPERTY AND EQUIPMENT:
Oil and natural gas properties, successful efforts method	32,820			33,800
Accumulated depletion, depreciation, and accretion	(16,251		)	(15,543		)
Total oil and natural gas properties, net	16,569			18,257
Total Assets	$	17,769		$	18,960

LIABILITIES AND MEMBER’S DEFICIT
CURRENT LIABILITIES:
Accounts payable and accrued liabilities	$	1,879		$	1,402
Current portion of asset retirement obligation	936			889
Accounts payable due to Parent	59,871			58,966
Total current liabilities	62,686			61,257
Asset retirement obligation	1,338			1,274
Total liabilities	64,024			62,531

MEMBER’S DEFICIT:	(46,255		)	(43,571		)
Total Liabilities and Member’s Deficit	$	17,769		$	18,960

F-48

PRC WILLISTON, LLC

UNAUDITED STATEMENTS OF OPERATIONS

(In thousands)



	Three Months Ended June 30,						Six Months Ended June 30,
	2013			2012			2013			2012
REVENUE:
Oil and gas sales	$	1,687		$	2,102		$	3,296		$	4,189
Total revenue	1,687			2,102			3,296			4,189

EXPENSES:
Lease operating	1,503			1,038			2,169			2,598
Severance taxes and marketing	101			77			201			187
Impairment of proved oil and gas property	1,231			—			1,231			—
Depreciation, depletion, and accretion	381			608			769			1,229
General and administrative	197			299			514			598
Total expenses	3,413			2,022			4,884			4,612

OPERATING INCOME (LOSS):	(1,726		)	80			(1,588		)	(423		)

INTEREST EXPENSE:	(615		)	(481		)	(1,096		)	(962		)

Net loss	$	(2,341	)	$	(401	)	$	(2,684	)	$	(1,385	)

F-49

PRC WILLISTON, LLC

UNAUDITED STATEMENT OF CHANGES IN MEMBER’S DEFICIT

(In thousands)



Balance, January 1, 2013	$	(43,571	)
Net loss	(2,684		)
Balance, June 30, 2013	$	(46,255	)

F-50

PRC WILLISTON, LLC

UNAUDITED STATEMENTS OF CASH FLOWS

(In thousands)



	Six Months Ended June 30,
	2013			2012
Cash flows from operating activities
Net loss	$	(2,684	)	$	(1,385	)
Adjustments to reconcile net loss to net cash used in operating activities:
Depletion, depreciation, and accretion	769			1,229
Asset impairment	1,231			—
Changes in operating assets and liabilities:
Accounts receivable	(184		)	1,366
Inventory	(261		)	—
Accounts payable and accrued liabilities	273			1,069
Accounts payable - Intercompany	906			(2,231		)
Net cash (used in) provided by operating activities:	50			48

Cash flows from investing activities
Capital expenditures	—			(48		)
Net cash provided by (used in) investing activities	—			(48		)

Cash flows from financing activities
(Repayments to) Advances from parent	—			—
Net cash (used in)provided by financing activities	—			—

Net change in cash and cash equivalents	50			—
Cash and cash equivalents, beginning of period	—			—
Cash and cash equivalents, end of period	50			—

Cash paid for interest	$	—		$	—

Non-cash transactions
Change in accrued capital expenditures	$	389		$	—
Non-cash additions to asset retirement obligation	$	48		$	—

F-51

PRC WILLISTON, LLC

NOTES TO FINANCIAL STATEMENTS

(Unaudited)

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 may have a material impact on the carrying value of oil and gas property.

Notes to the financial statements that would substantially duplicate the disclosure contained in the audited consolidated financial statements as reported in the 2012 annual report on Form 10-K for Magnum Hunter have been omitted.

Oil and Gas Properties

Capitalized Costs

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 June 30, 2013 or 2012. 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.

F-52

of the related future net cash flows. We recorded $1.2 million impairment charges to our proved properties during the three and six months ended June 30, 2013 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 no impairment charges to unproved properties during the six months ended June 30, 2013 or 2012.

Inventory

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. 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 $261,000 and $0 in commodities inventory as of June 30, 2013 and December 31, 2012 respectively.

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 June 30, 2013 or 2012. At June 30, 2013, and 2012, 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 six months ended June 30, 2013:



	Six Months Ended June 30, 2013
	(in thousands)
Asset retirement obligation at beginning of period	$	2,163
Accretion expense	62
Revisions in estimated liabilities	49
Asset retirement obligation at end of period	2,274
Less: current portion	(936		)
Asset retirement obligation at end of period	$	1,338

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 based on the amount funded to the Company multiplied by the interest rate applicable to the MHR Senior Revolving Credit Facility. 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.

F-53

The following table sets forth the Company’s related-party expenses during the three and six month periods ended June 30, 2013 and 2012:



	Three Months Ended		Six Months Ended
	June 30,		June 30,
	2013	2012	2013	2012
Interest expense	615,000	481,000	1,096,000	962,000
General and administrative	197,000	299,000	514,000	598,000

Accumulated interest and general and administrative expense allocated to PRC Williston are included in accounts payable due to Parent. At June 30, 2013, the balance due to Magnum Hunter was $59.9 million, and $59.0 million at December 31, 2012.

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 May 15, 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 , 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 June 30, 2013 and 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 guarantors. As such, the Company cannot estimate any potential loss as a result of the guarantee of indebtedness of the Parent. As of June 30, 2013, the Parent was in compliance with Senior Note debt covenants, as amended and waived, in the Magnum Hunter second quarter 2013 report on Form 10-Q, "Note 9 - Long Term Debt".

F-54

F-55

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 the 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.

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, except for Notes 3, 7, 14, 15, 16 and 19 which are as of August 30, 2013

F-56

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, “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.

As indicated in the accompanying “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 control 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, except for Notes 3, 7, 14, 15, 16, and 19 which are as of August 30, 2013, on those consolidated financial statements.

F-57

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, except for Notes 3, 7, 14, 15, 16, and 19 which are as of August 30, 2013, expressed an unqualified opinion thereon.

/s/ BDO USA, LLP

Dallas, Texas

June 14, 2013

F-58

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, shareholders' equity, and cash flows for each of the years ended December 31, 2011 and 2010. 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.

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.

Hein & Associates LLP

Dallas, Texas

February 29, 2012, except for Note 19 and Note 7 as to which the dates are January 11, 2013 and August 30, 2013, respectively

F-59

Table of Contents

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-60

Table of Contents

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-61

Table of Contents

MAGNUM HUNTER RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except share and per share data)



	Year Ended December 31,
	2012			2011			2010
	Revised (Note 3)
REVENUE:
Oil and gas sales	$	173,283		$	85,966		$	26,974
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	198,860			93,441			28,609
EXPENSES:
Lease operating expenses	45,684			25,456			10,678
Severance taxes and marketing	10,787			6,482			2,347
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	99,900			36,961			8,189
General and administrative	64,388			62,902			24,773
Total expenses	360,136			163,370			48,721

OPERATING LOSS	(161,276		)	(69,929		)	(20,112		)

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	(188,607		)	(86,631		)	(22,812		)
Income tax benefit	32,196			2,987			—
Loss from continuing operations	(156,411		)	(83,644		)	(22,812		)
Income from discontinued operations, net of tax	17,281			7,232			2,481
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	$	(1.20	)	$	(0.86	)	$	(0.39	)
Income from discontinued operations per share, basic and diluted	0.13			0.06			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	$	(152,398	)	$	(83,893	)	$	(22,941	)
Discontinued operations, net of tax	19,690			7,232			9,141
Net loss	$	(132,708	)	$	(76,661	)	$	(13,800	)

The accompanying Notes to Consolidated Financial Statements are an integral part of these Statements

F-62

Table of Contents

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-63

Table of Contents

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

The accompanying Notes to Consolidated Financial Statements are an integral part of these Statements

F-64

Table of Contents

MAGNUM HUNTER RESOURCES CORPORATION

CONSOLIDATED STATEMENT OF SHAREHOLDERS' EQUITY

(In thousands)



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

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Table of Contents

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

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Table of Contents

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 $161.3 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" to our consolidated financial statements), 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.

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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.

Revision to the Financial Statements

As discussed in Note 20, on April 24, 2013, the Company sold all of its ownership interest in its wholly owned subsidiary, Eagle Ford Hunter, Inc. Accordingly, certain balances in the consolidated financial statements and disclosures in footnotes 3,7,14,15, 16 and 19 have been revised for inclusion in the Company's Registration Statement under the Securities Act of 1933 as filed on form S-4 to which these financial statements are included. The operating results of Eagle Ford Hunter, Inc. ("Eagle Ford Hunter"), which has historically been included as part of the U.S. Upstream operating segment, have been reclassified as discontinued operations in the consolidated statements of operations for the years ended December 31, 2012, 2011, and 2010 as described in "Note 7 - Discontinued Operations".

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".

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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.

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".

Certain balances in the consolidated financial statements and disclosures in the footnotes have been revised as a result of the sale of Eagle Ford Hunter, LLC on April 24, 2013, for inclusion in the Company's Registration Statement under the Securities Act of 1933 as filed on form S-4 to which these financial statements are included. The operating results of Eagle Ford Hunter, Inc. ("Eagle Ford Hunter"), which has historically been included as part of the U.S. Upstream operating segment, have been reclassified as discontinued

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operations in the consolidated statements of operations for the years ended December 31, 2012, 2011, and 2010. See "Revision to the Financial Statements" above for additional information.

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 $87.7 million, $30.8 million, and $8.3 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.

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.

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.

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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.

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.

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.

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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 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 $7.6 million, $8.8 million, and $52,000, for the years ended December 31, 2012, 2011, and 2010, respectively.

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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.

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.

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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 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.

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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 $0.5 million 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

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 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.

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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



●	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.

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 our consolidated financial statements) 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	18,548		17,450		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, 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

F-79

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.

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

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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 $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

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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 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".

During 2010, the company sold non-operated working interest in the Cinco Terry property located in Crockett County, Texas which resulting in a gain of approximately $6.7 million on the disposal.

The operating results of Hunter Disposal, LLC and the Cinco Terry property have been reclassified as discontinued operations in the consolidated statements of operations for the years ended December 31, 2012, 2011, and 2010 as detailed in the table below:



	⁽¹⁾Year Ended December 31,
	2012			2011			2010
	(in thousands)
Revenues	$	2,400		$	13,047		$	6,486
Operating expenses	(2,047		)	(10,049		)	(3,687		)
Income tax expense and other	(123		)	(21		)	(449		)
Gain on sale of discontinued operations (net of tax of $1.3 million)	2,409			—			6,660
Income from discontinued operations, net of tax	$	2,639		$	2,977		$	9,010

⁽¹⁾ Year ended 2012 represents operations from January 1, 2012 through February 17, 2012, the date of sale.

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	Year Ended December 31,
	2012			2011			2010
	(in thousands)
Revenues	$	72,111		$	20,240		$	741
Operating expenses	(45,880		)	(13,694		)	(610		)
Income tax expense and other	(9,180		)	(2,291		)	—
Income from discontinued operations, net of tax	$	17,051		$	4,255		$	131

The condensed consolidating guarantor financial statements have also been revised to reflect Eagle Ford Hunter as a non-guarantor as the subsidiary was no longer a guarantor upon the closing of the sale on April 24,2013.

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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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.”

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

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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		Weighted-Average Exercise Price		Shares		Weighted-Average Exercise Price		Shares		Weighted-Average Exercise Price
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		Weighted-Average Exercise Price		Shares		Weighted-Average Exercise Price		Shares		Weighted-Average Exercise Price
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.

F-99

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

F-100

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	(23,452		)	(2,804		)	—
Various states	(517		)	(60		)	—
Canada and various provinces	(8,227		)	(123		)	—
Total deferred tax expense (benefit)	$	(32,196	)	$	(2,987	)	$	—
Total income tax expense (benefit)	$	(32,196	)	$	(2,987	)	$	—

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

F-103

through 2032. The Company has two (2) separate U.S. corporate filing entities. In addition, the Company files in various State taxing 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	24,770			27,221			5,134
Total continuing operations	(32,196		)	(2,987		)	0
Discontinued operations	10,601			2,291			—
Total tax expense (benefit)	$	(21,595	)	$	(696	)	$	0

F-104

Income (loss) before income taxes was as follows:



	Year Ended December 31,
	2012			2011			2010
	(in thousands)
Domestic	$	(155,367	)	$	(84,169	)	$	(22,812	)
Foreign	(33,240		)	(2,462		)	—
Income (loss) from continuing operations	(188,607		)	(86,631		)	(22,812		)
Income (loss) from discontinued operations	26,585			9,523			2,481
Gain on sale of discontinued operations	3,706			—			6,660
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-105

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. After giving effect to the Eagle Ford Properties sale, 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	21	%	6	%	—	%
Trafigura	22	%	12	%	—	%
DPI	9	%	15	%	—	%
Plains Marketing, LP	7	%	10	%	33	%
Clearfield Energy	5	%	10	%	23	%
Ergon Oil	4	%	8	%	19	%

F-106

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.



	Quarter Ended
	March 31,			June 30,			September 30,			December 31,			Year Ended
	2012
	(in thousands)
Total revenue	$	42,329		$	42,458		$	49,611		$	64,462		$	198,860
Loss from operations⁽¹⁾	(16,962		)	(23,394		)	(17,449		)	(103,471		)	(161,276		)
Income from discontinued operations, net of tax	5,101			2,416			4,908			4,856			17,281
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	$	11,884		$	23,709		$	24,271		$	33,577		$	93,441
Loss from operations	(2,973		)	(16,871		)	(16,657		)	(33,428		)	(69,929		)
Income from discontinued operations, net of tax	285			1,873			2,167			2,907			7,232
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	)	$	(0.01	)	$	(0.51	)	$	(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-107

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	$	133,727		$	39,556		$	—		$	—		$	—		$	—		$	173,283
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	134,090			39,521			15,942			12,952			—			(3,645		)	198,860
Lease operating expenses	44,111			5,163			—			—			—			(3,590		)	45,684
Severance taxes and marketing	8,416			2,371			—			—			—			—			10,787
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	65,041			27,461			5,963			967			—			468			99,900
General and administrative	30,680			2,043			3,798			418			27,137			312			64,388
Total expenses	232,462			74,136			17,669			11,805			27,137			(3,073		)	360,136
Operating income (loss)	(98,372		)	(34,615		)	(1,727		)	1,147			(27,137		)	(572		)	(161,276		)
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	(108,580		)	(33,241		)	5,661			665			(51,258		)	(1,854		)	(188,607		)
Income tax benefit	23,977			8,219			—			—			—			—			32,196
Loss from continuing operations	(84,603		)	(25,022		)	5,661			665			(51,258		)	(1,854		)	(156,411		)
Income from discontinued operations	17,051			—			—			230			—			—			17,281
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	$	75,235		$	10,731		$	—		$	—		$	—		$	—		$	85,966
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	74,509			10,767			2,491			9,426			—			(3,752		)	93,441
Lease operating expenses	25,839			1,813			—			—			—			(2,196		)	25,456
Severance taxes and marketing	5,894			588			—			—			—			—			6,482
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	28,573			6,055			1,789			544			—			—			36,961
General and administrative	8,883			1,914			850			461			50,794			—			62,902
Total expenses	93,586			10,410			3,012			9,320			50,794			(3,752		)	163,370
Operating income (loss)	(19,077		)	357			(521		)	106			(50,794		)	—			(69,929		)
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	(19,771		)	2,427			(2,195		)	(77		)	(67,015		)	—			(86,631		)
Income tax benefit	2,862			125			—			—			—			—			2,987
Loss from continuing operations	(16,909		)	2,552			(2,195		)	(77		)	(67,015		)	—			(83,644		)
Income from discontinued operations	4,255			—			—			2,977			—			—			7,232
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

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	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	$	26,974		$	—	$	—	$	—		$	—		$	—		$	26,974
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	27,142			—		414		3,390			—			(2,337		)	28,609
Lease operating expenses	10,868			—		—		—			—			(190		)	10,678
Severance taxes and marketing	2,347			—		—		—			—			—			2,347
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	7,780			—		45		364			—			—			8,189
General and administrative	1,724			—		71		143			22,835			—			24,773
Total expenses	23,967			—		330		3,926			22,835			(2,337		)	48,721
Operating income (loss)	3,175			—		84		(536		)	(22,835		)	—			(20,112		)
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 before income tax	3,175			—		84		(685		)	(25,386		)	—			(22,812		)
Income from discontinued operations	1,928			—		—		553			—			—			2,481
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

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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

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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.

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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

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.

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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

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upon the Company’s acquisition of certain of its assets. This includes units issued in accordance with the agreement of Eureka Hunter 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.

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

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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.

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.

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.

F-116

Eureka Hunter Holdings Operating Agreement

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-117

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	$	48,320	$	124,041	$	(31,209	)	$	204,319
Intercompany accounts receivable	803,834		—		—		(803,834		)	—
Property and equipment (using successful efforts accounting)	9,596		1,148,714		766,103		—			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	$	1,303,717	$	1,036,208	$	(1,802,595	)	$	2,198,632
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities	$	28,503	$	109,536	$	135,994	$	(30,377	)	$	243,656
Intercompany accounts payable	—		611,932		191,902		(803,834		)	—
Long-term liabilities	831,286		83,192		127,968		—			1,042,446
Redeemable preferred stock	100,000		—		100,878		—			200,878
Shareholders' equity	701,513		499,057		479,466		(968,384		)	711,652
Total Liabilities and Shareholders' Equity	$	1,661,302	$	1,303,717	$	1,036,208	$	(1,802,595	)	$	2,198,632

F-118

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	$	19,145	$	32,556	$	567		$	77,669
Intercompany accounts receivable	667,557		—		—		(667,557		)	—
Property and equipment (using successful efforts accounting)	13,287		627,544		434,303		—			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	$	711,913	$	599,880	$	(1,005,920	)	$	1,168,760
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities	$	21,112	$	81,927	$	64,056	$	580		$	167,675
Intercompany accounts payable	—		232,534		435,023		(667,557		)	—
Long-term liabilities	253,319		93,426		63,688		—			410,433
Redeemable preferred stock	100,000		—		—		—			100,000
Shareholders' equity ⁽¹⁾	488,456		304,026		37,113		(338,943		)	490,652
Total Liabilities and Shareholders' Equity	$	862,887	$	711,913	$	599,880	$	(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-119

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		$	122,606		$	79,334		$	(3,645	)	$	198,860
Expenses	53,883			194,085			141,289			(1,790		)	387,467
Loss from continuing operations before equity in net income of subsidiaries	(53,318		)	(71,479		)	(61,955		)	(1,855		)	(188,607		)
Equity in net income of subsidiaries	(91,254		)	458			(23,362		)	114,158			—
Loss from continuing operations before income tax	(144,572		)	(71,021		)	(85,317		)	112,303			(188,607		)
Income tax benefit	—			14,796			17,400			—			32,196
Loss from continuing operations	(144,572		)	(56,225		)	(67,917		)	112,303			(156,411		)
Income from discontinued operations, net of tax	—			(124		)	17,405			—			17,281
Gain on sale of discontinued operations, net of tax	—			2,409			—			—			2,409
Net income (loss)	(144,572		)	(53,940		)	(50,512		)	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		)	(53,940		)	(50,512		)	116,316			(132,708		)
Dividends on preferred stock	(22,842		)	—			(11,864		)	—			(34,706		)
Net income (loss) attributable to common shareholders	$	(167,414	)	$	(53,940	)	$	(62,376	)	$	116,316		$	(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		$	60,780		$	35,369		$	(3,779	)	$	93,441
Expenses	68,772			82,105			32,974			(3,779		)	180,072
Loss from continuing operations before equity in net income of subsidiaries	(67,701		)	(21,325		)	2,395			—			(86,631		)
Equity in net income of subsidiaries	(8,960		)	(2,196		)	(939		)	12,095			—
Loss from continuing operations before income tax	(76,661		)	(23,521		)	1,456			12,095			(86,631		)
Income tax benefit	—			571			2,416			—			2,987
Loss from continuing operations	(76,661		)	(22,950		)	3,872			12,095			(83,644		)
Income from discontinued operations, net of tax	—			—			7,232			—			7,232
Net income (loss)	(76,661		)	(22,950		)	11,104			12,095			(76,412		)
Net income attributable to non-controlling interest	—			—						(249		)	(249		)
Net loss attributable to Magnum Hunter Resources Corporation	(76,661		)	(22,950		)	11,104			11,846			(76,661		)
Dividends on preferred stock	(14,007		)	—			—			—			(14,007		)
Net income (loss) attributable to common shareholders	$	(90,668	)	$	(22,950	)	$	11,104		$	11,846		$	(90,668	)

F-120

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		$	16,558	$	12,993	$	(2,337	)	$	28,609
Expenses	27,421			13,501		12,836		(2,337		)	51,421
Loss from continuing operations before equity in net income of subsidiaries	(26,026		)	3,057		157		—			(22,812		)
Equity in net income of subsidiaries	3,769			—		—		(3,769		)	—
Loss from continuing operations	(22,257		)	3,057		157		(3,769		)	(22,812		)
Income from discontinued operations, net of tax	1,797			—		684		—			2,481
Gain on sale of discontinued operations, net of tax	6,660			—		—		—			6,660
Net income (loss)	(13,800		)	3,057		841		(3,769		)	(13,671		)
Net income attributable to non-controlling interest	—			—		—		(129		)	(129		)
Net loss attributable to Magnum Hunter Resources Corporation	(13,800		)	3,057		841		(3,898		)	(13,800		)
Dividends on preferred stock	(2,467		)	—		—		—			(2,467		)
Net income (loss) attributable to common shareholders	$	(16,267	)	$	3,057	$	841	$	(3,898	)	$	(16,267	)

F-121

Magnum Hunter Resources Corporation and Subsidiaries

Condensed Consolidating Statements of Comprehensive Income (Loss)

(in thousands)



	For the Year Ended December 31, 2012
	Magnum Hunter Resources Corporation			Guarantor Subsidiaries			Non Guarantor Subsidiaries			Eliminations		Magnum Hunter Resources Corporation Consolidated
Net income (loss)	$	(144,572	)	$	(53,940	)	$	(50,512	)	$	112,303	$	(136,721	)
Foreign currency translation loss	—			—			3,883			—		3,883
Unrealized gain (loss) on available for sale securities	—			(309		)	—			—		(309		)
Comprehensive income (loss)	(144,572		)	(54,249		)	(46,629		)	112,303		(133,147		)
Comprehensive income (loss) attributable to non-controlling interest	—			—			—			4,013		4,013
Comprehensive income (loss) attributable to Magnum Hunter Resources Corporation	$	(144,572	)	$	(54,249	)	$	(46,629	)	$	116,316	$	(129,134	)



	For the Year Ended December 31, 2011
	Magnum Hunter Resources Corporation			Guarantor Subsidiaries			Non Guarantor Subsidiaries			Eliminations			Magnum Hunter Resources Corporation Consolidated
Net income (loss)	$	(76,661	)	$	(22,950	)	$	11,104		$	12,095		$	(76,412	)
Foreign currency translation loss	—			—			(12,477		)	—			(12,477		)
Unrealized gain (loss) on available for sale securities	—			14			—			—			14
Comprehensive income (loss)	(76,661		)	(22,936		)	(1,373		)	12,095			(88,875		)
Comprehensive income (loss) attributable to non-controlling interest	—			—			—			(249		)	(249		)
Comprehensive income (loss) attributable to Magnum Hunter Resources Corporation	$	(76,661	)	$	(22,936	)	$	(1,373	)	$	11,846		$	(89,124	)



	For the Year Ended December 31, 2010
	Magnum Hunter Resources Corporation			Guarantor Subsidiaries		Non Guarantor Subsidiaries		Eliminations			Magnum Hunter Resources Corporation Consolidated
Net income (loss)	$	(13,800	)	$	3,057	$	841	$	(3,769	)	$	(13,671	)
Foreign currency translation loss	—			—		—		—			—
Unrealized gain (loss) on available for sale securities	—			—		—		—			—
Comprehensive income (loss)	(13,800		)	3,057		841		(3,769		)	(13,671		)
Comprehensive income (loss) attributable to non-controlling interest	—			—		—		(129		)	(129		)
Comprehensive income (loss) attributable to Magnum Hunter Resources Corporation	$	(13,800	)	$	3,057	$	841	$	(3,898	)	$	(13,800	)

F-122

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	)	$	275,914		$	241,018		$	—	$	58,011
Cash flow from investing activities	(364,045		)	(277,965		)	(367,197		)	—		(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			(4,017		)	38,675			—		42,772
Cash at beginning of period	18,758			(445		)	(3,462		)	—		14,851
Cash at end of period	$	26,872		$	(4,462	)	$	35,213		$	—	$	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	)	$	136,974		$	100,115		$	—	$	33,838
Cash flow from investing activities	(90,464		)	(136,489		)	(134,762		)	—		(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			175			(3,080		)	—		14,297
Cash at beginning of period	1,556			(620		)	(382		)	—		554
Cash at end of period	$	18,758		$	(445	)	$	(3,462	)	$	—	$	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	)	$	36,982		$	54,659		$	—	$	(1,168	)
Cash flow from investing activities	(21,926		)	(40,862		)	(55,493		)	—		(118,281		)
Cash flow from financing activities	117,998			(322		)	45			—		117,721
Net increase (decrease) in cash	3,263			(4,202		)	(789		)	—		(1,728		)
Cash at beginning of period	(1,707		)	3,582			407			—		2,282
Cash at end of period	$	1,556		$	(620	)	$	(382	)	$	—	$	554

F-123

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		$	60,552	$	111,126	$	(31,229	)	$	204,319
Intercompany accounts receivable	803,834		—			—		—		(803,834		)	—
Property and equipment (using successful efforts accounting)	9,596		18,257			1,276,467		620,093		—			1,924,413
Investment in subsidiaries	763,856		—			101,341		102,354		(967,551		)	—
Other assets	20,849		—			5,451		43,600		—			69,900
Total Assets	$	1,661,302	$	18,960		$	1,443,811	$	877,173	$	(1,802,614	)	$	2,198,632

LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities	$	28,503	$	2,291		$	117,511	$	125,727	$	(30,376	)	$	243,656
Intercompany accounts payable	—		58,966			508,254		236,636		(803,856		)	—
Long-term liabilities	831,286		1,274			97,271		112,615		—			1,042,446
Redeemable preferred stock	100,000		—			—		100,878		—			200,878
Shareholders' equity (deficit)	701,513		(43,571		)	720,775		301,317		(968,382		)	711,652
Total Liabilities and Shareholders' Equity	$	1,661,302	$	18,960		$	1,443,811	$	877,173	$	(1,802,614	)	$	2,198,632

F-124

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		$	21,932	$	27,503	$	645		$	77,669
Intercompany accounts receivable	667,557		—			—		—		(667,557		)	—
Property and equipment (using successful efforts accounting)	13,287		32,607			636,854		392,511		(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		$	721,924	$	552,070	$	(1,002,916	)	$	1,168,760

LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities	$	21,112	$	1,319		$	85,516	$	59,671	$	57		$	167,675
Intercompany accounts payable	—		60,173			234,468		390,934		(685,575		)	—
Long-term liabilities	253,319		1,983			96,885		58,246		—			410,433
Redeemable preferred stock	100,000		—			—		—		—			100,000
Shareholders' equity (deficit)	488,456		(28,680		)	305,055		43,219		(317,398		)	490,652
Total Liabilities and Shareholders' Equity	$	862,887	$	34,795		$	721,924	$	552,070	$	(1,002,916	)	$	1,168,760

F-125

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		$	141,106		$	53,220		$	(3,645	)	$	198,860
Expenses	53,883			22,505			211,404			82,972			16,703			387,467
Loss from continuing operations before equity in net income of subsidiaries	(53,318		)	(14,891		)	(70,298		)	(29,752		)	(20,348		)	(188,607		)
Equity in net income of subsidiaries	(91,254		)	—			458			(23,362		)	114,158			—
Loss from continuing operations before income tax	(144,572		)	(14,891		)	(69,840		)	(53,114		)	93,810			(188,607		)
Income tax benefit	—			—			14,796			17,400			—			32,196
Loss from continuing operations	(144,572		)	(14,891		)	(55,044		)	(35,714		)	93,810			(156,411		)
Income from discontinued operations, net of tax	—			—			(124		)	17,405			—			17,281
Gain on sale of discontinued operations, net of tax	—			—			2,409			—			—			2,409
Net income (loss)	(144,572		)	(14,891		)	(52,759		)	(18,309		)	93,810			(136,721		)
Net loss attributable to non-controlling interest	—						—						4,013			4,013
Net loss attributable to Magnum Hunter Resources Corporation	(144,572		)	(14,891		)	(52,759		)	(18,309		)	97,823			(132,708		)
Dividends on preferred stock	(22,842		)	—			—			(11,864		)	—			(34,706		)
Net income (loss) attributable to common shareholders	$	(167,414	)	$	(14,891	)	$	(52,759	)	$	(30,173	)	$	97,823		$	(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		$	70,205		$	17,256		$	(3,778	)	$	93,441
Expenses	68,772			11,704			91,651			16,728			(8,783		)	180,072
Loss from continuing operations before equity in net income of subsidiaries	(67,701		)	(3,017		)	(21,446		)	528			5,005			(86,631		)
Equity in net income of subsidiaries	(8,960		)	—			(2,196		)	(939		)	12,095			—
Loss from continuing operations before income tax	(76,661		)	(3,017		)	(23,642		)	(411		)	17,100			(86,631		)
Income tax benefit	—			—			571			2,416			—			2,987
Loss from continuing operations	(76,661		)	(3,017		)	(23,071		)	2,005			17,100			(83,644		)
Income from discontinued operations, net of tax	—			—			—			7,232			—			7,232
Net income (loss)	(76,661		)	(3,017		)	(23,071		)	9,237			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		)	(23,071		)	9,237			16,851			(76,661		)
Dividends on preferred stock	(14,007		)	—			—			—			—			(14,007		)
Net income (loss) attributable to common shareholders	$	(90,668	)	$	(3,017	)	$	(23,071	)	$	9,237		$	16,851		$	(90,668	)

F-126

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		$	19,949	$	1,424		$	(2,337	)	$	28,609
Expenses	27,421			15,275			17,578		1,610			(10,463		)	51,421
Loss from continuing operations before equity in net income of subsidiaries	(26,026		)	(7,097		)	2,371		(186		)	8,126			(22,812		)
Equity in net income of subsidiaries	3,769			—			—		—			(3,769		)	—
Loss from continuing operations	(22,257		)	(7,097		)	2,371		(186		)	4,357			(22,812		)
Income from discontinued operations, net of tax	1,797			—			—		684			—			2,481
Gain on sale of discontinued operations, net of tax	6,660			—			—		—			—			6,660
Net income (loss)	(13,800		)	(7,097		)	2,371		498			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		)	2,371		498			4,228			(13,800		)
Dividends on preferred stock	(2,467		)	—			—		—			—			(2,467		)
Net income (loss) attributable to common shareholders	$	(16,267	)	$	(7,097	)	$	2,371	$	498		$	4,228		$	(16,267	)

F-127

Magnum Hunter Resources Corporation and Subsidiaries

Condensed Consolidating Statements of Comprehensive Income (Loss)

(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
Net income (loss)	$	(144,572	)	$	(14,891	)	$	(52,759	)	$	(18,309	)	$	93,810	$	(136,721	)
Foreign currency translation loss	—			—			—			3,883			—		3,883
Unrealized gain (loss) on available for sale securities	—			—			(309		)	—			—		(309		)
Comprehensive income (loss)	(144,572		)	(14,891		)	(53,068		)	(14,426		)	93,810		(133,147		)
Comprehensive income (loss) attributable to non-controlling interest	—			—			—			—			4,013		4,013
Comprehensive income (loss) attributable to Magnum Hunter Resources Corporation	$	(144,572	)	$	(14,891	)	$	(53,068	)	$	(14,426	)	$	97,823	$	(129,134	)



	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
Net income (loss)	$	(76,661	)	$	(3,017	)	$	(23,071	)	$	9,237		$	17,100		$	(76,412	)
Foreign currency translation loss	—			—			—			(12,477		)	—			(12,477		)
Unrealized gain (loss) on available for sale securities	—			—			14			—			—			14
Comprehensive income (loss)	(76,661		)	(3,017		)	(23,057		)	(3,240		)	17,100			(88,875		)
Comprehensive income (loss) attributable to non-controlling interest	—			—			—			—			(249		)	(249		)
Comprehensive income (loss) attributable to Magnum Hunter Resources Corporation	$	(76,661	)	$	(3,017	)	$	(23,057	)	$	(3,240	)	$	16,851		$	(89,124	)



	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
Net income (loss)	$	(13,800	)	$	(7,097	)	$	2,371	$	498	$	4,357		$	(13,671	)
Foreign currency translation loss	—			—			—		—		—			—
Unrealized gain (loss) on available for sale securities	—			—			—		—		—			—
Comprehensive income (loss)	(13,800		)	(7,097		)	2,371		498		4,357			(13,671		)
Comprehensive income (loss) attributable to non-controlling interest	—			—			—		—		(129		)	(129		)
Comprehensive income (loss) attributable to Magnum Hunter Resources Corporation	$	(13,800	)	$	(7,097	)	$	2,371	$	498	$	4,228		$	(13,800	)

F-128

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		$	281,782		$	235,104		$	(1,210	)	$	58,011
Cash flow from investing activities	(364,045		)	(49		)	(287,204		)	(357,912		)	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			—			(3,641		)	38,299			—			42,772
Cash at beginning of period	18,758			—			(546		)	(3,361		)	—			14,851
Cash at end of period	$	26,872		$	—		$	(4,187	)	$	34,938		$	—		$	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	)	$	138,855		$	98,048		$	1,924		$	33,838
Cash flow from investing activities	(90,464		)	(175		)	(141,954		)	(129,111		)	(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			—			107			(3,012		)	—			14,297
Cash at beginning of period	1,556			—			(653		)	(349		)	—			554
Cash at end of period	$	18,758		$	—		$	(546	)	$	(3,361	)	$	—		$	14,851

F-129

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	)	$	37,687		$	53,869		$	4,903		$	(1,168	)
Cash flow from investing activities	(21,926		)	(237		)	(41,531		)	(54,606		)	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		)	(4,364		)	(494		)	—			(1,728		)
Cash at beginning of period	(1,707		)	133			3,711			145			—			2,282
Cash at end of period	$	1,556		$	—		$	(653	)	$	(349	)	$	—		$	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-130

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	Weighted Avg Price per Bbl
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

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-131

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

F-132

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.

F-133

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 20, 2013

F-134

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Members

PRC Williston, LLC

We have audited the accompanying balance sheets 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-135

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-136

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-137

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-138

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-139

PRC WILLISTON, LLC

NOTES TO FINANCIAL STATEMENTS

NOTE 1—ORGANIZATION AND NATURE OF OPERATIONS

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.

F-140

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.

F-141

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 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

F-142

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.

Income Taxes

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 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

F-143

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.

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 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

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.

F-144

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

F-145

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-146

Report of Independent Registered Public Accounting Firm

To the Board of Directors

Magnum Hunter Resources Corporation

We have audited the accompanying statements of revenues and direct operating expenses of the oil and gas properties purchased by Bakken Hunter, LLC, a wholly-owned subsidiary of Magnum Hunter Resources Corporation (the “Purchaser”), from Baytex Energy USA Ltd (“Baytex”) for the year ended December 31, 2011. These financial statements are the responsibility of the Purchaser’s management. Our responsibility is to express an opinion on these financial statements based on our audit.

In our opinion, the financial statements referred to above present fairly, in all material respects, the revenues and direct operating expenses of the oil and gas properties purchased by the Purchaser from Baytex described in Note 1 for the year ended December 31, 2011, in conformity with accounting principles generally accepted in the United States of America.

The accompanying statements were prepared for the purpose of complying with the rules and regulations of the Securities and Exchange Commission (for inclusion in the current report on Form 8-K of Magnum Hunter Resources Corporation) and are not intended to be a complete financial presentation of the properties described above.

Hein & Associates LLP

Dallas, Texas

August 3, 2012

F-147

STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES OF THE OIL AND GAS PROPERTIES PURCHASED BY BAKKEN HUNTER, LLC, FROM BAYTEX ENERGY USA, LTD



	Three Months Ended				Twelve Months Ended
	March 31,				December 31,
	2012		2011		2011
	(unaudited)		(unaudited)
REVENUES	$	5,109,072	$	3,240,505	$	15,025,308

DIRECT OPERATING EXPENSES	1,241,696		813,510		3,763,066

EXCESS OF REVENUES OVER DIRECT OPERATING EXPENSES	$	3,867,376	$	2,426,995	$	11,262,242

F-148

NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES OF THE OIL AND GAS PROPERTIES PURCHASED BY BAKKEN HUNTER, LLC, FROM BAYTEX ENERGY USA, LTD FOR THE TWELVE MONTHS ENDED DECEMBER 31, 2011 AND THE THREE MONTHS ENDED MARCH 31, 2012 AND 2011

NOTE 1 — BASIS OF PRESENTATION

On April 18, 2012, Bakken Hunter, LLC (the “Purchaser”), a Delaware limited liability company and wholly-owned subsidiary of Magnum Hunter Resources Corporation (“Magnum Hunter”), entered into a Purchase and Sale Agreement (the “Purchase Agreement”) with Baytex Energy USA Ltd. (“Baytex”), an affiliate of Baytex Energy Corporation (“Baytex Parent”). Pursuant to the Purchase Agreement, Bakken Hunter agreed to purchase all of Baytex’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 that certain Operating Agreement (the “Operating Agreement”) dated January 1, 2010, among Samson Resources Company (“Samson”), as operator, Baytex and Williston Hunter, Inc., a wholly-owned subsidiary of Magnum Hunter (“Williston Hunter”) (collectively, the “Assets”). The purchase price of the Assets is $311 million in cash, subject to adjustment for certain customary items, including revenues and expenses attributable to the Assets, and certain title deficiencies and environmental conditions.

The statements of revenues and direct operating expenses associated with the Assets were derived from Baytex Parent’s accounting records. During the periods presented, the Assets were not accounted for or operated as a consolidated entity or as a separate division by Baytex Parent. Revenues and direct operating expenses for the Assets included in the accompanying statements represent the net collective working and revenue interests to be acquired by the Purchaser. The revenues and direct operating expenses presented herein relate only to the Assets which have been acquired and do not represent all of the oil and natural gas operations of Baytex Parent, other owners, or other third party working interest owners. Direct operating expenses include lease operating expenses and production and other related taxes. General and administrative expenses and depreciation, depletion, and amortization of oil and gas properties and federal and state taxes have been excluded from direct operating expenses in the accompanying statements of revenues and direct operating expenses because the allocation of certain expenses would be arbitrary and would not be indicative of what such costs would have been had the Assets been operated as a standalone entity. No dry holes were conveyed to the Purchaser as part of the Purchase Agreement. Accordingly, exploration expenses and dry hole costs are not applicable to this presentation. Full separate financial statements prepared in accordance with accounting principles generally accepted in the United States of America do not exist for the Assets and are not practicable to prepare in these circumstances. The statements of revenues and direct operating expenses presented are not indicative of the results of operations of the Assets on a go forward basis due to changes in the business and the omission of various operating expenses.

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Use of Estimates: The preparation of statements of revenues and direct operating expenses in conformity with accounting principles generally accepted in the United States of America requires management to make certain estimates and assumptions that affect the reported amounts of revenues and expenses during the reporting periods. Although these estimates are based on management’s best available knowledge of current and future events, actual results could be different from those estimates.

Revenue Recognition: Revenues are recognized for oil and natural gas sales under the sales method of accounting. Under this method, revenues are recognized on production as it is taken and delivered to its purchasers. The volumes sold may be more or less than the volumes entitled to, based on the owner’s net interest in the Assets. These differences result from production imbalances, which are not significant, and are reflected as adjustments to proved reserves and future cash flows in the unaudited supplementary oil and gas information included herein.

Interim Financial Information: The interim financial information for the three months ended March 31, 2012 and 2011 included herein is unaudited. In the opinion of the Purchaser’s management, the information furnished herein reflects all adjustments, consisting of only normal recurring adjustments, necessary for a fair presentation of the results of the interim periods reported herein. Operating results for the three months ended March 31, 2012 may not necessarily be indicative of the results for the year ending December 31, 2012.

NOTE 3 — SUPPLEMENTARY OIL AND GAS INFORMATION — (UNAUDITED)

Estimated Net Quantities of Oil and Natural Gas Reserves

The following are estimates of the net proved oil and natural gas reserves of the properties located entirely within the United States of America. Reserve volumes and values were determined under definitions and guidelines of the U.S. Securities and Exchange Commission (“SEC”) and, with the exception of the exclusion of future income taxes, conform to the FASB Accounting Standards Codification Topic 932, Extractive Activities-Oil and Gas. Reserve estimates are expected to change as additional performance data becomes available.

F-149

Estimated quantities of proved domestic oil and gas reserves and changes in quantities of proved developed and undeveloped reserves in the thousand barrels of oil (“MBbl”) and million cubic feet (“MMcf”) were as follows:



	Crude Oil (Mbbls)		Natural Gas (MMcf)
Proved reserves at January 1, 2011	3,637		72
Production	(172	)	(11	)
Extensions and discoveries	1,319		13
Proved reserves at December 31, 2011	4,784		74

Proved developed reserves
December 31, 2011	1,385		63

Discounted Future Net Cash Flows

A summary of the discounted future net cash flows related to proved crude oil and natural gas reserves is shown below. Future net cash flows calculated at December 31, 2011 are based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month prior period.



	December 31, 2011		December 31, 2010
Commodity prices used in determining future cash flows
Oil (per Bbl)	$	87.89	$	71.78
Natural Gas (per Mcf)	$	3.22	$	3.64



	December 31, 2011			December 31, 2010
	(in thousands)			(in thousands)
Future cash inflows	$	376,909		$	234,131
Less related future
Production costs	(74,540		)	(48,229		)
Development and abandonment costs	(106,988		)	(82,090		)
Future income tax expense	(53,344		)	(23,788		)
Future net cash flows	142,037			80,024
Ten percent annual discount for estimated timing of cash flows	(91,404		)	(57,851		)
Standardized measure of discounted future net cash flows	$	50,633		$	22,173

* Future cash inflows from proved undeveloped reserves are approximately $267.7 million.

F-150

Changes in Discounted Future Net Cash Flows

A summary of the changes in the discounted future net cash flows applicable to proved crude oil and natural gas reserves follows:




	(in thousands)
Present Value, beginning of period	$	22,173
Net changes in prices and production costs	26,870
Net changes in future development costs	(25,798		)
Previously estimated development costs incurred	7,013
Sales of oil and gas produced, net	(11,269		)
Extensions and discoveries	37,036
Revisions of previous quantity estimates
Accretion of discount	13,954
Net change in income taxes	(18,905		)
Changes in rate of production and other	(441		)
Present value, end of period	$	50,633

F-151

Magnum Hunter Resources Corporation

Unaudited Combined Pro Forma Consolidated Statement of Operations

The following unaudited pro forma financial information gives effect to the Company's 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, paid in cash funded by borrowings on the line of credit, on May 22, 2012, the closing date of the acquisition.

The unaudited pro forma consolidated statement of operations for the year ended December 31, 2012 is based on our audited consolidated statement of operations for the year ended December 31, 2012, included in our Annual Report on Form 10-K for the year ended December 31, 2012, and gives effect to the transaction described above as if it occurred on January 1, 2012.

The unaudited pro forma consolidated financial statement presented herein has been included as required by the rules of the SEC and is provided for comparative purposes only. The unaudited pro forma consolidated financial statement should be read in conjunction with our historical consolidated financial statements and related notes for the periods presented.

The unaudited pro forma consolidated financial statement presented herein is based upon assumptions and include adjustments as explained in the notes to the unaudited pro forma consolidated financial statement, and the actual recording of the transaction could differ. The unaudited pro forma consolidated financial statement presented herein is not necessarily indicative of the financial results that would have occurred had the transaction described above occurred on the date indicated and should not be viewed as indicative of operations in the future. However, management believes that the assumptions used provide a reasonable basis for presenting the significant effects of the transaction discussed above and that the pro forma adjustments give appropriate effect to those assumptions.

203



UNAUDITED COMBINED PRO FORMA CONSOLIDATED STATEMENT OF OPERATIONS
For the Year Ended December 31, 2012
(in thousands, except share and per-share data)

	Magnum Hunter Historical			Baytex Assets Historical			Baytex Assets Pro Forma Adjustments			Combined Pro Forma
REVENUE:
Oil and gas sales	$	173,283		$	8,125		$	—		$	181,408
Gas transportation, gathering, and processing	13,040			—						13,040
Oil field services	12,333			—						12,333
Other revenue	204			—			—			204
Total revenue	198,860			8,125			—			206,985

EXPENSES:
Lease operating expenses	45,684			1,187			—			46,871
Severance taxes and marketing	10,787			824			—			11,611
Exploration	117,216			—			—			117,216
Gas transportation, gathering, and processing	8,028			—						8,028
Field operations	10,037			—			—			10,037
Impairment of proved oil & gas properties	4,096			—			—			4,096
Depreciation, depletion and accretion	99,900			—		A)	5,123			105,023
General and administrative	64,388			—			—			64,388
Total expenses	360,136			2,011			5,123			367,270

INCOME (LOSS) FROM OPERATIONS	(161,276		)	6,114			(5,123		)	(160,285		)

OTHER INCOME AND (EXPENSE):
Interest income	230			—			—			230
Interest expense	(51,846		)	—		B)	(11,951		)	(63,797		)
Gain (Loss) on derivative contracts	22,239			—			—			22,239
Other	2,046			—			—			2,046
Total other expense	(27,331		)	—			(11,951		)	(39,282		)
Loss from continuing operations before income tax	(188,607		)	6,114			(17,074		)	(199,567		)
Income tax benefit	32,196			—			—			32,196
Loss from continuing operations	(156,411		)	6,114			(17,074		)	(167,371		)
Income from discontinued operations, net of tax	17,281			—						17,281
Gain (Loss) on sale of discontinued operations,	2,409			—						2,409
Net loss	(136,721		)	6,114			(17,074		)	(147,681		)
Net loss attributable to non-controlling interest	4,013			—			—			4,013
Net loss attributable to Magnum Hunter Resources Corporation	(132,708		)	6,114			(17,074		)	(143,668		)
Dividends on preferred stock	(34,706		)	—			—			(34,706		)
Net loss attributable to common shareholders	$	(167,414	)	$	6,114		$	(17,074	)	$	(178,374	)

Loss per common share
Basic and diluted	$	(1.07	)							$	(1.15	)

Weighted average shares outstanding	155,743,418						—			155,743,418

204

Magnum Hunter Resources Corporation

Notes to Unaudited Combined Pro Forma Consolidated Statement of Operations


A.	To record the pro forma adjustment to depreciation, depletion and amortization (“DD&A”) as a result of treating the acquisition of the Baytex assets as if the transaction had occurred January 1, 2012.


B.	To recored the pro forma adjustment to interest expense as a result of treating the acquisition of the Baytex assets as if the transaction had occurred January 1, 2012.

205

MAGNUM HUNTER RESOURCES CORPORATION

For a period of time, generally until 90 days following October 8, 2013, the effective date of the registration statement on Form S-4 (of which this prospectus forms a part), all dealers that effect transactions in these securities, whether or not participating in the exchange offer, may be required to deliver a prospectus. This is in addition to the dealers’ obligation to deliver a prospectus when acting as underwriters and with respect to their unsold allotments or subscriptions

Ngas Gathering Inactive 424B3Prospectus supplement