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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549





Form 10-K



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

For the fiscal year ended December 31, 2011

Commission file number: 001-32997







LOGO

Magnum Hunter Resources Corporation

(Name of registrant as specified in its charter)



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

777 Post Oak Boulevard, Suite 650, Houston, Texas 77056

(Address of principal executive offices, including zip code)

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

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



|                                                                                                                           |  |                                          
|-------------------------------------------------------------------------------------------------------------------------- |  | -----------------------------------------
|Title of Each Class                                                                                                        |  | Name of Each Exchange on Which Registered
|$0.01 par value Common Stock 10.25% Series C Cumulative Perpetual Preferred Stock 8.0% Series D Cumulative
Preferred Stock |  | NYSE NYSE Amex NYSE Amex                 

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

None





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

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

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

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

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

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



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

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

State the aggregate market value of voting and non-voting common equity held by non-affiliates computed by reference to the price at which
the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of the registrants most recently completed second fiscal quarter: $798,265,888.

As of February 27, 2012, 130,565,699 shares of the registrants common stock were issued and outstanding.





DOCUMENTS INCORPORATED BY REFERENCE

Documents incorporated by reference: Portions of the registrants notice of annual meeting of shareholders and proxy statement to be filed pursuant to Regulation 14A within 120 days after
the registrants fiscal year end of December 31, 2011 are incorporated by reference into Part III of this Form 10-K.



|* | Subsequent to the filing of this report, we will file an amended report on Form 10-K/A, which will have documents formatted in XBRL (Extensible Business Reporting
Language). We have elected to take advantage of the 30-day grace period in filing our first annual report on Form 10-K with detailed tagging requirements as allowed by Rule 405(a)(2)(ii) of Regulation S-T.
|- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------









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Magnum Hunter Resources Corporation

2011 Annual Report on Form 10-K

Table of Contents



|         |  |                                                                                                              |  |  |      | 
|-------- |  | ------------------------------------------------------------------------------------------------------------ |  |  | ---- | 
|         |  | Glossary of Oil and Natural Gas Terms                                                                        |  |  | 5    | 
|Item 1.  |  | BUSINESS                                                                                                     |  |  | 12   | 
|Item 1A. |  | RISK FACTORS                                                                                                 |  |  | 22   | 
|Item 1B. |  | UNRESOLVED STAFF COMMENTS                                                                                    |  |  | 43   | 
|Item 2.  |  | PROPERTIES                                                                                                   |  |  | 43   | 
|Item 3.  |  | LEGAL PROCEEDINGS                                                                                            |  |  | 62   | 
|Item 4.  |  | MINE SAFETY DISCLOSURES                                                                                      |  |  | 62   | 
|Item 5.  |  | MARKET FOR REGISTRANTS COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES |  |  | 63   | 
|Item 6.  |  | SELECTED FINANCIAL DATA                                                                                      |  |  | 66   | 
|Item 7.  |  | MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS                        |  |  | 67   | 
|Item 7A. |  | QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK                                                    |  |  | 92   | 
|Item 8.  |  | FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA                                                                  |  |  | F-1  | 
|Item 9.  |  | CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL
DISCLOSURE                         |  |  | F-53 | 
|Item 9A. |  | CONTROLS AND PROCEDURES                                                                                      |  |  | F-53 | 
|Item 9B. |  | OTHER INFORMATION                                                                                            |  |  | F-55 | 
|Item 10. |  | DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE                                                       |  |  | F-55 | 
|Item 11. |  | EXECUTIVE COMPENSATION                                                                                       |  |  | F-55 | 
|Item 12. |  | SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER
MATTERS               |  |  | F-55 | 
|Item 13. |  | CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE                                     |  |  | F-55 | 
|Item 14. |  | PRINCIPAL ACCOUNTANT FEES AND SERVICES                                                                       |  |  | F-55 | 
|Item 15. |  | EXHIBITS AND FINANCIAL STATEMENT SCHEDULES                                                                   |  |  | F-56 | 



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CAUTIONARY NOTICE

The statements and information contained in this annual report on Form 10-K that are not statements of historical fact, including all of the estimates and assumptions contained herein, are
forward looking statements as defined in Section 27A of the Securities Act of 1933, as amended, referred to as the Securities Act, and Section 21E of the Securities Exchange Act of 1934, as amended, referred to as the Exchange
Act. These forward-looking statements include, among others, statements, estimates and assumptions relating to our business and growth strategies, our oil and gas reserve estimates, our ability to successfully and economically explore for and
develop oil and gas resources, our exploration and development prospects, future inventories, projects and programs, expectations relating to availability and costs of drilling rigs and field services, 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 acquisitions described herein, forward-looking statements include, but are not limited to, statements regarding the expected timing of the completion of the proposed transactions; the ability to
complete the proposed transactions considering the various closing conditions; the benefits of such transactions and their impact on the Companys business; and any statements of assumptions underlying any of the foregoing. In addition, if and
when any proposed transaction 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. Forward-looking statements
generally can be identified by the use of forward-looking terminology such as may, will, could, should, expect, intend, estimate, anticipate,
believe, project, pursue, plan or continue or the negative thereof or variations thereon or similar terminology.

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



| |  |  | adverse economic conditions in the United States, Canada and globally;
| | - |  | ----------------------------------------------------------------------



| |  |  | difficult and adverse conditions in the domestic and global capital and credit markets;
| | - |  | ---------------------------------------------------------------------------------------



| |  |  | changes in domestic and global demand for oil and natural gas;
| | - |  | --------------------------------------------------------------



| |  |  | volatility in the prices we receive for our oil and natural gas;
| | - |  | ----------------------------------------------------------------



| |  |  | the effects of government regulation, permitting and other legal requirements;
| | - |  | ------------------------------------------------------------------------------



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



| |  |  | uncertainties about the estimates of our oil and natural gas reserves;
| | - |  | ----------------------------------------------------------------------



| |  |  | our ability to increase our production and oil and natural gas income through exploration and development;
| | - |  | ----------------------------------------------------------------------------------------------------------



| |  |  | our ability to successfully apply horizontal drilling techniques;
| | - |  | -----------------------------------------------------------------



| |  |  | 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 transportation pipelines;
| | - |  | ----------------------------------------------------------------------------------



| |  |  | changes in our drilling plans and related budgets;
| | - |  | --------------------------------------------------



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| |  |  | regulatory, environmental and land management issues, and demand for gas gathering services, relating to our midstream operations;
| | - |  | ----------------------------------------------------------------------------------------------------------------------------------



| |  |  | the adequacy of our capital resources and liquidity including, but not limited to, access to additional borrowing capacity; and
| | - |  | -------------------------------------------------------------------------------------------------------------------------------



| |  |  | other factors discussed under Risk Factors in Item 1A of this report.
| | - |  | -----------------------------------------------------------------------

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



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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 report.



|                   |  |                                                                                                                                                                                                                                                                                                                                                                  
|------------------ |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|bbl                |  | Stock tank barrel, or 42 U.S. gallons liquid volume, used in this report in reference to crude oil or other liquid hydrocarbons.                                                                                                                                                                                                                                 
|                   | 
|bcf                |  | Billion cubic feet of natural gas.                                                                                                                                                                                                                                                                                                                               
|                   | 
|boe                |  | Barrels of crude oil equivalent, determined using the ratio of six mcf of natural gas to one bbl of crude oil, condensate or natural gas liquids.                                                                                                                                                                                                                
|                   | 
|boepd              |  | boe per day.                                                                                                                                                                                                                                                                                                                                                     
|                   | 
|Completion         |  | The process of treating a drilled well followed by the installation of permanent equipment for the production of natural gas or oil, or in the case of a dry hole, the reporting
of abandonment to the appropriate agency.                                                                                                                                       
|                   | 
|Condensate         |  | Hydrocarbons which are in the gaseous state under reservoir conditions and which become liquid when temperature or pressure is reduced. A mixture of pentanes and higher
hydrocarbons.                                                                                                                                                                           
|                   | 
|Development well   |  | A well drilled within the proved area of a natural gas or oil reservoir to the depth of a stratigraphic horizon known to be productive.                                                                                                                                                                                                                          
|                   | 
|Drilling locations |  | Total gross locations specifically quantified by management to be included in the Companys multi-year drilling activities on existing acreage. The Companys actual
drilling activities may change depending on the availability of capital, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, drilling results and other factors.
|                   | 
|Dry hole           |  | A well found to be incapable of producing either oil or natural gas in sufficient quantities to justify completion as an oil or gas well.                                                                                                                                                                                                                        
|                   | 
|EUR                |  | Estimated ultimate recovery.                                                                                                                                                                                                                                                                                                                                     
|                   | 
|Exploratory well   |  | A well drilled to find and produce natural gas or oil reserves not classified as proved, to find a new reservoir in a field previously found to be productive of natural gas or
oil in another reservoir or to extend a known reservoir.                                                                                                                         
|                   | 
|Field              |  | An area consisting of either a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic
condition.                                                                                                                                                                           
|                   | 
|Formation          |  | An identifiable layer of rocks named after its geographical location and dominant rock type.                                                                                                                                                                                                                                                                     



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|                                     |  |                                                                                                                                                                                                                                                                                                                           
|------------------------------------ |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|                                     | 
|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.
|                                     | 
|Lease                                |  | A legal contract that specifies the terms of the business relationship between an energy company and a landowner or mineral rights holder on a particular tract of
land.                                                                                                                                                  
|                                     | 
|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.                                                                                                                                                                 
|                                     | 
|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.                                                                                                                                                                                                                                                                                             



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|                                             |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                          
|-------------------------------------------- |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|                                             | 
|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 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 100% working interest the operator owns. This operator may assign its working
interest to another operator subject to a retained 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 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, 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.                                                                                                                                                                          



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|                                      |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                              
|------------------------------------- |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|                                      | 
|                                      |  | (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 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                                                                                                                                                                                                                                                                                



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|                                        |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                        
|--------------------------------------- |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|                                        |  | 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                                                                                                                                                                                                                                                                                                                          



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|                   |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                           
|------------------ |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|                   |  | a defined project. Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities
assumed for probable reserves. Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with
displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the Company believes that such adjacent portions are in communication with the known (proved) reservoir. Possible
reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir. Where direct observation has defined a highest known oil (HKO) elevation and the potential
exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions
of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.
|                   | 
|Productive well    |  | A well that is found to be capable of producing either oil or natural gas in sufficient quantities to justify completion as an oil or gas well.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                           
|                   | 
|Project            |  | A targeted development area where it is probable that oil or natural gas can be produced from new wells.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                  
|                   | 
|Prospect           |  | A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs,
is deemed to have potential for the discovery of commercial hydrocarbons.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                               
|                   | 
|R/P                |  | The reserves to production ratio. The reserve portion of the ratio is the amount of a resource known to exist in an area and to be economically recoverable. The production
portion of the ratio is the amount of resource used in one year at the current rate.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                          
|                   | 
|Recompletion       |  | The process of re-entering an existing well bore that is either producing or not producing and completing new reservoirs in an attempt to establish or increase existing
production.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                      
|                   | 
|Reserves           |  | Oil, natural gas and gas liquids thought to be accumulated in known reservoirs.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                           
|                   | 
|Reservoir          |  | A porous and permeable underground formation containing a natural accumulation of producible natural gas and/or oil 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.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    



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|                     |  |                                                                                                                                                                                                                                                                                                                                                                                                                                   
|-------------------- |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|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, could be to wait for pipeline or processing
facility, or could be 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, production and income tax expenses, discounted
at 10% per annum to reflect timing of future cash flows and using the same pricing assumptions as were used to calculate PV-10. Standardized measure differs from PV-10 because standardized measure includes the effect of future income
taxes.
|                     | 
|Successful           |  | A well is determined to be successful if it is producing oil or natural gas, or awaiting hookup, but not abandoned or plugged.                                                                                                                                                                                                                                                                                                    
|                     | 
|Undeveloped acreage  |  | Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether
such acreage contains proved reserves.                                                                                                                                                                                                          
|                     | 
|Water flood          |  | A method of secondary recovery in which water is injected into the reservoir formation to displace residual oil and enhance hydrocarbon recovery.                                                                                                                                                                                                                                                                                 
|                     | 
|Working interest     |  | The operating interest that gives the owner thereof the right to drill, produce and conduct operating activities on the property and receive a share of production and requires
the owner to pay a share of the costs of drilling and production operations.                                                                                                                                                                      



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|Item 1. | BUSINESS
|------- | --------

Website
Access to Reports

We make our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and
amendments to those reports, filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act, available free of charge on or through our Internet website, www.magnumhunterresources.com, as soon as reasonably practicable after
we electronically file such material with, or furnish it to, the SEC.

The 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, primarily in the states of West Virginia, Ohio, Texas, Kentucky and North Dakota and in Saskatchewan, Canada. We are also engaged in midstream operations involving the gathering of natural gas through our
ownership and operation of a gas gathering system in West Virginia and Ohio, referred to as our Eureka Hunter Pipeline System. We are presently active in three of the most prolific unconventional shale resource plays in North America, namely the
Marcellus/Utica Shales in West Virginia and Ohio, the Eagle Ford Shale in south Texas and the Williston Basin/Bakken Shale in North Dakota and Saskatchewan, Canada.

In May 2009, we restructured our management team and completely refocused our business strategy. Our business strategy is to exploit our inventory of lower risk drilling locations and acquire undeveloped
leases and long-lived proved reserves with significant exploitation and development opportunities primarily located in unconventional resource plays. Over the past three years, we have substantially increased our assets and production base through a
combination of acquisitions, joint ventures and ongoing development drilling efforts; our percentage of operated properties has increased significantly; our inventory of acreage and drilling locations in resource plays has grown dramatically; and
our management team has been expanded. We are focused on the further development and exploitation of our core unconventional resource plays, the acquisition of additional operated properties in our core operating regions, and selective expansion of
our midstream operations.

At December 31, 2011, our proved reserves were 44.9 mmboe and were approximately 48% oil. Our proved reserves
had a PV-10 value of $616.9 million (SEC basis) and $600.9 million (NYMEX basis), which is different from the standardized measure of $474 million due to the inclusion in the standardized measure of estimated future income taxes. Our
proved reserves at year end 2011 increased 235% from year end 2010. Our average daily production volumes for 2011 were 5,510 boepd, which represent a 324% increase from those volumes for 2010. Our daily production volumes were in excess of 12,500
boepd at December 31, 2011. As of February 27, 2012, we had over 560,072 net acres, with 170,000 net acres in our core resource areas, including approximately 58,426 net acres in the Marcellus Shale, 61,151 net acres in the Utica
Shale (a portion of which acreage overlaps our Marcellus Shale acreage), 24,000 net acres in the Eagle Ford Shale and 75,814 net acres in the Williston Basin (Bakken Shale/Three Forks/Sanish formations).

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

Recent Developments

Acquisition of Williston Basin Assets

In May 2011, we acquired NuLoch Resources Inc., or
NuLoch, a publicly traded Canadian oil and gas company engaged in the exploration, acquisition, development and production of properties in Western Canada and North Dakota, predominately in the Bakken Shale and Three Forks/Sanish formations of the
mid-continental Williston Basin. We acquired NuLoch in a stock-for-stock exchange pursuant to which shares of common stock of Magnum Hunter were exchanged for shares of NuLoch. The NuLoch assets acquired by us included (i) five



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mmboe of proved reserves as of December 31, 2010, (ii) production from approximately 124 wells, (iii) approximately 347,531 gross (76,000 net) lease acres in the Williston Basin
and (iv) a multi-year inventory of approximately 338 low-risk horizontal unconventional drilling locations. The acquired Williston Basin assets are operated by our wholly-owned subsidiaries, Williston Hunter, Inc. and Williston Hunter Canada,
Inc., referred to as Williston Hunter U.S. and Williston Hunter Canada, respectively.

Expansion of Marcellus Shale Position

We significantly expanded our Marcellus Shale acreage position through the following transactions completed by our wholly-owned
subsidiary, Triad Hunter, LLC, referred to as Triad Hunter.

PostRock Asset Acquisitions. In three separate transactions, which closed
in December 2010, January 2011 and June 2011, Triad Hunter acquired certain Marcellus Shale oil and gas properties in West Virginia from affiliates of PostRock Energy Corporation. The properties acquired in these PostRock asset acquisitions
included (i) an aggregate of approximately 13,293 gross (10,389 net) lease acres, comprised of 4,228 gross (2,114 net) lease acres in Wetzel County, West Virginia and 9,065 gross (6,161 net) lease acres in Lewis County, West Virginia,
(ii) eight proved developed producing wells and (iii) 27 identified horizontal unconventional drilling locations. The total purchase price of these properties consisted of approximately $24.7 million in cash and 3,201,360 restricted shares
of common stock of Magnum Hunter.

Windsor Asset Acquisition. In April 2011, Triad Hunter acquired certain Marcellus Shale oil
and gas properties located in Wetzel County, West Virginia from a privately-held independent oil and gas company for a purchase price of $20 million in cash. The acquired properties represented the remaining 50% non-operating working interest in
approximately 4,228 net lease acres in which Triad Hunter already owned the 50% operating working interest, which it had previously acquired through the PostRock asset acquisitions.

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 has been
designated as the operator for the contract area. Stone Energy also contributed to the joint venture certain infrastructure assets, including improved roadways, certain central field processing units (including water handling), and gas flow lines,
and agreed to commit its share of natural gas production from the contract area to gathering by our Eureka Hunter Pipeline System.

Expansion of Southern Appalachian Basin Position

In April 2011, we acquired NGAS Resources, Inc., or NGAS, a publicly traded exploration and production company focused on unconventional natural gas plays in the eastern United States, principally in the
southern Appalachian Basin. We acquired NGAS in a stock-for-stock exchange pursuant to which shares of common stock of Magnum Hunter were exchanged for shares of NGAS. The NGAS assets acquired by us included (i) 63.1 bcfe (10.5 mmboe) of proved
reserves as of December 31, 2010, (ii) production from approximately 1,364 wells, (iii) approximately 322,390 gross (275,684 net) lease acres, predominately in Kentucky, a substantial portion of which is held by production, and
(iv) a multi-year inventory of approximately 586 low-risk horizontal unconventional drilling locations. The acquired southern Appalachian Basin assets are operated by our wholly-owned subsidiary, Magnum Hunter Production, Inc., referred to as
Magnum Hunter Production or MHP.

Acquisition of Utica Shale Properties

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 lease acreage
consists of approximately 15,558 gross (12,186 net) acres that are presently prospective for the Utica Shale. Substantially all of this leasehold acreage is held by shallow production. Triad Hunter has agreed to acquire another block of



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similar acreage from the seller on or before April 16, 2012, assuming the seller can satisfy certain title requirements and meet certain other required conditions. The acquisition of this
Utica Shale acreage significantly expands our acreage position in a strategic region of Ohio, and also provides the opportunity for our midstream business to expand the Eureka Hunter Pipeline System into this region, which is currently not served by
midstream competitors.

Expansion of Credit Facilities

Our lenders significantly expanded our senior revolving credit facility through six separate borrowing base increases over the last 12 months. At January 1, 2011, our senior revolving credit facility
had a borrowing base of $71.5 million. As a result of the six borrowing base increases, the borrowing base under this facility is now $235 million. This facility is our MHR Senior Revolving Credit Facility. In addition, in 2011, we obtained a new
term loan facility for Magnum Hunter. Pursuant to this new facility, we obtained a $100 million term loan, which closed and was fully funded in September 2011. This facility is our MHR Term Loan Facility. Also in 2011, we obtained two new credit
facilities in the total amount of $150 million for Eureka Hunter Pipeline, LLC, or Eureka Hunter, our wholly-owned subsidiary which owns and operates our Eureka Hunter Pipeline System. The Eureka Hunter credit facilities were established to fund
Eureka Hunters pipeline development capital expenditures on a non-recourse basis to Magnum Hunter. The Eureka Hunter credit facilities consist of (i) a revolving credit facility in an aggregate principal amount of up to $100 million (with
an initial committed amount of $25 million) and (ii) a $50 million term loan facility, both of which closed in August 2011. These facilities are referred to as our Eureka Hunter Revolver and our Eureka Hunter Term Loan, and collectively as the
Eureka Hunter Credit Facilities.

Marcellus Shale Gas Processing Arrangements

In October 2011, Triad Hunter entered into certain midstream services agreements with MarkWest Liberty Midstream & Resources, L.L.C. and an affiliate, collectively MarkWest Liberty, pursuant to
which MarkWest Liberty will provide long-term gas processing and related services for natural gas produced in northwest West Virginia by both Triad Hunter and other producers that is gathered through our Eureka Hunter Pipeline System. In October
2011, Eureka Hunter and MarkWest Liberty entered into a mutual cooperation agreement whereby both companies agreed to jointly develop natural gas-related services to support Marcellus Shale producers in a significant geographic area in northwest
West Virginia. Pursuant to this agreement, Eureka Hunter sold its 200 mmcfe per day capacity Thomas Russell cryogenic natural gas processing plant, which was then under construction, to MarkWest Liberty. MarkWest Liberty intends to install this new
plant, the Mobley 2 plant, adjacent to MarkWest Libertys 120 mmcfe per day capacity natural gas processing plant, the Mobley 1 plant, near Logansport, West Virginia. We anticipate that the Mobley 1 plant will be in commercial operation during
the third quarter of 2012 and the Mobley 2 plant will be in commercial operation during the fourth quarter of 2012. MarkWest Liberty will also provide natural gas liquids handling and fractionation services for the Mobley plant complex
products. These agreements with MarkWest Liberty will allow Eureka Hunter to offer third party producers in the Marcellus Shale not only gas gathering services through our Eureka Hunter Pipeline System, but also access to natural gas processing at
MarkWest Libertys Mobley complex.

Series C and Series D Preferred Stock

In January 2011, we completed our at the market, or ATM, offering of our Series C Cumulative Perpetual Preferred Stock, or Series C Preferred Stock, when we sold the last remaining authorized
shares of the Series C Preferred Stock. This sale completed the funding of the Series C Preferred Stock at its authorized limit of 4,000,000 shares, or $100 million based on its liquidation preference of $25 per share.

In March 2011, we completed an initial public offering of 400,000 shares of our Series D Perpetual Preferred Stock, or Series D Preferred Stock, for net
proceeds of approximately $17.9 million. In March 2011, we also



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commenced the sale of shares of our Series D Preferred Stock pursuant to an ATM offering. As of February 27, 2012, we have sold an aggregate of 1,676,556 shares of Series D Preferred Stock
pursuant to the ATM offering for net proceeds of approximately $78.2 million. As of February 27, 2012, we have received total net proceeds from the issuance of our Series D Preferred Stock of approximately $96.1 million.

Summary of Proved Reserves and Wells

SEC Case Reserve Summary



|                         |  |                      |             |  |            |   |       |              |  |     |                 |   |  |  |       |  |  |  |         | 
|------------------------ |  | -------------------- | ----------- |  | ---------- | - | ----- | ------------ |  | --- | --------------- | - |  |  | ----- |  |  |  | ------- | 
|                         |  | At December 31, 2011 |            
|                         |  | ProvedReserves(a)    |             |  |            |   |       | %Oil/Liquids |  |     | ProductiveWells |  
|Area                     |  |                      | PV-10(b)(c) |  |            |   | Gross |              |  | Net |                
|                         |  | (mmboe)              |             |  | (Millions) |   |       |              |  |     |                 |   |  |  |      
|Eagle Ford Shale(d)      |  |                      | 6.2         |  |            | $ | 110.7 |              |  |     | 87              |   |  |  | 36    |  |  |  | 10.8    | 
|Appalachian Basin        |  |                      | 29.9        |  |            |   | 295.7 |              |  |     | 27              |   |  |  | 3,112 |  |  |  | 2,257.3 | 
|Williston Basin          |  |                      |             |  |            |   |       |              |  |     |                 |   |  |  |       |  |  |  |         | 
|Williston Hunter U.S.(e) |  |                      | 5.7         |  |            |   | 120.4 |              |  |     | 98              |   |  |  | 66    |  |  |  | 59.9    | 
|Williston Hunter Canada  |  |                      | 3.1         |  |            |   | 90.1  |              |  |     | 88              |   |  |  | 262   |  |  |  | 80.6    | 
|                         |  |                      |             |  |            |   |       |              |  |     |                 |   |  |  |       |  |  |  |         | 
|Total                    |  |                      | 44.9        |  |            | $ | 616.9 |              |  |     | 48              | % |  |  | 3,476 |  |  |  | 2,408.6 | 
|                         |  |                      |             |  |            |   |       |              |  |     |                 |   |  |  |       |  |  |  |         | 



|(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 $96.19 per barrel of oil and $4.11 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 for our proved reserves at December 31, 2011 was $474 million. See Item 2. PropertiesNon-GAAP Measures;
Reconciliations for a definition of pre-tax PV-10 and a reconciliation of our standardized measure to our pre-tax PV10 value.
|--- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

|(d) | Includes certain other properties described under Item 2. PropertiesOther Properties below.
|--- | ----------------------------------------------------------------------------------------------

|(e) | For purposes of this table, the Williston Hunter U.S. information includes our North Dakota legacy properties as described under Item 2. PropertiesWilliston
BasinNorth Dakota Legacy Properties below.
|--- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

NYMEX Futures Strip Case Reserve Summary



|                         |  |                      |             |  |            |   |       |              |  |     |                  |  |  |  |       |  |  |  |         | 
|------------------------ |  | -------------------- | ----------- |  | ---------- | - | ----- | ------------ |  | --- | ---------------- |  |  |  | ----- |  |  |  | ------- | 
|                         |  | At December 31, 2011 |            
|                         |  | ProvedReserves(a)    |             |  |            |   |       | %Oil/Liquids |  |     | Productive Wells | 
|Area                     |  |                      | PV-10(b)(c) |  |            |   | Gross |              |  | Net |                 
|                         |  | (mmboe)              |             |  | (Millions) |   |       |              |  |     |                  |  |  |  |      
|Eagle Ford Shale(d)      |  |                      | 6.1         |  |            | $ | 105.4 |              |  |     | 87               |  |  |  | 36    |  |  |  | 10.9    | 
|Appalachian Basin        |  |                      | 30.2        |  |            |   | 298.5 |              |  |     | 27               |  |  |  | 3,112 |  |  |  | 2,257.2 | 
|Williston Basin          |  |                      |             |  |            |   |       |              |  |     |                  |  |  |  |       |  |  |  |         | 
|Williston Hunter U.S.(e) |  |                      | 5.7         |  |            |   | 112.6 |              |  |     | 98               |  |  |  | 66    |  |  |  | 59.9    | 
|Williston Hunter Canada  |  |                      | 3.1         |  |            |   | 84.4  |              |  |     | 87               |  |  |  | 262   |  |  |  | 80.6    | 
|                         |  |                      |             |  |            |   |       |              |  |     |                  |  |  |  |       |  |  |  |         | 
|Total                    |  |                      | 45.1        |  |            | $ | 600.9 |              |  |     | 48               |  |  |  | 3,476 |  |  |  | 2,408.6 | 
|                         |  |                      |             |  |            |   |       |              |  |     |                  |  |  |  |       |  |  |  |         | 



|(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.
|--- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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|(b) | The prices used to calculate this measure were the NYMEX futures strip prices as of December 31, 2011.
|--- | ------------------------------------------------------------------------------------------------------

|(c) | The standardized measure for our proved reserves at December 31, 2011 was $477 million. See Item 2. PropertiesNon-GAAP Measures;
Reconciliations for a definition of pre-tax PV-10 and a reconciliation of our standardized measure to our pre-tax PV-10 value.
|--- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

|(d) | Includes certain other properties described under Item 2. PropertiesOther Properties below.
|--- | ----------------------------------------------------------------------------------------------

|(e) | For purposes of this table, the Williston Hunter U.S. information includes our North Dakota legacy properties as described under Item 2. PropertiesWilliston
BasinNorth Dakota Legacy Properties below.
|--- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

Business Strategy

Our business strategy is to create significant value for our stockholders by growing reserves, production volumes and cash flow through a combination of
efficient development of our properties and strategic acquisitions. Key elements of our business strategy include:

Focus on Substantial
Inventory in 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, the Utica Shale, the Eagle Ford Shale and the Bakken Shale/Three
Forks/Sanish formations. As of February 27, 2012, the Company had over 489,757 gross acres (170,426 net acres) and approximately 4,100 identified drilling locations in these core areas. With improvements in drilling and completion
technologies over the past five years, the development of unconventional resources in these areas has become economic. We believe that these areas represent the potential for the best return on invested capital for our stockholders.

Strategic Acquisitions in Core AreasThe Company intends to continue to opportunistically acquire additional acreage and reserves
in our core areas. In the past year, we significantly expanded our positions in the Williston Basin, Marcellus Shale, Eagle Ford Shale and southern Appalachian Basin through several acquisitions, representing over $570 million in total transaction
value. We also recently expanded our leasehold position in the Utica Shale in Ohio. We believe that our acquisition and operational track record, as well as our extensive industry relationships, will provide for continued growth opportunities
through strategic acquisitions in our core areas.

Focus on Development of Oil and Liquids Rich ResourcesWe plan to focus our
development and acquisition efforts primarily on oil and liquids rich projects, including (i) oil reserves in the Williston Basin (Bakken Shale/Three Forks/Sanish formations), (ii) oil reserves in the oil window of the Eagle Ford Shale in
south Texas and (iii) liquids rich gas (1,250 plus btu) in the Marcellus Shale and the Utica Shale areas of northwest West Virginia and southeastern Ohio.

Utilize Expertise in Unconventional Resource Plays to Continue to Improve Rates of ReturnWe use state of the art, advanced drilling, completion and production technologies, allowing us the
best opportunity for cost-effective drilling, completion, and production success. Our technical team regularly reviews the most current technologies and 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.

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. During the past
three years, we have significantly increased the number of wells that we operate and control. As of December 31, 2011, we operated approximately 82% of our proved reserves. Approximately 70% of our 2012 preliminary capital expenditure budget
relates to our operated properties. We have experienced increasingly robust drilling and completion results, and hence rates of return, in all our operated areas.



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Allocate Capital Expenditures to Projects With Highest Rates of ReturnThe Companys large
and diverse inventory of economical properties allows management to allocate capital to areas and projects representing the potential for the highest rates of return. In 2012, we expect to allocate a higher percentage of capital expenditures to
liquids-related projects due to their better relative rates of return under current commodity price levels for oil, natural gas, and natural gas liquids.

Maintain Financial FlexibilityThe Company utilizes what it considers to be appropriate amounts of debt and equity to maintain manageable debt and leverage ratios, while at the same time
maximizing liquidity and providing above average returns on equity. The Company seeks to maintain financial flexibility so that it can pursue organic growth and acquisitions without stressing its leverage ratios. At December 31, 2011, the
Companys net debt to total capitalization ratio, excluding our existing indebtedness under the Eureka Hunter Credit Facilities, was 28.4%. The Company seeks to manage its leverage while minimizing dilution through the timely and strategic
issuance of nonconvertible preferred stock and common stock. The Company has issued a total of $100 million of its nonconvertible Series C Preferred Stock and, as of February 27, 2012, a total of $103.8 million of its nonconvertible Series D
Preferred Stock (in each case, based on their respective liquidation preferences). In addition, we have established the Eureka Hunter Credit Facilities to fund substantially all of Eureka Hunters 2012 financing needs, and these facilities are
non-recourse to Magnum Hunter.

Continued Development of Our Eureka Hunter Pipeline SystemWe are continuing the commercial
development of our Eureka Hunter Pipeline System to support the development of our existing and anticipated future Marcellus Shale and Utica Shale acreage positions as well as the increasing gathering needs of third party producers. We are
constructing the Eureka Hunter Pipeline System using 20-inch and 16-inch high-pressure pipeline with initial throughput capacity of approximately 300 mmcfpd. As of February 27, 2012, we have completed approximately 45 miles of the Eureka Hunter
Pipeline System. We have also entered into a processing agreement with MarkWest Liberty to provide us with gas processing at the Mobley 2 plant, which is currently anticipated to be completed during the fourth quarter of 2012. The Eureka Hunter
Pipeline System will enable us 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.

Competitive Strengths

We believe that our key competitive strengths include:

Experienced Management
Team With Substantial Experience in Unconventional Resource PlaysOur senior management team, on average, has over 25 years of experience in the oil and gas industry. Senior management has extensive experience in managing,
financing and operating public oil and gas companies. Magnum Hunter Resources, Inc., 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 over $30 billion in financing transactions and acquisitions in the oil
and gas industry, and our personnel have extensive expertise in all key operational disciplines in our core unconventional resource plays. Over the last three years, we have significantly increased the depth of our management team, together with our
knowledge of unconventional resource plays.

Balanced Long-Lived Asset Base with Substantial Oil and Liquids ReservesAs of
February 27, 2012, we owned interests in approximately 3,476 gross (2,408 net) productive wells across approximately 958,465 gross (560,072 net) mineral acres, substantially all of which are in the Marcellus Shale, the Utica Shale,
the Eagle Ford Shale, the Williston Basin and the southern Appalachian Basin. We believe this geographic mix of properties, combined with our continuing business strategy of developing and acquiring properties in our core resource areas of the
Marcellus Shale, Utica Shale, Eagle Ford Shale and Williston Basin, present us with multiple growth opportunities. Our R/P ratio life is approximately 22.7 years based on year-end 2011 proved reserves of 44.9 mmboe. As of December 31,
2011, approximately 48% and 43% of our proved reserves and production, respectively, were oil and natural gas liquids.



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Substantial Acreage Position and Drilling Inventory in Core Resource AreasAs of
February 27, 2012, we had over 170,000 net acres in our core resource areas, including approximately 58,426 net acres in the Marcellus Shale, 61,151 net acres in the Utica Shale (a portion of which acreage overlaps our Marcellus Shale
acreage), 24,000 net acres in the Eagle Ford Shale and 75,814 net acres in the Williston Basin (Bakken Shale/Three Forks/Sanish formations). We have identified an inventory of approximately 4,100 gross (1,400 net) drilling locations in
these core areas, with only approximately 9% currently booked as proved reserves.

Improving Results in All Core Resource AreasAs
a result of improved drilling and completion techniques, our IP rates and rates of return have been steadily increasing. Our average daily production volumes for 2011 were 5,510 boepd, which represent a 324% increase from those volumes for 2010.
Improvements in our IP-24 hour rates for wells operated by us include: (i) IP-24 hour rates for the most recently completed six wells operated by the Company in the Eagle Ford Shale have averaged in excess of 1,602 boepd; (ii) IP-24 hour
rates for the most recently completed seven wells operated by the Company in the Marcellus Shale have averaged in excess of 9,914 mmcfpd; and (iii) IP-24 hour rates for the most recently completed five wells operated by the Company in the
Bakken Shale/Three Forks/Sanish formations have averaged in excess of 500 boepd.

Operated AssetsWe operate a substantial
majority of our assets. As of December 31, 2011, we operated approximately 81% of our producing wells and 82% of our proved reserves. Approximately 70% of our 2012 preliminary capital expenditure budget relates to properties that we operate. As
a result, we have control over the timing, allocation and amount of a substantial portion of our planned 2012 capital expenditures, which allows us the flexibility to reallocate these expenditures depending on commodity prices, rates of return and
industry conditions. We have also demonstrated increasingly robust drilling and completion results in our operated areas.

Marcellus
Shale/Utica Shale Infrastructure AssetsThe Company owns approximately 207 miles of pipeline, gathering systems and/or rights-of-way, which make up our Eureka Hunter Pipeline System, to provide critical takeaway capacity and third
party gathering in the capacity-constrained Marcellus Shale and Utica Shale areas of northwest West Virginia and southeastern Ohio. In addition, we own and operate five drilling rigs and various oil field service equipment, which contribute to the
efficient operation and development of our assets in the Marcellus Shale and Utica Shale areas. We believe these assets provide a significant cost and competitive advantage for our activities in these areas.

2012 Preliminary Capital Budget

We
estimate our preliminary capital budget for fiscal year 2012 to be approximately $150 million for our upstream operations and approximately $50 million for our midstream operations (excluding, in each case, any budgeted amounts for operations that
may be acquired pursuant to acquisitions).

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 hedging 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, fracing and other oilfield services and equipment and, with respect to our midstream operations, the acquisition of commitments from third party producers for the
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.



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The prices of our products are controlled by the world oil market and North American natural gas markets;
thus, competitive pricing behavior in this regard is considered unlikely; however, competition in the oil and natural gas exploration industry exists in the form of competition to acquire the most promising properties and obtain the most favorable
prices for the costs of drilling and completing wells. Competition for the acquisition of oil and gas properties is intense with many properties available in a competitive bidding process in which we may lack technological information or expertise
available to other bidders. Therefore, we may not be successful in acquiring and developing profitable properties in the face of this competition. Our ability to acquire additional properties in the future will depend upon our ability to evaluate
and select suitable properties and to consummate transactions in an efficient manner even in a highly competitive environment. See Item 1A. Risk FactorsCompetition in the oil and natural gas industry is intense, which may adversely
affect our ability to compete.

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

Operating Hazards and Risks

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

Our operations are subject to hazards and
risks inherent in drilling for and producing and gathering and transporting oil and natural gas, such as fires, natural disasters, explosions, encountering formations with abnormal pressures, blowouts, craterings, pipeline ruptures and spills, any
of which can result in the loss of hydrocarbons, environmental pollution, personal injury claims and 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.

Our Company is 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



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

We commonly use hydraulic fracturing as part of our operations. Hydraulic fracturing
typically is regulated by state oil and natural gas commissions, but the U.S. federal 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, including Texas, are also considering implementing, or in some instances, have implemented, new regulations pertaining to hydraulic fracturing, including the disclosure of chemicals used in
connection therewith. These regulatory requirements may result in additional costs and operational restrictions and delays, which could have an adverse impact on our business, financial condition, results of operations and cash flows. See Item
1A. Risk FactorsFederal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.

Climate change has become the subject of an important public policy debate. Climate change remains a complex issue, with some scientific research
suggesting that an increase in greenhouse gas emissions, or GHGs, may pose a risk to society and the environment. The oil and natural gas exploration and production industry is a source of certain GHGs, namely carbon dioxide and methane. The
commercial risk associated with the production of fossil fuels lies in the uncertainty of government-imposed climate change legislation, including cap and trade schemes, and regulations that may affect us, our suppliers and our customers. The cost
of meeting these requirements may have an adverse impact on our business, financial condition, results of operations and cash flows, and could reduce the demand for our products. See Item 1A. Risk FactorsClimate change legislation
or regulations restricting emissions of greenhouse gases could result in increased operating costs and reduced demand for the oil, natural gas and natural gas liquids that we produce.



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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 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, as 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

At December 31, 2011, we had 305 full-time employees, of which 16 were
officers. None of our employees is represented by a union. Management considers our relations with employees to be very good.

Facilities

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

Our Triad Hunter offices consist of approximately 9,000
square feet of leased office space in Marietta, Ohio, under leases that expire in 2012, as well as field offices in Kentucky and West Virginia. Our Magnum Hunter Production 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 the Company in Lexington, Kentucky. 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 2014. 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 2014. We also own a commercial office building in Grapevine, Texas
containing approximately 10,200 square feet, which houses our accounting functions.

Segment Reporting

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 13 to our consolidated financial statements, Other InformationSegment Reporting (Unaudited), which is incorporated to this Item 1 by reference.

Available Information

Our principal executive offices are located at 777 Post Oak Blvd.,
Suite 650, Houston, Texas 77056. Our telephone number 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 report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and, if applicable, amendments to those reports filed or furnished
pursuant to Section 13(a) of 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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|Item 1A. | RISK FACTORS
|-------- | ------------

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

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 recent years. Unemployment rates remain very high and businesses and consumer confidence levels have not yet fully recovered to pre-recession levels. In addition, more volatility may occur before a sustainable, yet lower, growth
rate is achieved. Global economic growth drives demand for energy from all sources, including for oil and natural gas. A lower future economic growth rate will result in decreased demand for our crude oil and natural gas production as well as lower
commodity prices, which will reduce our cash flows from operations and our profitability.

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

The prices we receive for our oil and natural gas production heavily influence our revenue, profitability, access to capital and future rate of growth. Oil and natural gas are commodities, and therefore
their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil and natural gas have been extremely volatile. These markets will likely continue to be volatile in the
future. The prices we receive for our production, and the levels of our 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



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decline in oil or natural gas prices may materially and adversely affect our future business, financial condition, results of operations, liquidity or ability to finance planned capital
expenditures.

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

Since we entered the oil and gas business in April 2005, through December 31, 2011, we had incurred a cumulative net loss from
operations of $138.1million. 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 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 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 little operating history upon which
to judge our business strategy, our management team or our current operations.

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 recently acquired businesses could negatively impact our future business and financial results.

The NGAS and NuLoch acquisitions are our largest acquisitions to date and as such may consume a significant amount of our management resources. Further, the acquisition of NuLoch represents an expansion
of our operations into a new geographic core area, with 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 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 businesses of the acquired entities 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.



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Upon the completion of the NuLoch acquisition, we expanded our operations into Canada,
which subjects us to additional regulations and risks from foreign operations, including currency fluctuations, which could impact our financial position and results of operations.

Prior to the completion of the NuLoch acquisition, we operated solely in the U.S., primarily in the Appalachian Basin, the Williston Basin and south Texas. Upon the consummation of the NuLoch acquisition,
we expanded our operations into portions of Canada, which exposes 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 in order for us to continue our
exploration and midstream activities, including meeting certain drilling obligations under our existing lease obligations and expanding our pipeline facilities.

Our cash flow from our reserves, if any, 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 and gathering system capacity constraints.

Market conditions or the restriction in the availability of satisfactory oil and natural gas transportation arrangements may hinder
our access to oil and natural gas markets or delay our production. The availability of a ready market for our oil and natural gas production depends on a number of factors, including the demand for and supply of oil and natural gas and the proximity
of reserves to pipelines and terminal facilities. Our ability to market our production depends in substantial part on the availability and capacity of gathering systems, pipelines and processing facilities owned and operated by third parties. Our
failure to obtain such services on acceptable terms could materially harm our business. Our productive properties may be located in areas with limited or no access to pipelines, thereby necessitating delivery by other means, such as trucking, or
requiring compression



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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, Eagle Ford Shale and Bakken Shale/Three Forks/Sanish areas proves to be successful, the amount of oil
and natural gas being produced by us and others could exceed the capacity of the various gathering and intrastate or interstate transportation pipelines currently available in these areas. If this occurs, it will be necessary for new pipelines and
gathering systems to be built. Because of the current economic climate, certain pipeline projects that are planned for the Marcellus Shale, Utica Shale, Eagle Ford Shale and Bakken Shale/Three Forks/Sanish areas may not occur for lack of financing.
In addition, capital constraints could limit our ability to build intrastate gathering systems, such as our Eureka Hunter Pipeline 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 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 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 and personnel in our 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 pipeline and conduct other operations that we currently have planned and
budgeted, causing us to miss our forecasts and projections.



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

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



| |  |  | the 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 conducted a portion of its operations through drilling partnerships, and we recently sponsored one drilling partnership, 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 drilling partnerships with third parties. Our Magnum Hunter Production subsidiary recently completed a
sponsored drilling partnership and plans to sponsor an additional drilling and/or income partnership or partnerships in 2012. Under this 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 third parties may have obligations that
are important to the success of the joint venture, such as the obligation to pay substantial carried costs pertaining to the joint venture and to pay their share of capital and other costs of the joint venture. The performance of these third party
obligations, including the ability of the third parties to satisfy their obligations under these arrangements, is outside our control. If these parties do not satisfy their obligations under these arrangements, our business may be adversely
affected. The failure to continue our drilling and/or income partnerships or other joint venture projects or to resolve disagreements with our drilling and/or income partnership partners 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 development, exploration 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, transportation, processing and acquisition of, oil and natural gas reserves. To date, we have
financed capital expenditures primarily with proceeds from bank borrowings, cash generated by operations and proceeds from preferred and common stock equity offerings. We intend to finance our future capital expenditures with a combination of the
sale of common and preferred equity, asset sales, cash flow from operations and current and new financing arrangements with our banks. Our cash flow from operations and access to capital is subject to a number of variables, including:



| |  |  | our proved reserves;
| | - |  | --------------------



| |  |  | the amount of oil and natural gas we are able to produce from existing wells;
| | - |  | -----------------------------------------------------------------------------



| |  |  | the prices at which oil and natural gas are sold;
| | - |  | -------------------------------------------------



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| |  |  | 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 Pipeline
System.
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------

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 credit facilities contain covenants that restrict our
ability to, among other things, incur indebtedness, grant liens, make certain restricted payments, change the nature of our business, acquire or make expenditures for oil and gas properties outside of the U.S. and Canada, dispose of our assets or
enter into mergers, consolidations or similar transactions, make investments, loans or advances, pay dividends on our outstanding stock, 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 significant
insurance coverage against some, but not all, potential losses to protect against the risks we foresee. We do not carry business interruption insurance. We may elect not to carry certain types or amounts of insurance if our management believes that
the cost of available insurance is excessive relative to the risks presented. In addition, it is not possible to insure fully against pollution and environmental risks.

We are not insured against all risks. Losses and liabilities arising from uninsured and underinsured events could materially and adversely affect our business, financial condition, 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, including the possibility of pipeline leaks, breaks and ruptures, pipeline damage due to natural
hazards, such as ground movement and weather, 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 partnering and consultant arrangements.

We had a total of 309 full-time employees as of February 27, 2012. Despite this number of employees, we expect that we will continue to require the
services of independent consultants and contractors to perform various



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professional services, including reservoir engineering, land, legal, environmental and tax services. We will also pursue alliances with partners in the areas of geological and geophysical
services and prospect generation, evaluation and leasing. Our dependence on third party consultants and service providers creates a number of risks, including but not limited to:



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



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

If we experience significant delays in obtaining the services of such third parties or poor performance by such parties,
our results of operations 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 and senior management. Our business or prospects could be
adversely affected if any of these persons does not continue in their management role with us and we are unable to attract and retain qualified replacements. Additionally, we do not presently carry key person 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 analyses,
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;
| | - |  | ---------------------------



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| |  |  | 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 our internal 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 and securing trained
personnel. Many of our competitors possess and employ financial, technical and personnel resources substantially greater than ours, which can be particularly important in the areas in which we operate. Those companies may be able to pay more for
productive oil and natural gas properties and exploratory prospects and to evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. Our ability to acquire additional prospects and
to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in 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, attracting and retaining quality personnel and raising additional capital.

We have limited experience in drilling wells to the Marcellus Shale, Utica Shale, Eagle Ford Shale and Bakken Shale/Three
Forks/Sanish 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 experience in the drilling and completion of Marcellus Shale, Utica Shale, Eagle Ford Shale and
Bakken Shale/Three Forks/Sanish formations 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, Eagle Ford Shale and Bakken Shale/Three Forks/Sanish 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.



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

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

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

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

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

As of February 27, 2012, our outstanding indebtedness was
approximately $340 million (which included borrowings under the MHR Senior Revolving Credit Facility, the MHR Term Loan Facility and the Eureka Hunter Term Loan). 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 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;
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | 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.
| | - |  | --------------------------------------------------------------------------------------------------------------------------------------------------

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.



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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 in the future enter into
derivative contracts in order 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 hedging agreement 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 and our MHR Term Loan Facility, the percentage of our total production volumes with respect to which we will be allowed to enter into derivative contracts is limited, and we
therefore retain the risk of a price decrease for our remaining production volumes. Information as to these 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.

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

There is a risk that we will be required to further write down the carrying value of our oil and gas properties, which would reduce our earnings and
stockholders equity. 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 capitalized costs of our oil and gas
properties may not exceed the estimated future net cash flows from our properties. If capitalized costs exceed future cash flows, we write down the costs of the properties to our estimate of fair market value. Any such charge will not affect our
cash flow from operating activities, but will reduce our earnings and stockholders equity. 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.

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

The
application of the successful efforts method of accounting requires managerial judgment to determine the proper classification of wells designated as developmental or exploratory, which will ultimately determine the proper accounting treatment of
the costs incurred. The results from a drilling operation can take considerable time to analyze and the determination that commercial reserves have been discovered requires both judgment and industry experience. Wells may be completed that are
assumed to be productive but may actually deliver oil and gas in quantities insufficient to be economic, which may result in the abandonment of the wells at a later

date. 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



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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 Company incurred an impairment charge
related to certain proved oil and gas properties acquired as part of our acquisition of NGAS in 2011 totaling $21.8 million due to a significant decline in natural gas prices at December 31, 2011. Impairment of proved oil and gas
properties was calculated on a field by field basis under the successful efforts accounting method. An impairment was recorded based upon the estimated fair value of a 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. We also incurred impairment charges associated with our
undeveloped acreage of $306,000 and $802,000 in our Eagle Ford Shale and Appalachian Basin regions, respectively, due to expiring acreage that we chose not to develop.

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.

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

Our MHR Senior Revolving Credit Facility and our MHR Term Loan Facility contain certain covenants that, among other things, restrict our ability to, with
certain exceptions:



| |  |  | incur indebtedness;
| | - |  | -------------------



| |  |  | grant liens;
| | - |  | ------------



| |  |  | make certain restricted payments;
| | - |  | ---------------------------------



| |  |  | change the nature of our business;
| | - |  | ----------------------------------



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



| |  |  | dispose of our assets or enter into mergers, consolidations or similar transactions;
| | - |  | ------------------------------------------------------------------------------------



| |  |  | make investments, loans or advances;
| | - |  | ------------------------------------



| |  |  | pay dividends on our outstanding stock;
| | - |  | ---------------------------------------



| |  |  | enter into transactions with affiliates;
| | - |  | ----------------------------------------



| |  |  | create new subsidiaries; and
| | - |  | ----------------------------



| |  |  | enter into certain derivative 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 of not less than 2.5 to 1.0;
| | - |  | -----------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | a debt to EBITDAX ratio of not more than 4.25 to 1.0 for the fiscal quarter ended December 31, 2011, and of not more than 4.00 to 1.0 commencing
with the fiscal quarter ending March 31, 2012; and
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | a ratio of consolidated current assets to consolidated current liabilities of not less than 1.0 to 1.0 or of not less than 1.05 to 1.0 commencing with
the fiscal quarter ending June 30, 2012 if the amounts owed under the MHR Term Loan Facility have not been repaid in full as of such date.
| | - |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

Our MHR Term Loan Facility also requires us to satisfy certain financial covenants, including maintaining:



| |  |  | an EBITDAX to interest ratio of not less than 2.125 to 1.0;
| | - |  | -----------------------------------------------------------



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| |  |  | a debt to EBITDAX ratio of not more than 5.00 to 1.0 for the fiscal quarter ended December 31, 2011, and of not more than 4.75 to 1.0 commencing
with the fiscal quarter ending March 31, 2012; and
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | a ratio of our total proved reserves to our indebtedness under our MHR Senior Revolving Credit Facility and our MHR Term Loan Facility of not less than
1.5 to 1.0.
| | - |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------

The Eureka Hunter Revolver and the Eureka Hunter Term Loan also require Eureka Hunter Pipeline, LLC, our
wholly-owned subsidiary, to comply with certain 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 obtained, would be on terms acceptable to us.

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

Certain of our subsidiaries, including PRC Williston, LLC, Triad Hunter, LLC, Eagle Ford Hunter, Inc., Magnum Hunter Production, Inc., NGAS Hunter, LLC, Williston Hunter Canada, Inc. and Williston Hunter,
Inc., have each guaranteed the performance of our obligations under our MHR Senior Revolving Credit Facility and our MHR Term Loan Facility, and our obligations under these credit facilities have been collateralized through the grant of first and
second priority liens on substantially all of the assets held by Magnum Hunter Resources Corporation and these restricted subsidiaries. An event of default under either of these credit facilities will constitute an event of default under the other.

Eureka Hunters obligations under the Eureka Hunter Revolver and the Eureka Hunter Term Loan have been guaranteed by Eureka
Hunters subsidiary, and have been collateralized through the grant of first and second priority liens on substantially all of the assets held by Eureka Hunter and its subsidiary. An event of default under either of these credit facilities will
constitute an event of default under the other. The Eureka Hunter Revolver and the Eureka Hunter Term Loan are non-recourse to Magnum Hunter Resources Corporation and to its restricted subsidiaries under the MHR Senior Revolving Credit Facility and
MHR Term Loan Facility.

Our ability to meet our debt obligations under these credit facilities will depend on the future performance of our
properties, which will be affected by financial, business, economic, regulatory and other factors, many of which we are unable to control. Our failure to service any such debt could result in a default under the related credit facility and the
credit facility under which such default is a cross-default, which could result in the loss of our ownership interests in the secured properties and otherwise materially adversely affect our business, financial condition and results of operations.

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

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



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

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

Certain 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.

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, including Texas, are also considering
implementing, or in some instances, have implemented, new regulations pertaining to hydraulic fracturing, including the disclosure of chemicals used in connection therewith. In May 2011, a bill was passed by the Texas legislature that will require
hydraulic fracturing operators to disclose the chemicals used in the fracturing process on a well-by-well basis. Further, various municipalities in several states, including Pennsylvania, West Virginia and Ohio, have passed ordinances which seek to
prohibit hydraulic fracturing. We believe that we follow applicable standard industry practices and legal requirements for groundwater protection in our hydraulic fracturing activities. Nonetheless, if new or more stringent federal, state, or local
legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of
exploration, development, or production activities, and perhaps even be precluded from drilling wells.



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In addition, certain governmental reviews are either underway or being proposed that focus on environmental
aspects of hydraulic fracturing practices. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices, and a committee of the U.S. House of Representatives has conducted an
investigation of hydraulic fracturing practices. The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, with initial results expected to be available by late 2012 and final
results by 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.

To our
knowledge, there have been no citations, suits, or contamination of potable drinking water arising from our 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 ngls 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.



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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 ngl prices, drilling and operating expenses, capital expenditures, taxes and availability of funds.

Actual future production, oil, natural gas and ngl 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 ngl prices and other factors, many of which are beyond our control.

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

Regulatory authorities exercise considerable discretion in the timing and scope of 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 or production 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 production of oil or natural gas, pipeline construction, gas processing facilities and associated well production 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 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.



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

The Dodd-Frank Wall Street Reform and Consumer
Protection Act, or the Act, was enacted in 2010. The Act provides for new statutory and regulatory requirements for derivative transactions, including certain oil and gas hedging transactions involving swaps. In particular, the Act includes a
requirement that certain hedging transactions involving swaps be cleared and exchange-traded and a requirement to post cash collateral for non-cleared swap transactions, although, at this time, it is unclear which transactions will ultimately be
required to be cleared and exchange-traded or which counterparties will be required to post cash collateral with respect to non-cleared swap transactions. The Act provides for a potential exception from the clearing and exchange-trading requirement
for hedging transactions by commercial end-users, a category of non-financial entities in which we may be included. While the Commodity Futures Trading Commission, or CFTC, and other federal agencies have adopted, and continue to adopt, numerous
regulations pursuant to the Act, many of the key concepts and defined terms under the Act have not yet been delineated by rules and regulations to be adopted by the CFTC and other applicable regulatory agencies. As a consequence, it is difficult to
predict the aggregate effect the Act and the regulations promulgated thereunder may have on our hedging activities. Whether we are required to submit our swap transactions for clearing or post cash collateral with respect to such transactions will
depend on the final rules and definitions adopted by the CFTC. If we are subject to such requirements, significant liquidity issues could result by reducing our ability to use cash posted as collateral for investment or other corporate purposes. A
requirement to post cash collateral could also limit our ability to execute strategic hedges, which would result in increased commodity price uncertainty and volatility in our future cash flows. The Act and related regulations will also require us
to comply with certain futures and swaps position limits and new recordkeeping and reporting requirements, and may also require the counterparties to our derivative instruments to spin off some of their derivatives activities to a separate entity,
which may not be as creditworthy as the current counterparty. The Act and related regulations could also materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our
ability to monetize or restructure existing derivative contracts, and increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the legislation and regulations, our results of operations may become
more volatile and our cash flows may be less predictable.

Acquired properties may not be worth what we pay due to
uncertainties in evaluating 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 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 every well, and even when we inspect a well we may not discover structural, subsurface, or environmental problems that may exist or arise. We may not be entitled to contractual indemnification for pre-closing liabilities,
including environmental liabilities, and our contractual indemnification may not be effective. Often, we 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.



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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 plan. 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 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 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 increase our profits.

The successful acquisition of producing properties requires an assessment of numerous
factors beyond our control, including, without limitation:



| |  |  | 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, and structural and environmental problems are not necessarily observable even when an inspection is made.



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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 south Texas, West
Virginia, Ohio, Kentucky, North Dakota and Saskatchewan regions, we may pursue acquisitions of properties located in other geographic areas.

Our current Eureka Hunter gathering 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 Pipeline System, which provides or is anticipated 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 completion of construction, securing regulatory and governmental approvals, resolving any land management issues and connecting the pipeline to the producing sources of natural
gas.

The construction, operation and maintenance of the Eureka Hunter Pipeline 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 for neighboring landowners and other third
parties to 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 Pipeline System could
subject us to substantial liabilities arising from environmental cleanup, restoration costs and natural resource damages, claims made by neighboring 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,
petrophysical 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, Eagle Ford Shale, Bakken Shale and other
areas depend on data obtained through geoscientific, petrophysical 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



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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.

Risks Related to Our Equity Securities

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

The price of our common stock has fluctuated substantially since it first became listed on a national securities exchange in August
2006. From August 30, 2006 to February 27, 2012, the trading price at the close of the market (initially the American Stock Exchange and currently the NYSE) of our common stock ranged from a low of $0.20 per share to a high of $8.57 per
share. We expect our common stock to continue to be subject to fluctuations as a result of a variety of factors, including factors beyond our control. These factors include:



| |  |  | changes in oil and natural gas prices;
| | - |  | --------------------------------------



| |  |  | variations in quarterly drilling, recompletions, acquisitions and operating results;
| | - |  | ------------------------------------------------------------------------------------



| |  |  | changes in financial estimates by securities analysts;
| | - |  | ------------------------------------------------------



| |  |  | changes in market valuations of comparable companies;
| | - |  | -----------------------------------------------------



| |  |  | additions or departures of key personnel;
| | - |  | -----------------------------------------



| |  |  | the level of our overall indebtedness;
| | - |  | --------------------------------------



| |  |  | future issuances of our common stock and related dilution to existing stockholders; and
| | - |  | ---------------------------------------------------------------------------------------



| |  |  | the other risks and uncertainties described in this Risk Factors section and elsewhere in this report.
| | - |  | --------------------------------------------------------------------------------------------------------

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

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

Our common stock is traded on the NYSE under the symbol MHR. On February 27, 2012, the last reported sale
price of our common stock on the NYSE was $6.94 per share. The present volume of trading in our common stock may not always provide investors sufficient liquidity in the event they wish to sell large blocks of common stock. There can be no assurance
that an active market for our common stock will be available for trading in large volumes. In addition, the stock market in general, and early stage public companies in particular, have experienced extreme price and volume fluctuations that have
often been unrelated or disproportionate to the operating performance of such companies. If we are unable to further develop an active market for our common stock, our stockholders may not be able to sell our common stock at prices they consider to
be fair or at times that are convenient for them, or at all.



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

In the future we may issue additional securities up to our total authorized and unissued
amounts, including shares of our common stock or securities convertible into or exchangeable for our common stock, resulting in the dilution of the ownership interests of our stockholders. We are authorized under our amended and restated certificate
of incorporation to issue up to 250,000,000 shares of common stock and up to 10,000,000 shares of preferred stock with such designations, preferences and rights as may be determined by our board of directors. As of February 27, 2012,
there were 130,565,699 shares of our common stock issued and outstanding, 4,000,000 shares of our Series C Preferred Stock issued and outstanding and 2,076,556 shares of our Series D Preferred Stock issued and outstanding.

We have an effective shelf registration statement from which additional shares of our common stock and other securities can be issued from the time to
time. We may also issue additional shares of our common stock or securities convertible into or exchangeable for our common stock in connection with hiring personnel, future acquisitions or future private placements of our securities for
capital-raising purposes or for other business purposes.

Additionally, we are engaged in the issuance and sale of our common stock and Series
D Preferred Stock from time to time through sales agents pursuant to at the market (ATM) sales agreements between us and the sales agents. Sales of shares of our common stock and Series D Preferred Stock, if any, by the sales agents will
be made in privately negotiated transactions or in any method permitted by law deemed to be an ATM offering as defined in Rule 415 promulgated under the Securities Act, at negotiated prices, at prices prevailing at the time of sale or at prices
related to such prevailing market prices, including sales made directly on the NYSE or NYSE Amex or sales made through a market maker other than on an exchange.

Our amended and restated certificate of incorporation, amended and restated bylaws, and Delaware law contain provisions that could make it more difficult for a third party to acquire us without the
consent of our board of directors and our executive officers, who collectively beneficially owned approximately 8% of the outstanding shares of our common stock as of February 27, 2012.

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



| |  |  | the ability of our board of directors to issue shares of our common stock and preferred stock without stockholder approval;
| | - |  | ---------------------------------------------------------------------------------------------------------------------------



| |  |  | the ability of our board of directors to make, alter, or repeal our bylaws without further stockholder approval;
| | - |  | ----------------------------------------------------------------------------------------------------------------



| |  |  | the requirement for advance notice of director nominations to our board of directors and for proposing other matters to be acted upon at stockholder
meetings;
| | - |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | requiring that special meetings of stockholders be called only by our chairman, by a majority of our board of directors, by our chief executive officer
or by our president; and
| | - |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | allowing our directors, and not our stockholders, to fill vacancies on the board of directors, including vacancies resulting from removal or
enlargement of the board of directors.
| | - |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

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

As of February 27, 2012, our board of directors and executive officers collectively beneficially owned approximately 8% of the outstanding shares of our common stock. Although this is not a majority
of our



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outstanding common stock, these stockholders, acting together, will have the ability to exert substantial influence over all matters requiring stockholder approval, including the election and
removal of directors, any proposed merger, consolidation, or sale of all or substantially all of our assets and other corporate transactions.

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

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

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

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

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

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

As of February 27, 2012, we have issued and sold an aggregate of 4,000,000 shares of our
Series C Preferred Stock and 2,076,556 shares of our Series D Preferred Stock. Under the certificates of designations of the Series C Preferred Stock and Series D Preferred Stock, if we liquidate, holders of our Series C Preferred
Stock and Series D Preferred Stock are entitled to receive the repayment of their original investment, together with any accrued but unpaid dividends, before any payment is made to holders of our common stock.

Our outstanding warrants, which are exercisable for shares of our common stock, may be exercised, which would dilute our existing
common stockholders.

As of December 31, 2011, we had outstanding warrants that have an exercise price of $2.50 and a final
maturity of November 2012 exercisable for an aggregate of 134,177 shares of our common stock; outstanding warrants that have an exercise price of $10.50, a final maturity of October 2013 and can be redeemed by the Company at any time prior to their
maturity for $0.001 per warrant share exercisable for an aggregate of 13,253,267 shares of our common stock; outstanding warrants that have an exercise price of $15.13 and a final maturity of February 2014 exercisable for an aggregate of 97,780
shares of our common stock; and outstanding warrants that have an exercise price of $19.04 and a final maturity of November 2014 exercisable for an aggregate of 40,608 shares of our common stock. Any such exercise will be dilutive to our existing
stockholders.



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

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

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



|Item 1B. | UNRESOLVED STAFF COMMENTS
|-------- | -------------------------

None.



|Item 2. | PROPERTIES
|------- | ----------

Eagle
Ford Shale Properties

The Company made its initial entry into the Eagle Ford Shale through the acquisition of Sharon Resources, Inc. in
October 2009. We subsequently expanded our Eagle Ford Shale position through additional leasing activities and entry into two joint ventures, one with Hunt Oil Company, or Hunt Oil, in May 2010, and the other with a private independent oil and gas
company in October 2010. Our Eagle Ford Shale properties are held primarily by our wholly-owned subsidiary, Eagle Ford Hunter, Inc.

The Eagle
Ford Shale is one of the fastest growing unconventional resource plays in the U.S. Since July 2010, the industry rig count in the Eagle Ford Shale has grown from approximately 98 rigs to 263 rigs at February 24, 2012. Estimated original oil in place
ranges from 20 to 40 mmbbls per section (640 acres). Based on our drilling results and those of others in the trend, we believe the Eagle Ford Shale can be characterized as having very low geological risks and repeatable drilling opportunities.

As of February 27, 2012, our Eagle Ford Shale properties included approximately 54,000 gross (24,000 net) acres primarily targeting
the Eagle Ford Shale oil window, principally in Gonzales and Lavaca Counties, Texas. As of December 31, 2011, proved reserves attributable to our Eagle Ford Shale properties were 5.4 mmboe on an SEC basis, of which 94% were oil and 24% were
classified as proved developed producing, and 5.4 mmboe on a NYMEX basis. As of February 27, 2012, our Eagle Ford Shale properties included 18 gross (10 net) productive wells, of which we operated 14.

Our joint venture with Hunt Oil covers an area of mutual interest, or AMI, consisting of 32,412 gross acres (15,050 net acres) in Gonzales and
Lavaca Counties, Texas, in which we and Hunt Oil each have a 50% ownership interest. Both parties have agreed to work together within the AMI on an equal and joint basis through December 2014. Both parties have cross-assigned existing ownership
interests in their respective lease acreage positions for both Lavaca and Gonzales Counties. Additionally, the parties share all leasing, exploration, drilling, completion and development costs and other expenses in the AMI on an equal basis. Each
company has also agreed to allow the other to be the designated operator for all wells on lease acres contributed to the AMI by the other. All wells drilled under our Hunt Oil joint venture have been, and all new wells to be drilled under the joint
venture are expected to be, Eagle Ford Shale horizontal wells.



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Our joint venture with the private independent oil and gas company covers an AMI consisting of approximately
4,000 gross acres (2,000 net acres) of certain specific lease acreage positions currently owned by the Company and the other party in Gonzales and Lavaca Counties, Texas. Both parties have agreed to work together within the AMI on an equal
and joint basis through October 2013. The parties share all leasing, exploration, drilling, completion and development costs and other expenses in the AMI on an equal basis. We are the operator under the joint venture. All wells drilled under the
joint venture have been, and all new wells to be drilled under the joint venture are expected to be, Eagle Ford Shale horizontal wells.

The
Eagle Ford Shale is a Cretaceous aged shale ranging in thickness from less than 50 feet to over 300 feet. The Eagle Ford Shale is present within the subsurface along the entire Gulf Coast of Texas and is productive within the majority of
the trend, producing from the more brittle calcareous shale sections. The Eagle Ford Shale produces from depths that range from approximately 7,500 to 14,000 feet.

Our Eagle Ford Shale acreage is located in Gonzales, Lavaca, Atascosa and Fayette Counties, Texas (Eagleville Field) within the prolific oil window. The Company has focused within the oil trend of the
Eagle Ford Shale (9,000 to 11,500 feet) to provide better economic returns. The effective development of our Eagle Ford Shale assets depends on optimization of horizontal drilling techniques and more effective completion procedures. Increased
lateral length, increased number of frac stages and proper frac fluid selection are also important factors in increasing EURs and production rates. As a result of improving drilling and completion techniques, we have experienced significantly
improved IP rates, EURs and rates of return for our Eagle Ford Shale wells. Our six most recently completed Company operated wells in the Eagle Ford Shale have generated an average IP-24 hour rate of approximately 1,602 boepd. We have currently
identified approximately 358 gross (179 net) horizontal drilling locations on our Eagle Ford Shale properties, of which less than 15% are currently classified as proved reserves.

We have an active drilling program in our Peach Creek and Shiner prospect areas, located in Gonzales and Lavaca Counties near the towns of Moulton and Shiner, Texas. The Company has an average working
interest of 50% and net revenue interest of 38.3% in the Peach Creek and Shiner wells. The Company has an average working interest of 96.75% and 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.

We have drilled, fraced and produced from 18 gross (10 net) horizontal wells in the Eagle Ford Shale. The following table contains information regarding our Eagle Ford Shale horizontal wells as of
February 27, 2012.



|                    |  |                                   |  |          |      |  |                     |  |     |                 |  |  |                       |  |  |                  |       |  |                      |  |    |                      |  |  |                       |  |  |  |       |  |  |  |     | 
|------------------- |  | --------------------------------- |  | -------- | ---- |  | ------------------- |  | --- | --------------- |  |  | --------------------- |  |  | ---------------- | ----- |  | -------------------- |  | -- | -------------------- |  |  | --------------------- |  |  |  | ----- |  |  |  | --- | 
|                    |  | Eagle Ford Shale
Horizontal Wells | 
|Well Name           |  | County / State                    |  | Operator |      |  | MHR WorkingInterest |  |     | FirstProduction |  |  | LateralLength 
(feet) |  |  | # of 
FracStages |       |  | IP-24 HourRate (Boe) |  |    | 7 Day IP Rate(Boe/d) |  |  | 30 Day IP Rate(Boe/d) | 
|Operated            |  |                                   |  |          |      |  |                     |  |     |                 |  |  |                       |  |  |                  |       |  |                      |  |    |                      |  |  |                       |  |  |  |       |  |  |  |     | 
|Gonzo Hunter #1H    |  | Gonzales, TX                      |  |          | MHR  |  |                     |  | 50  | %               |  |  | 10/30/10              |  |  |                  | 4,365 |  |                      |  | 9  |                      |  |  | 605                   |  |  |  | 519   |  |  |  | 391 | 
|Lagunillas Camp #2H |  | Atascosa, TX                      |  |          | MHR  |  |                     |  | 100 | %               |  |  | 11/18/10              |  |  |                  | 4,600 |  |                      |  | 14 |                      |  |  | 339                   |  |  |  | 168   |  |  |  | 165 | 
|Lagunillas Camp #1H |  | Atascosa, TX                      |  |          | MHR  |  |                     |  | 97  | %               |  |  | 12/31/10              |  |  |                  | 4,600 |  |                      |  | 15 |                      |  |  | 258                   |  |  |  | 151   |  |  |  | 157 | 
|Southern Hunter #1H |  | Gonzales, TX                      |  |          | MHR  |  |                     |  | 50  | %               |  |  | 01/08/11              |  |  |                  | 4,460 |  |                      |  | 14 |                      |  |  | 1,321                 |  |  |  | 1,091 |  |  |  | 908 | 
|Gonzo North #1H     |  | Gonzales, TX                      |  |          | MHR  |  |                     |  | 50  | %               |  |  | 03/15/11              |  |  |                  | 5,300 |  |                      |  | 15 |                      |  |  | 1,039                 |  |  |  | 715   |  |  |  | 618 | 
|Furrh #1H           |  | Lavaca, TX                        |  |          | MHR  |  |                     |  | 50  | %               |  |  | 04/24/11              |  |  |                  | 4,730 |  |                      |  | 16 |                      |  |  | 882                   |  |  |  | 704   |  |  |  | 648 | 
|Geo Hunter #1H      |  | Lavaca, TX                        |  |          | MHR  |  |                     |  | 50  | %               |  |  | 05/17/11              |  |  |                  | 4,546 |  |                      |  | 13 |                      |  |  | 854                   |  |  |  | 701   |  |  |  | 596 | 
|Sable Hunter #1H    |  | Lavaca, TX                        |  |          | MHR  |  |                     |  | 42  | %               |  |  | 09/12/11              |  |  |                  | 5,067 |  |                      |  | 16 |                      |  |  | 1,017                 |  |  |  | 795   |  |  |  | 657 | 
|Oryx Hunter #1H     |  | Lavaca, TX                        |  |          | MHR  |  |                     |  | 45  | %               |  |  | 09/18/11              |  |  |                  | 6,687 |  |                      |  | 21 |                      |  |  | 2,044                 |  |  |  | 1,254 |  |  |  | 902 | 
|Furrh #2H           |  | Lavaca, TX                        |  |          | MHR  |  |                     |  | 50  | %               |  |  | 11/15/11              |  |  |                  | 5,945 |  |                      |  | 20 |                      |  |  | 1,275                 |  |  |  | 966   |  |  |  | 894 | 
|Kudu Hunter #1H     |  | Lavaca, TX                        |  |          | MHR  |  |                     |  | 46  | %               |  |  | 11/28/11              |  |  |                  | 5,696 |  |                      |  | 20 |                      |  |  | 1,590                 |  |  |  | 1,006 |  |  |  | 883 | 
|Snipe Hunter #1H    |  | Lavaca, TX                        |  |          | MHR  |  |                     |  | 50  | %               |  |  | 12/30/11              |  |  |                  | 6,094 |  |                      |  | 23 |                      |  |  | 2,033                 |  |  |  | 932   |  |  |  | 832 | 
|Leopard Hunter #1H  |  | Lavaca, TX                        |  |          | MHR  |  |                     |  | 50  | %               |  |  | 01/08/12              |  |  |                  | 6,708 |  |                      |  | 25 |                      |  |  | 1,333                 |  |  |  | 970   |  |  |  | 817 | 
|Gonzo North #2H     |  | Gonzales, TX                      |  |          | MHR  |  |                     |  | 50  | %               |  |  | 02/12/12              |  |  |                  | 6,120 |  |                      |  | 24 |                      |  |  | 1,336                 |  |  |  | NA    |  |  |  | NA  | 
|Non-Operated        |  |                                   |  |          |      |  |                     |  |     |                 |  |  |                       |  |  |                  |       |  |                      |  |    |                      |  |  |                       |  |  |  |       |  |  |  |     | 
|Cinco Ranch #1H     |  | Gonzales, TX                      |  |          | Hunt |  |                     |  | 50  | %               |  |  | 03/25/11              |  |  |                  | 5,370 |  |                      |  | 10 |                      |  |  | 290                   |  |  |  | 261   |  |  |  | 213 | 
|Cinco Ranch #2H     |  | Gonzales, TX                      |  |          | Hunt |  |                     |  | 50  | %               |  |  | 03/24/11              |  |  |                  | 5,540 |  |                      |  | 14 |                      |  |  | 396                   |  |  |  | 334   |  |  |  | 326 | 
|JP Ranch #1H        |  | Gonzales, TX                      |  |          | Hunt |  |                     |  | 50  | %               |  |  | 01/24/12              |  |  |                  | 5,804 |  |                      |  | 16 |                      |  |  | 772                   |  |  |  | 722   |  |  |  | N/A | 
|O. Borchers #1H     |  | Gonzales, TX                      |  |          | Hunt |  |                     |  | 50  | %               |  |  | 02/09/12              |  |  |                  | 5,356 |  |                      |  | 19 |                      |  |  | N/A                   |  |  |  | N/A   |  |  |  | N/A | 



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##### Table of Contents

Our Eagle Ford Shale preliminary capital expenditure budget for 2012 is currently $50 million, although we
expect to increase this budget, depending on our drilling results and capital availability.

Williston Basin Properties

As of February 27, 2012, our Williston Basin properties included approximately 413,003 gross (122,561 net) acres. As of December 31, 2011,
proved reserves attributable to our Williston Basin properties were 8.9 mmboe on an SEC basis, of which 94% were oil and 42% were classified as proved developed producing, and 8.8 mmboe on a NYMEX basis. As of February 27, 2012, the Williston
Basin properties included approximately 288 gross (98.9 net) productive wells.

The Company made its entry into the Williston Basin through
the acquisition of interests in waterflood properties in North Dakota from a private independent oil and gas company in December 2006. These properties are our North Dakota legacy properties. We expanded our position in the Williston Basin with the
acquisition of NuLoch in May 2011. The acquired NuLoch properties included operated properties in Alberta and Saskatchewan, Canada and non-operated properties in North Dakota.

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 found within the Williston Basin. 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 Shale and 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.

The following table contains information regarding our recently completed Williston Basin horizontal wells as of February 27, 2012.



| |  |                             |  |                                   |              |  |           |                    |                    |  |      |                 |  |  |               |  |  |                  |         |  |                      |  |    |                       |  |  |                       |  |  |  |       |  |  |  |     |  |  | 
| |  | --------------------------- |  | --------------------------------- | ------------ |  | --------- | ------------------ | ------------------ |  | ---- | --------------- |  |  | ------------- |  |  | ---------------- | ------- |  | -------------------- |  | -- | --------------------- |  |  | --------------------- |  |  |  | ----- |  |  |  | --- |  |  | 
| |  |                             |  | Williston Hunter Horizontal Wells |              |  |          
| |  | Well Name                   |  | County / Province                 |              |  | Formation |                    | MHRWorkingInterest |  |      | FirstProduction |  |  | LateralLength |  |  | # of 
FracStages |         |  | IP-24 HourRate (Boe) |  |    | 7 Day IP 
Rate(Boe/d) |  |  | 30 Day IP Rate(Boe/d) |  |  | 
| |  | Tableland- Operated         |  |                                   |              |  |           |                    |                    |  |      |                 |  |  |               |  |  |                  |         |  |                      |  |    |                       |  |  |                       |  |  |  |       |  |  |  |     |  |  | 
| |  | 1-14-1-10 W2M               |  |                                   | Saskatchewan |  |           | Three Forks/Sanish |                    |  | 100  | %               |  |  | 10/19/2011    |  |  |                  | 1 Mile  |  |                      |  | 26 |                       |  |  | 749                   |  |  |  | 552   |  |  |  | 333 |  |  | 
| |  | 12-2-1-11 W2M               |  |                                   | Saskatchewan |  |           | Three Forks/Sanish |                    |  | 100  | %               |  |  | 12/13/2011    |  |  |                  | 1 Mile  |  |                      |  | 24 |                       |  |  | 178                   |  |  |  | 146   |  |  |  | N/A |  |  | 
| |  | 13-16-1-10 W2M              |  |                                   | Saskatchewan |  |           | Three Forks/Sanish |                    |  | 100  | %               |  |  | 12/16/2011    |  |  |                  | 1 Mile  |  |                      |  | 24 |                       |  |  | 491                   |  |  |  | 324   |  |  |  | N/A |  |  | 
| |  | 13-10-1-10 W2M              |  |                                   | Saskatchewan |  |           | Three Forks/Sanish |                    |  | 100  | %               |  |  | 1/6/2012      |  |  |                  | 1 Mile  |  |                      |  | 24 |                       |  |  | 576                   |  |  |  | N/A   |  |  |  | N/A |  |  | 
| |  | 12-10-1-10 W2M              |  |                                   | Saskatchewan |  |           | Three Forks/Sanish |                    |  | 100  | %               |  |  | 1/12/2012     |  |  |                  | 1 Mile  |  |                      |  | 21 |                       |  |  | 543                   |  |  |  | N/A   |  |  |  | N/A |  |  | 
| |  | North Dakota - Non-Operated |  |                                   |              |  |           |                    |                    |  |      |                 |  |  |               |  |  |                  |         |  |                      |  |    |                       |  |  |                       |  |  |  |       |  |  |  |     |  |  | 
| |  | Mustang 7-6-163-98          |  |                                   | Divide, ND   |  |           | Three Forks/Sanish |                    |  | 7.5  | %               |  |  | 10/8/2011     |  |  |                  | 2 Miles |  |                      |  | 26 |                       |  |  | 565                   |  |  |  | 438   |  |  |  | 345 |  |  | 
| |  | Ranchero 18-19-163-98       |  |                                   | Divide, ND   |  |           | Three Forks/Sanish |                    |  | 10.0 | %               |  |  | 10/9/2011     |  |  |                  | 2 Miles |  |                      |  | 26 |                       |  |  | 843                   |  |  |  | 791   |  |  |  | 651 |  |  | 
| |  | Bonneville 25-36-163-100    |  |                                   | Divide, ND   |  |           | Three Forks/Sanish |                    |  | 5.6  | %               |  |  | 10/19/2011    |  |  |                  | 2 Miles |  |                      |  | 26 |                       |  |  | 950                   |  |  |  | 937   |  |  |  | 751 |  |  | 
| |  | Blue Jay 32-29-163-95       |  |                                   | Divide, ND   |  |           | Bakken             |                    |  | 10.3 | %               |  |  | 10/24/2011    |  |  |                  | 2 Miles |  |                      |  | 26 |                       |  |  | 852                   |  |  |  | 455   |  |  |  | 346 |  |  | 
| |  | Lark 29-32-162-97           |  |                                   | Divide, ND   |  |           | Three Forks/Sanish |                    |  | 10.0 | %               |  |  | 12/10/2011    |  |  |                  | 2 Miles |  |                      |  | 26 |                       |  |  | 636                   |  |  |  | 417   |  |  |  | N/A |  |  | 
| |  | Edna 14-23-160-100          |  |                                   | Divide, ND   |  |           | Three Forks/Sanish |                    |  | 7.0  | %               |  |  | 12/13/2011    |  |  |                  | 2 Miles |  |                      |  | 18 |                       |  |  | 406                   |  |  |  | 353   |  |  |  | N/A |  |  | 
| |  | Stork 17-20-162-96          |  |                                   | Divide, ND   |  |           | Three Forks/Sanish |                    |  | 10.0 | %               |  |  | 12/13/2011    |  |  |                  | 2 Miles |  |                      |  | 20 |                       |  |  | 621                   |  |  |  | 515   |  |  |  | N/A |  |  | 
| |  | Hauge 13-21 28-33-163-99)   |  |                                   | Divide, ND   |  |           | Three Forks/Sanish |                    |  | 1.9  | %               |  |  | 12/14/2011    |  |  |                  | 2 Miles |  |                      |  | 20 |                       |  |  | 897                   |  |  |  | 782   |  |  |  | N/A |  |  | 
| |  | Thomte 8-5-163-99           |  |                                   | Divide, ND   |  |           | Three Forks/Sanish |                    |  | 10.0 | %               |  |  | 1/6/2012      |  |  |                  | 2 Miles |  |                      |  | 30 |                       |  |  | 1,309                 |  |  |  | 1,241 |  |  |  | N/A |  |  | 



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##### Table of Contents

Williston Hunter U.S. Properties

As of February 27, 2012, our Williston Hunter U.S. properties included approximately 36,355 net acres in the Williston Basin in North Dakota, which are prospective for the Bakken Shale and Three
Forks/Sanish formations. As of February 27, 2012, the Williston Hunter U.S. properties included approximately 105 gross (9.5 net) productive wells, all of which were operated by third parties.

Our Williston Hunter U.S. property acreage is located in Divide and Burke Counties, North Dakota, with our primary production from these properties
coming from the Bakken Shale and Three Forks/Sanish formations. Currently, all of our Williston Hunter U.S. properties are operated by larger industry participants, including Samson Oil and Gas Limited and Baytex Energy Corp. NuLochs strategy
has been to utilize much larger industry participants, with local presence and the ability to secure drilling services, as the operators of its properties. However, Magnum Hunters new strategy, in North Dakota as well as its other core areas,
is to acquire properties that it can operate and to increase its working interests, where possible. Since the completion of the NuLoch acquisition in May 2011 through December 31, 2011, Williston Hunter U.S. has participated in the drilling of
87 wells (8.1 net). Most of these wells produce from the Three Forks/Sanish formations. Some wells produce from the middle Bakken Shale. At December 31, 2011, 12 horizontal wells (one net) were awaiting completion, five wells (0.4 net) were
drilling and six drilling rigs were operating on our Williston Hunter U.S. properties.

Williston Hunter U.S. plans to continue to expand its
Bakken Shale and Three Forks/Sanish drilling program in 2012 at an estimated cost to Williston Hunter U.S. of approximately $39.2 million.

Williston Hunter Canada Properties

Our
Williston Hunter Canada property acreage is located primarily in Enchant, near Vauxhall, Alberta, Canada, at Balsam near Grande Prairie, Alberta, Canada and at Tableland, near Estevan, Saskatchewan, Canada. As of February 27 2012, the Williston
Hunter Canada properties included approximately 107,270 gross acres (79,693 net acres). At December 31, 2011, the Williston Hunter Canada properties included approximately 65 gross productive wells, all of which we operated.

Saskatchewan  The Tableland properties target sweet light oil from the Bakken Shale and Three Forks/Sanish formations. At
December 31, 2011, Williston Hunter Canada had 41,797 gross (32,944 net) acres of largely contiguous land that is prospective for Bakken and Three Forks/Sanish oil in the Tableland field. Williston Hunter Canada had 17 producing oil wells (15.2
net) at Tableland at December 31, 2011, and had two wells (two net) awaiting completion and one well (one net) drilling at year end. As a result of new fracing techniques utilized on our last five completed Tableland wells, our IP-24 hour rates
for these wells have averaged approximately 500 boepd each.

We plan to continue our drilling program in Tableland in 2012 at an estimated
cost of approximately $10.8 million. We may expand our drilling activities in Tableland, depending on continued improved drilling results and capital availability.

Alberta  The Alberta properties target shallow natural gas and sweet light oil from the Enchant Second White Specks formation and Kiskatinaw formation. Our Alberta properties include the
Enchant Second White Specks and Balsam properties. The Enchant property consists of 10,720 acres. At December 31, 2011, 48 wells (44.1 net) were producing on this acreage. The natural gas is collected by Williston Hunter Canadas gathering
system and compressed and processed through third-party facilities. The Balsam property consists of a 63% working interest in two producing Kiskatinaw oil wells. The oil is produced to tanks and trucked to market and the associated solution gas is
processed in third-party facilities.



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##### Table of Contents

North Dakota Legacy Properties

At December 31, 2011, the Company owned an approximately 43% average non-operated working interest in 15 fields located in the Williston Basin in North Dakota comprising 151 wells and
approximately 15,000 gross (6,450 net) acres. These leases are operated by a private company that presently owns the remaining working interests. Approximately 90% of these leases, which are located in Burke, Renville, Ward, Bottineau and
McHenry Counties in North Dakota, are held by production.

Appalachian Basin Properties

The Appalachian Basin is considered one of the most mature oil and natural gas producing regions in the U.S. The Company made its entry into the
Appalachian Basin in February 2010 through the acquisition by our wholly-owned subsidiary, Triad Hunter, of substantially all the assets of privately-held Triad Energy Corporation and certain of its affiliates, collectively Triad Energy. Triad
Hunter acquired the assets of Triad Energy in connection with Triad Energys reorganization under Chapter 11 of the U.S. Bankruptcy Code.

In 2010 and 2011, Triad Hunter expanded its position in the Marcellus Shale area of the Appalachian Basin through multiple transactions, including the
PostRock asset acquisitions, the Windsor asset acquisition and the Stone Energy joint venture, which resulted in an increase in our Marcellus Shale acreage of an aggregate of approximately 12,694 gross (11,235 net) acres to a total of approximately
72,668 gross (58,426 net) acres as of February 27, 2012. Triad Hunter also recently expanded its leasehold position in the Utica Shale through an acquisition of approximately 15,558 gross (12,186 net) acres in southeastern Ohio. The properties
held by Triad Hunter are referred to as our Triad Hunter properties.

The Company further expanded its presence in the southern Appalachian
Basin through the acquisition of NGAS in April 2011. The properties acquired in the NGAS acquisition are held by our wholly-owned subsidiary, Magnum Hunter Production, Inc., referred to as Magnum Hunter Production or MHP. The properties held by
Magnum Hunter Production are referred to as our Magnum Hunter Production or MHP properties.

As of February 27, 2012, our Appalachian
Basin properties included a total of approximately 484,412 gross (412,323 net) acres, located primarily in the Marcellus Shale, Utica Shale and southern Appalachian Basin. At December 31, 2011, proved reserves attributable to our Appalachian
Basin properties were 29.9 mmboe on an SEC basis, of which 27% were oil and 59% were classified as proved developed producing, and 30.2 mmboe on a NYMEX basis. As of February 27, 2012, the Appalachian Basin properties included approximately
3,112 gross (2,257 net) productive wells, of which we operated approximately 88%.

We have allocated approximately $50 million of our
2012 preliminary capital budget to our upstream operations in the Appalachian Basin.

Marcellus Shale Properties

As of February 27, 2012, we had approximately 58,426 net acres in the Marcellus Shale area of West Virginia and Ohio. Our Marcellus Shale
acreage is located principally in Tyler, Pleasants, Doddridge, Wetzel and Lewis Counties, West Virginia and in Washington, Monroe and Noble Counties, Ohio. As of February 27, 2012, the Company operated 33 vertical Marcellus Shale wells and 16
horizontal Marcellus Shale wells. As of February 27, 2012, approximately 63% of our leases in the Marcellus Shale area were held by production.

The liquids rich natural gas produced in the Companys core Marcellus Shale area (which has a btu content ranging from 1,125 to 1,375), 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. Once MarkWest Libertys Mobley gas processing complex becomes operational, Triad Hunter will be able to
sell the liquids portion of its gas stream, which we anticipate will result in a pricing uplift attributable to these liquids of approximately $1.00 to $1.50 per mcfe. For these reasons, we believe our Marcellus Shale properties generate a more
attractive rate of return compared to other U.S. natural gas regions.



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##### Table of Contents

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 lateral 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.

Triad Hunter has drilled, fraced and produced from 15 gross (13.5 net) horizontal wells in the Marcellus Shale to date. As a result of our improved
drilling and fracing techniques, our IP-24 hour rates for the seven most recently completed Company operated wells in the Marcellus Shale have averaged 9,914 mmcfpd. The following table contains information regarding our recently drilled Marcellus
Shale horizontal wells as of February 27, 2012.



| |  |                        |  |                                   |  |              |  |                     |     |   |                 |  |            |                       |  |  |                 |  |  |                       |    |  |                       |  |            |                        |  |  |            |  |  |  |            |  |  | 
| |  | ---------------------- |  | --------------------------------- |  | ------------ |  | ------------------- | --- | - | --------------- |  | ---------- | --------------------- |  |  | --------------- |  |  | --------------------- | -- |  | --------------------- |  | ---------- | ---------------------- |  |  | ---------- |  |  |  | ---------- |  |  | 
| |  |                        |  | Marcellus Shale Horrizontal Wells |  |              | 
| |  | Well Name              |  | County                            |  | Operator     |  | MHR WorkingInterest |     |   | FirstProduction |  |            | LateralLength 
(feet) |  |  | # of FracStages |  |  | IP-24 Hour Rate(mcfe) |    |  | 7 Day IP Rate(mcfe/d) |  |            | 30 Day IP Rate(mcfe/d) |  |  |           
| |  | Operated               |  |                                   |  |              |  |                     |     |   |                 |  |            |                       |  |  |                 |  |  |                       |    |  |                       |  |            |                        |  |  |            |  |  |  |            |  |  | 
| |  | Weese #1H              |  | Tyler, WV                         |  | MHR          |  |                     | 100 | % |                 |  | 12/31/2010 |                       |  |  | 3,550           |  |  |                       | 12 |  |                       |  | 7,210      |                        |  |  | 4,559      |  |  |  | 4,205      |  |  | 
| |  | Weese #3H              |  | Tyler, WV                         |  | MHR          |  |                     | 100 | % |                 |  | 1/20/2011  |                       |  |  | 3,030           |  |  |                       | 12 |  |                       |  | 5,413      |                        |  |  | 4,352      |  |  |  | 4,836      |  |  | 
| |  | Ormet #1H              |  | Monroe, OH                        |  | MHR          |  |                     | 50  | % |                 |  | 2/25/2011  |                       |  |  | 3,700           |  |  |                       | 12 |  |                       |  | Tight hole |                        |  |  | Tight hole |  |  |  | Tight hole |  |  | 
| |  | WVDNR #1102            |  | Wetzel, WV                        |  | MHR          |  |                     | 100 | % |                 |  | 9/19/2011  |                       |  |  | 4,950           |  |  |                       | 16 |  |                       |  | 10,000     |                        |  |  | 6,184      |  |  |  | 5,800      |  |  | 
| |  | WVDNR #1103            |  | Wetzel, WV                        |  | MHR          |  |                     | 100 | % |                 |  | 9/22/2011  |                       |  |  | 5,000           |  |  |                       | 16 |  |                       |  | 10,500     |                        |  |  | 7,164      |  |  |  | 7,078      |  |  | 
| |  | WVDNR #1104            |  | Wetzel, WV                        |  | MHR          |  |                     | 100 | % |                 |  | 9/26/2011  |                       |  |  | 5,000           |  |  |                       | 16 |  |                       |  | 10,400     |                        |  |  | 6,139      |  |  |  | 5,618      |  |  | 
| |  | Roger Weese #1110      |  | Tyler, WV                         |  | MHR          |  |                     | 100 | % |                 |  | 10/25/2011 |                       |  |  | 4,350           |  |  |                       | 16 |  |                       |  | 9,700      |                        |  |  | 6,183      |  |  |  | 5,040      |  |  | 
| |  | Everett Weese #1107    |  | Tyler, WV                         |  | MHR          |  |                     | 100 | % |                 |  | 12/20/2011 |                       |  |  | 5,300           |  |  |                       | 18 |  |                       |  | 9,700      |                        |  |  | 6,618      |  |  |  | 6,542      |  |  | 
| |  | Everett Weese # 1108   |  | Tyler, WV                         |  | MHR          |  |                     | 100 | % |                 |  | 12/20/2011 |                       |  |  | 5,200           |  |  |                       | 16 |  |                       |  | 9,600      |                        |  |  | 6,913      |  |  |  | 6,337      |  |  | 
| |  | Everett Weese #1109    |  | Tyler, WV                         |  | MHR          |  |                     | 100 | % |                 |  | 12/20/2011 |                       |  |  | 5,550           |  |  |                       | 18 |  |                       |  | 9,500      |                        |  |  | 7,239      |  |  |  | 6,361      |  |  | 
| |  | Spencer Unit #1112H    |  | Tyler, WV                         |  | MHR          |  |                     | 100 | % |                 |  | N/A        |                       |  |  | 4,310           |  |  |                       | 17 |  |                       |  | N/A        |                        |  |  | N/A        |  |  |  | N/A        |  |  | 
| |  | Spencer Unit #1113H    |  | Tyler, WV                         |  | MHR          |  |                     | 100 | % |                 |  | N/A        |                       |  |  | 4,000           |  |  |                       | 16 |  |                       |  | N/A        |                        |  |  | N/A        |  |  |  | N/A        |  |  | 
| |  | Spencer Unit #1114H    |  | Tyler, WV                         |  | MHR          |  |                     | 100 | % |                 |  | N/A        |                       |  |  | 4,720           |  |  |                       | 19 |  |                       |  | N/A        |                        |  |  | N/A        |  |  |  | N/A        |  |  | 
| |  | Spencer Unit #1115H    |  | Tyler, WV                         |  | MHR          |  |                     | 100 | % |                 |  | N/A        |                       |  |  | 3,900           |  |  |                       | 16 |  |                       |  | N/A        |                        |  |  | N/A        |  |  |  | N/A        |  |  | 
| |  | Non-Operated           |  |                                   |  |              |  |                     |     |   |                 |  |            |                       |  |  |                 |  |  |                       |    |  |                       |  |            |                        |  |  |            |  |  |  |            |  |  | 
| |  | Lance Mills Unit 2 #5H |  | Wetzel, WV                        |  | Stone Energy |  |                     | 50  | % |                 |  | 6/5/2011   |                       |  |  | 5,350           |  |  |                       | 13 |  |                       |  | 3,360      |                        |  |  | 3,114      |  |  |  | 2,789      |  |  | 
| |  | Lance Mills Unit 2 #2H |  | Wetzel, WV                        |  | Stone Energy |  |                     | 50  | % |                 |  | 6/6/2011   |                       |  |  | 5,600           |  |  |                       | 11 |  |                       |  | 3,875      |                        |  |  | 2,987      |  |  |  | 2,620      |  |  | 

Triad Hunter plans to continue to expand its Marcellus Shale horizontal well drilling program in 2012. Completion
operations on the newly drilled Marcellus Shale wells may be delayed until the later months of 2012 in anticipation of higher natural gas prices and the installation and operation of the Mobley gas processing complex.

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 has been designated as the operator for the contract area. Stone Energy also contributed to the joint venture certain
infrastructure assets, including improved roadways, certain central field processing units (including water handling), and gas flow lines, and agreed to commit its share of natural gas production from the contract area to gathering by our Eureka
Hunter Pipeline System.

Utica Shale Properties

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 lease acreage
consists of approximately 15,558 gross (12,186 net) acres that are presently prospective for the Utica Shale, substantially all of which is held by shallow production. The acquired acreage is in



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close proximity to other Triad Hunter acreage in Washington and Noble Counties, Ohio. Triad Hunter has agreed to acquire another block of similar acreage from the seller on or before
April 16, 2012, assuming the seller can satisfy certain title requirements and meet certain other required conditions. The acquisition of this Utica Shale acreage significantly expands our acreage position in a strategic region of Ohio, and
also provides the opportunity for our midstream business to expand our Eureka Hunter Pipeline System into this region, which is currently not served by midstream competitors.

Many in the industry believe the Utica Shale could rival the Marcellus Shale in terms of oil and gas potential. Like the Marcellus Shale, the productive limits of the Utica Shale cover a large area within
New York, Pennsylvania, Ohio and West Virginia. This Ordovician age shale is a dark gray to black, organic rich shale deposit productive at depths between 6,000 and 12,500 feet and ranges in thickness from 100 to 500 feet. However, the industry is
currently targeting a lower portion of the Utica Shale called the Point Pleasant formation, which ranges in thickness between 80 and 120 feet. Utica Shale gas is best produced from hydraulically fractured horizontal wellbores that generally exceed
4,000 feet in lateral length and typically involve multistage fracturing completions.

Triad Hunter owns mineral rights to a total of
approximately 61,151 net acres that are presently prospective for the Utica Shale. Approximately 17,375 of these net acres are located in Ohio (which include the acreage acquired in February 2012 and the balance of which overlaps our Marcellus Shale
acreage), and approximately 43,776 of the net acres are located in West Virginia (all of which overlaps our Marcellus Shale acreage).

Processing Agreement

In October 2011,
Triad Hunter entered into a processing agreement with MarkWest Liberty pursuant to which MarkWest Liberty will provide long-term gas processing and related services for natural gas produced in northwest West Virginia by both Triad Hunter and other
producers that is gathered through our Eureka Hunter Pipeline System.

Southern Appalachian Basin Properties

As of February 27, 2012, our Magnum Hunter Production properties included approximately 367,140 gross (313,124 net) lease acres located in the
southern Appalachian Basin, primarily in Kentucky. Our primary production from the MHP 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 lateral 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 February 27, 2012, MHP had drilled 77 Devonian Shale horizontal wells, primarily in the Huron and Cleveland sections of
the Devonian Shale formation. In 2011, MHP drilled 12 Huron horizontal wells and four Cleveland horizontal wells, principally to hold existing acreage commitments covering a total of approximately 223,500 net acres.

The Mississippian Weir sandstone covers approximately 38,000 gross (32,300 net) acres of our MHP properties. In 2011, MHP drilled four Weir horizontal
wells with increasingly encouraging results as we extended our lateral lengths and continued to optimize our completion techniques. The Weir produces oil in addition to high btu natural gas. As of February 27, 2012, we were drilling one Weir
horizontal well. We plan to drill a minimum of four additional Weir horizontal wells in 2012 under our preliminary 2012 capital budget.

The
Magnum Hunter Production properties also include a non-operating interest in a coalbed methane project in the Arkoma Basin in Arkansas and Oklahoma, in addition to certain non-operated projects in West Virginia and Virginia. Magnum Hunter Production
also owns and operates a New Albany Shale field in western Kentucky known as Haleys Mill. The Haleys Mill field contains approximately 36,465 net acres on which the New Albany Shale formation is present at depths ranging from 2,600 to
2,800 feet. As of February 27, 2012, we were



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operating three producing horizontal wells in the Haleys Mill field. Magnum Hunter Production also co-owns a processing facility in the Haleys Mill field which reduces nitrogen levels
in the natural gas produced from the field to pipeline quality standards.

Other Properties

South Louisiana/East ChalkleyOur East Chalkley field is located in Cameron Parish, Louisiana. The field consists of approximately
714 gross acres (443 net acres). This developmental project is an exploitation of bypassed oil reserves remaining in a natural gas field located at depths between 9,300 and 9,400 feet. As of February 27, 2012, the Company operated the
East Chalkley field and owned an approximately 62% working interest and an approximately 42.7% net revenue interest in the field. We have not allocated any capital to this project for 2012.

Other Texas and Louisiana AssetsOther properties of the Company are located in Nacogdoches, Colorado, Lavaca, Bee, Fayette and Wharton Counties, Texas and Desoto Parish, Louisiana. As of
February 27, 2012, these properties consisted of an aggregate of approximately 7,050 gross (1,188 net) acres. We have not allocated any capital to these assets for 2012.

Midstream Assets

Eureka Hunter Pipeline System

Our acquisition of assets from Triad Energy in 2010 included important infrastructure assets for the efficient development of the Companys Marcellus
Shale and Utica Shale unconventional resources. As of February 27, 2012, these assets included approximately 207 miles of pipeline, gathering systems and/or rights-of-way, which we are currently developing, located in northwestern West Virginia
and southeastern Ohio, in the Marcellus and Utica Shales. This is our Eureka Hunter Pipeline System. The Eureka Hunter Pipeline System runs through Pleasants, Tyler, Ritchie, Wetzel, Marion, Harrison, Doddridge, Lewis and Monongalia Counties in West
Virginia and Washington County, Ohio, in certain of the liquids rich portions of the Marcellus and Utica Shales. We expect our Eureka Hunter Pipeline System to have sufficient pipeline capacity to gather significant quantities of Company produced
natural gas from our Marcellus Shale and Utica Shale development programs, as well as substantial volumes of third-party gas.

Eureka Hunter
is currently constructing new 20-inch and 16-inch high-pressure pipeline with approximately 300 mmcfpd of initial throughput capacity. The first pipeline section of six miles was turned to sales in December 2010. Since then, Eureka Hunter has
completed the construction of approximately 39 additional miles of pipeline, for a total of 45 miles of completed pipeline as of February 27, 2012. This additional construction included (i) 10 miles of 20-inch pipeline extending
easterly from the initial six mile segment towards the pipelines future Lewis Wetzel Lateral and the planned Mobley gas processing complex (see MarkWest Processing Agreement below), (ii) the Pursley Lateral, which is a 20-inch
lateral section of pipeline extending 14 miles northerly in Tyler County, West Virginia, terminating near the border of Tyler and Wetzel Counties, and (iii) approximately three miles of 20-inch mainline westerly in Wetzel County connecting to
the Pursley Lateral. The Pursley Lateral will enable the Eureka Hunter Pipeline System to gather gas produced by Triad Hunter and third party producers in the Middlebourne area of Tyler County, West Virginia.

We have budgeted $50 million for Eureka Hunter projects in 2012, of which approximately $35.9 million is expected to be used for the construction of
three key Eureka Hunter Pipeline System laterals, namely, the Lewis Wetzel Lateral, the Mobley Lateral and the Doddridge Lateral. We expect the 2012 budgeted Eureka Hunter capital expenditures will be funded through the Eureka Hunter Credit
Facilities. The Lewis Wetzel Lateral will be approximately seven miles of 20-inch mainline that will connect to the Mobley Lateral. The 20-inch Mobley Lateral will extend easterly approximately eight miles for the delivery of gas to MarkWest
Libertys planned Mobley processing complex in Wetzel County, West Virginia. The 16-inch Doddridge Lateral will initially extend four miles southerly into Doddridge County, West Virginia from the systems 20-inch mainline in Tyler County,
West Virginia.



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MarkWest Processing Agreement

In October 2011, Triad Hunter entered into certain midstream services agreements with MarkWest Liberty pursuant to which MarkWest Liberty will provide long-term gas processing and related services for
natural gas produced in northwest West Virginia gathered by Eureka Hunter for both Triad Hunter and other producers through the Eureka Hunter Pipeline System. In October 2011, Eureka Hunter and MarkWest Liberty entered into a mutual cooperation
agreement whereby both companies agreed to jointly develop natural gas-related services to support Marcellus Shale producers in a significant geographic area in northwest West Virginia. Pursuant to this agreement, Eureka Hunter sold its 200 mmcfe
per day capacity Thomas Russell cryogenic natural gas processing plant, which was then under construction, to MarkWest Liberty. MarkWest Liberty intends to install this new plant, the Mobley 2 plant, adjacent to MarkWest Libertys 120 mmcfe per
day capacity natural gas processing plant, the Mobley 1 plant, near Logansport, West Virginia. We anticipate that the Mobley 1 plant will be in commercial operation during the third quarter of 2012 and the Mobley 2 plant will be in commercial
operation during the fourth quarter of 2012. MarkWest Liberty will also provide natural gas liquids handling and fractionation services for Mobley plant products. We have contracted for a specified amount of firm capacity at the Mobley 2 plant and,
until the Mobley 2 plant becomes operational, may enter into processing arrangements for interruptible capacity at the Mobley 1 plant. Natural gas production processed at the Mobley complex will be able to access both the Columbia Gas Transmission
and the Equitrans interstate pipeline systems. These agreements with MarkWest Liberty will allow Eureka Hunter to offer third party producers in the Marcellus Shale not only gas gathering services through the Eureka Hunter Pipeline System, but also
access to natural gas processing at MarkWest Libertys Mobley complex.

Other Gas Gathering and Processing

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

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

Gas Processing. Eureka Hunter 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. Magnum Hunter Production owns a 50% interest in a nitrogen rejection facility in Western Kentucky, used for the processing of MHPs Illinois Basin production. 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. The nitrogen rejection facility is part of the infrastructure build-out for MHP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.



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Equipment and Services

Alpha Hunter DrillingOur wholly-owned subsidiary, Alpha Hunter Drilling, LLC, currently owns and operates five drilling rigs capable of drilling 6,000 to 10,000 feet, which are primarily used
for vertical section (top-hole) air drilling. The drilling rigs are used for both the Companys Appalachian Basin operations and to provide drilling services to third parties. The Companys fleet consists of three Schramm T200XD drilling
rigs and two Schramm T130XD drilling rigs. 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 proven to reduce overall drilling costs, by minimizing mobilization and demobilization charges and significantly decreasing the overall time to drill horizontal wells on each pad site. At February 27, 2012, one
of our three Schramm T200XD drilling rigs was under contract to a large producer in the Appalachian Basin area for the drilling of multiple wells. The Company is currently in negotiations with third party producers to lease the second Schramm T200XD
drilling rig under a multi-well drilling contract. The Company uses the third Schramm T200XD drilling rig for drilling the top-holes for the Companys Marcellus Shale drilling program and leases the drilling rig on the spot market when it is
not in use by the Company. At February 27, 2012, the two T130XD Schramm drilling rigs were contracted on the spot market.

Water
DisposalTypically, Marcellus Shale wells produce significant amounts of water that, in most cases, require disposal. In February 2012, we sold our Marcellus Shale commercial salt water disposal operations, which included salt water
disposal facilities located in Ohio and Kentucky, to a third party for aggregate cash and other consideration valued at $8.8 million, subject to certain working capital, earnings and other similar adjustments. We entered into services agreements
with the buyer of the operations pursuant to which the buyer agreed to provide us with a specified level of salt water disposal capacity at the facilities for a term of five years. See Item 7Managements Discussion and Analysis
of Financial Condition and Results of OperationsRelated Party Transactions.

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 and, in some cases, under contracts of approximately
one-year duration.

Marketing of U.S. Production

Since mid-2011, we have received premium pricing for our marketing of the crude oil produced from our Eagle Ford Shale properties. We attribute this premium pricing to the high quality and geographic
location of the crude oil product. This crude oil is approximately 40 to 42 degrees API gravity and is considered sweet because it is low in sulfur. Since our production is within relatively close proximity to refineries near Corpus
Christi, Texas, the Houston Ship Channel and St. James, Louisiana, we are able to utilize to some extent the price differentials existing in the West Texas Intermediate, or WTI, and Louisiana Light Sweet markets to gain better pricing for our
marketing of the production. This combination of production location and crude oil quality have allowed us to sell our Eagle Ford Shale crude oil at prices above WTI price postings during the second half of 2011 and into 2012, and we anticipate that
market conditions should allow us to continue to receive pricing above WTI postings further into 2012. Currently, we are marketing our Eagle Ford Shale crude oil at prices that are averaging approximately $9.50 per bbl above WTI price postings. We
market our Eagle Ford Shale crude oil production to at least three markets to assure competitive pricing, retain the ability to move production as quickly as possible and reduce buyer credit exposure.



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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.

We sell natural gas liquids extracted from our Eagle
Ford Shale natural gas production to the processing plant operator at current spot prices. We expect that our natural gas liquids (other than ethane, when and if extracted) to be extracted and fractionated by MarkWest Liberty, when MarkWest
Libertys Mobley gas processing complex becomes operational, will be marketed by MarkWest Liberty at prevailing market prices. We will be responsible for the marketing of such ethane, if and when extracted, depending on when the Mobley complex
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 a 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.

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, under a one-year contract ending on October 31, 2012.

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.

Derivatives

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

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;
| | - |  | -----------------------------------------



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| |  |  | 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 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 or production; and
| | - |  | ----------------------------------------------------------------------



| |  |  | the price and availability of alternative fuels.
| | - |  | ------------------------------------------------

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



| |  |  | our production and/or sales of oil and natural gas are less than expected;
| | - |  | --------------------------------------------------------------------------



| |  |  | payments owed under derivative hedging contracts come due prior to receipt of the hedged months production revenue; or
| | - |  | -----------------------------------------------------------------------------------------------------------------------



| |  |  | the counterparty to the hedging contract defaults on its contract obligations.
| | - |  | ------------------------------------------------------------------------------

In addition, hedging arrangements limit the benefit we would receive from increases in the price of oil and natural gas. Hedging transactions we may
enter into may not adequately protect us from a decline in the price of oil and natural gas above certain caps. Furthermore, should we choose not to engage in hedging transactions in the future (to the extent we are not otherwise obligated to hedge
under our credit facilities), we may be adversely affected by volatility in oil and natural gas prices.

As of December 31, 2011, we had
the following hedges in place:



|                                           |  |      |            |   |      |   |           |  
|------------------------------------------ |  | ---- | ---------- | - | ---- | - | --------- | -
|                                           |  | 2012 |            |   | 2013 |  
|Natural Gas Hedges                         |  |      |            |   |      |   |           |  
|Swaps                                      |  |      |            |   |      |   |           |  
|Volume (mmbtu/d)                           |  |      | 6,100      |   |      |   | 6,000     |  
|Price per mcf                              |  | $    | 4.16       |   |      | $ | 4.13      |  
|Collars                                    |  |      |            |   |      |   |           |  
|Volume (mmbtu/d)                           |  |      | 11,910     |   |      |   | 12,500    |  
|Floor Price per mcf                        |  | $    | 4.58       |   |      | $ | 4.50      |  
|Ceiling Price per mcf                      |  | $    | 6.42       |   |      | $ | 5.96      |  
|Total Gas Volume Hedged (mcf)              |  |      | 6,591,660  |   |      |   | 6,752,500 |  
|Total proved developed producing mcf (PDP) |  |      | 10,937,490 |   |      |   | 6,990,620 |  
|Total % of PDP Hedged                      |  |      | 60         | % |      |   | 96        | %



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|                              |  |      |           |   |      |   |           |  
|----------------------------- |  | ---- | --------- | - | ---- | - | --------- | -
|                              |  | 2012 |           |   | 2013 |  
|Crude Oil Hedges              |  |      |           |   |      |   |           |  
|Floors                        |  |      |           |   |      |   |           |  
|Volume (bbls/d)               |  |      | 151       |   |      |   | N/A       |  
|Price per bbl                 |  | $    | 80.00     |   |      |   | N/A       |  
|Swaps                         |  |      |           |   |      |   |           |  
|Volume (bbls/d)               |  |      | N/A       |   |      |   | N/A       |  
|Price per bbl                 |  |      | N/A       |   |      |   | N/A       |  
|Collars                       |  |      |           |   |      |   |           |  
|Volume (bbls/d)               |  |      | 3,000     |   |      |   | 2,763     |  
|Floor Price per bbl           |  | $    | 81.69     |   |      | $ | 81.38     |  
|Ceiling Price per bbl         |  | $    | 98.92     |   |      | $ | 97.61     |  
|Total Oil Volume Hedged (bbl) |  |      | 1,153,200 |   |      |   | 1,008,495 |  
|Total PDP bbl                 |  |      | 918,440   |   |      |   | 659,490   |  
|Total % of PDP Hedged         |  |      | 125       | % |      |   | 153       | %

MHP Drilling Partnerships

Prior to our acquisition of NGAS in April 2011, NGAS had, from 1996 through 2010, sponsored 38 drilling partnerships for accredited investors to participate in certain of its drilling initiatives. 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, completed its first
sponsored drilling partnership, Energy Hunter Partners 2011-A, Ltd., raising approximately $12.9 million from accredited investors. The drilling partnership is structured to allow these investors to participate with Magnum Hunter Production in a
portfolio of wells being drilled by the Company in our unconventional resource plays in the southern Appalachian Basin, the Marcellus Shale and the Eagle Ford Shale. The drilling partnership participates in the 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 the drilling partnership and the program. Proceeds from the private placement of interests in the drilling partnership,
together with Magnum Hunter Production capital contributions, were contributed to the program to fund the programs share of drilling and completion costs of the project wells. Interests in the program are shared proportionately until
distributions to the drilling partnership reach 100% of its investment in the program, 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 20% basis.

Magnum Hunter Production plans to sponsor
an additional drilling and/or income partnership or partnerships in 2012 to participate in Company drilling and acquisition initiatives. Our 2011 program and any future 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 gas properties are primarily located in (i) the Appalachian
Basin in West Virginia, Ohio and Kentucky, with substantial acreage in the Marcellus Shale area in West Virginia; (ii) the Eagle Ford Shale area in south Texas; and (iii) the Williston Basin in North Dakota and Canada. Cawley,
Gillespie & Associates, Inc., independent petroleum consultants, which we refer to as CGA, has estimated our U.S. oil and natural gas reserves (other than North Dakota reserves) and the present value of future net revenues therefrom as of
December 31, 2011. Those estimates were determined based on prices and costs as of or for the twelve-month period ended December 31, 2011. AJM Deloitte and Touche, LLP, independent petroleum consultants, which we



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refer to as AJM, has estimated our Canadian and North Dakota oil and natural gas reserves and the present value of future net revenues therefrom as of December 31, 2011. Those estimates were
determined based on prices and costs as of or for the twelve-month period ended December 31, 2011. Since January 1, 2011, 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 new rule requires disclosure of oil and gas proved reserves by significant geographic area, using the arithmetic 12-month average beginning-of-the-month
price for the year, as opposed to using year-end prices as was practiced in all previous years. The rule also allows for the use of reliable technologies to estimate proved oil and gas reserves, contingent on demonstrated reliability, in conclusions
about reserve volumes. Under the new rules, companies are required to report on the independence and qualifications of 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 based on the new SEC rules as defined in Rule 4.10(a) of Regulation S-X and Item 1200 of Regulation S-K.



|                   |  |                                       |        |  |         |  |       |        |  |  |         |  |  |   |       | 
|------------------ |  | ------------------------------------- | ------ |  | ------- |  | ----- | ------ |  |  | ------- |  |  | - | ----- | 
|                   |  | Net Reserves (SEC Prices at 12/31/11) |       
|Category           |  | Oil                                   |        |  | NGL     |  |       | Gas    |  |  | PV-10   | 
|                   |  | (mbbls)                               |        |  | (mbbls) |  |       | (mmcf) |  |  | ($mm)   | 
|Proved Developed   |  |                                       | 7,719  |  |         |  | 1,460 |        |  |  | 90,198  |  |  | $ | 397.2 | 
|Proved Undeveloped |  |                                       | 9,405  |  |         |  | 3,126 |        |  |  | 49,039  |  |  | $ | 219.7 | 
|                   |  |                                       |        |  |         |  |       |        |  |  |         |  |  |   |       | 
|Total Proved       |  |                                       | 17,124 |  |         |  | 4,586 |        |  |  | 139,237 |  |  | $ | 616.9 | 
|                   |  |                                       |        |  |         |  |       |        |  |  |         |  |  |   |       | 

The table below summarizes our proved reserves, based on NYMEX futures strip pricing as of December 31, 2011.



|                   |  |                                                           |        |  |         |  |       |        |  |  |         |  |  |   |       | 
|------------------ |  | --------------------------------------------------------- | ------ |  | ------- |  | ----- | ------ |  |  | ------- |  |  | - | ----- | 
|                   |  | Net Reserves (Based on NYMEX Futures Prices at 
12/31/11) |       
|Category           |  | Oil                                                       |        |  | NGL     |  |       | Gas    |  |  | PV-10   | 
|                   |  | (mbbls)                                                   |        |  | (mbbls) |  |       | (mmcf) |  |  | ($mm)   | 
|Proved Developed   |  |                                                           | 7,645  |  |         |  | 1,446 |        |  |  | 90,928  |  |  | $ | 391.8 | 
|Proved Undeveloped |  |                                                           | 9,420  |  |         |  | 3,158 |        |  |  | 49,827  |  |  | $ | 209.1 | 
|                   |  |                                                           |        |  |         |  |       |        |  |  |         |  |  |   |       | 
|Total Proved       |  |                                                           | 17,065 |  |         |  | 4,604 |        |  |  | 140,755 |  |  | $ | 600.9 | 
|                   |  |                                                           |        |  |         |  |       |        |  |  |         |  |  |   |       | 

All of our reserves are located within the continental U.S. and Canada. Reserve estimates are inherently imprecise and
remain subject to revisions based on production history, results of additional exploration and development, prices of oil and natural gas and other factors. Please read Item 1A. Risk FactorsOur estimated proved reserves are based on
many assumptions that may turn out to be inaccurate. Any significant inaccuracies in these reserve estimates or underlying assumptions may materially affect the quantities and present value of our reserves. You should also read the notes
following the table below and our consolidated financial statements for the year ended December 31, 2011 in conjunction with the following reserve estimates.



56



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



|                                   |  |      |          |  |      |   |          |      |  |   |         | 
|---------------------------------- |  | ---- | -------- |  | ---- | - | -------- | ---- |  | - | ------- | 
|                                   |  | 2011 |          |  | 2010 |   |          | 2009 | 
|Description                        |  |      |          |  |      |   |          |      |  |   |         | 
|Proved Developed Reserves          |  |      |          |  |      |   |          |      |  |   |         | 
|Oil (mbbls)                        |  |      | 7,718.9  |  |      |   | 3,720.3  |      |  |   | 1,694.7 | 
|NGLs (mbbls)                       |  |      | 1,459.8  |  |      |   |         |      |  |   | 361.0   | 
|Natural Gas (mmcf)                 |  |      | 90,198.2 |  |      |   | 18,887.7 |      |  |   | 4,952.5 | 
|Proved Undeveloped Reserves        |  |      |          |  |      |   |          |      |  |   |         | 
|Oil (mbbls)                        |  |      | 9,405.4  |  |      |   | 3,104.0  |      |  |   | 2,126.8 | 
|NGLs (mbbls)                       |  |      | 3,125.8  |  |      |   |         |      |  |   | 426.0   | 
|Natural Gas (mmcf)                 |  |      | 49,039.0 |  |      |   | 20,564.2 |      |  |   | 4,411.7 | 
|                                   |  |      |          |  |      |   |          |      |  |   |         | 
|Total Proved Reserves (mboe)(1)(2) |  |      | 44,916.1 |  |      |   | 13,399.7 |      |  |   | 6,169.2 | 
|                                   |  |      |          |  |      |   |          |      |  |   |         | 
|PV-10 Value ($mm)(3)               |  | $    | 616.9    |  |      | $ | 177.8    |      |  | $ | 65.6    | 
|Standardized Measure ($mm)         |  | $    | 474.0    |  |      | $ | 128.0    |      |  | $ | 47.4    | 



|(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 (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. The estimated future production is
priced based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for the period January through December 2011, using $96.19 per bbl and $4.11 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, 2011, our proved undeveloped reserves, or PUDs, on an SEC basis totaled 12.5 mmboe of crude oil and ngls and 49.0 bcf of natural gas for a total of 20.7 mmboe. Changes in PUDs that occurred during the year were due to increased
drilling activity in our Eagle Ford Shale, Marcellus Shale and Bakken Shale/Three Forks/Sanish areas.



57



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The following table summarizes the changes in our proved reserves for the year ended December 31, 2011:



|                                            |  |                                      |        |  
|------------------------------------------- |  | ------------------------------------ | ------ | -
|Proved Reserves (mboe)                      |  | For the Year 
EndedDecember 31, 2011 |       
|Proved reservesbeginning of year           |  |                                      | 13,400 |  
|Revisions of previous estimates             |  |                                      | 13,686 |  
|Improved recovery                           |  |                                      |       |  
|Extensions and discoveries                  |  |                                      | 6,420  |  
|Production                                  |  |                                      | (2,011 | )
|Purchases of reserves in place              |  |                                      | 13,638 |  
|Sales of reserves in place                  |  |                                      | (217   | )
|Proved reservesend of year                 |  |                                      | 44,916 |  
|Proved developed reservesbeginning of year |  |                                      | 6,868  |  
|Proved developed reservesend of year       |  |                                      | 24,212 |  

Recent SEC Rule-Making Activity

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



| |  |  | Commodity Prices: Economic producibility of reserves and discounted cash flows are now based on a 12-month average commodity price unless
contractual arrangements designate the price to be used.
| | - |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Disclosure of Unproved Reserves: Probable and possible reserves may be disclosed separately on a voluntary basis.
| | - |  | -----------------------------------------------------------------------------------------------------------------



| |  |  | Proved Undeveloped Reserve Guidelines: Reserves may be classified as proved undeveloped if there is a high degree of confidence that the
quantities will be recovered and they are scheduled to be drilled within the next five years, unless the specific circumstances justify a longer time.
| | - |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Reserves Estimation Using New Technologies:Reserves may be estimated through the use of reliable technology in addition to flow tests and
production history.
| | - |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Reserves Personnel and Estimation Process:Additional disclosure is required regarding the qualifications of the chief technical person who
oversees the reserves estimation process. We are also required to provide a general discussion of our internal controls used to assure the objectivity of the reserves estimate.
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Non-Traditional Resources:The definition of oil and gas producing activities has expanded and focuses on the marketable product rather
than the method of extraction.
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------

Reserve Estimation

CGA and AJM evaluated our oil and gas reserves on a consolidated basis as of December 31, 2011. 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. CGA and AJM do
not own an interest in any of our properties and are not employed by us on a contingent basis.

We maintain an internal staff of petroleum
engineers and geoscience professionals who work closely with CGA and AJM to ensure the integrity, accuracy and timeliness of the data used to calculate our proved oil and gas reserves. Our internal technical team members meet with CGA and AJM
periodically throughout the year to discuss the assumptions and methods used in the proved reserve estimation process. We provide historical



58



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##### Table of Contents

information to CGA and AJM 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 CGA and AJM, as well as extensive management review and approval. All of our reserve estimates are
reviewed and approved by our executive vice president of operations and our vice president of reservoir engineering. Our executive vice president of operations holds a B.S. in petroleum engineering from the University of Louisiana-Lafayette with
more than 36 years of experience and is a member of the National Society of Professional Engineers, Society of Petroleum Engineers, and the Society of Petroleum Evaluation Engineers. Our vice president of reservoir engineering holds a B.S. in
chemical engineering from Ohio State University with more than 29 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.

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.

Acreage and Productive Wells Summary

The following tables set forth, for our continuing
operations, our gross and net acreage of developed and undeveloped oil and natural gas leases and our gross and net productive oil and natural gas wells as of December 31, 2011.



|                         |  |                     |         |  |                       |  |         |               |  |  |         |  |  |       |         |  |     |  |         |  |  |  |         | 
|------------------------ |  | ------------------- | ------- |  | --------------------- |  | ------- | ------------- |  |  | ------- |  |  | ----- | ------- |  | --- |  | ------- |  |  |  | ------- | 
|                         |  | DevelopedAcreage(1) |         |  | UndevelopedAcreage(2) |  |         | Total Acreage | 
|                         |  | Gross               |         |  | Net                   |  |         | Gross         |  |  | Net     |  |  | Gross |         |  | Net | 
|Eagle Ford Shale(3)      |  |                     | 14,152  |  |                       |  | 5,548   |               |  |  | 46,898  |  |  |       | 19,640  |  |     |  | 61,050  |  |  |  | 25,188  | 
|Appalachian Basin        |  |                     | 193,034 |  |                       |  | 193,034 |               |  |  | 291,378 |  |  |       | 219,289 |  |     |  | 484,412 |  |  |  | 412,323 | 
|Williston Basin          |  |                     |         |  |                       |  |         |               |  |  |         |  |  |       |         |  |     |  |         |  |  |  |         | 
|Williston Hunter U.S.(4) |  |                     | 82,424  |  |                       |  | 13,942  |               |  |  | 223,310 |  |  |       | 28,928  |  |     |  | 305,734 |  |  |  | 42,870  | 
|Williston Hunter Canada  |  |                     | 32,590  |  |                       |  | 26,577  |               |  |  | 74,679  |  |  |       | 53,114  |  |     |  | 107,269 |  |  |  | 79,691  | 
|                         |  |                     |         |  |                       |  |         |               |  |  |         |  |  |       |         |  |     |  |         |  |  |  |         | 
|Total                    |  |                     | 322,200 |  |                       |  | 239,101 |               |  |  | 636,265 |  |  |       | 320,971 |  |     |  | 958,465 |  |  |  | 560,072 | 
|                         |  |                     |         |  |                       |  |         |               |  |  |         |  |  |       |         |  |     |  |         |  |  |  |         | 



|(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) | Includes certain other properties described under Other Properties above.
|--- | ---------------------------------------------------------------------------

|(4) | For purposes of this table, the Williston Hunter U.S. information includes the North Dakota legacy properties as described under Item 2. PropertiesWilliston
BasinNorth Dakota Legacy Properties above.
|--- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



59



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##### Table of Contents

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



|                         |  |                    |       |  |                    |  |       |                       |  |  |       |  |  |       |       |  |     |  |       |  |  |  |       | 
|------------------------ |  | ------------------ | ----- |  | ------------------ |  | ----- | --------------------- |  |  | ----- |  |  | ----- | ----- |  | --- |  | ----- |  |  |  | ----- | 
|                         |  | ProducingOil Wells |       |  | ProducingGas Wells |  |       | Total 
ProducingWells | 
|                         |  | Gross              |       |  | Net                |  |       | Gross                 |  |  | Net   |  |  | Gross |       |  | Net | 
|Eagle Ford Shale(1)      |  |                    | 17    |  |                    |  | 9     |                       |  |  | 19    |  |  |       | 2     |  |     |  | 36    |  |  |  | 11    | 
|Appalachian Basin        |  |                    | 1,098 |  |                    |  | 1,052 |                       |  |  | 2,014 |  |  |       | 1,205 |  |     |  | 3,112 |  |  |  | 2,257 | 
|Williston Basin          |  |                    |       |  |                    |  |       |                       |  |  |       |  |  |       |       |  |     |  |       |  |  |  |       | 
|Williston Hunter U.S.(2) |  |                    | 262   |  |                    |  | 80    |                       |  |  |      |  |  |       |      |  |     |  | 262   |  |  |  | 80    | 
|Williston Hunter Canada  |  |                    | 20    |  |                    |  | 17    |                       |  |  | 46    |  |  |       | 43    |  |     |  | 66    |  |  |  | 60    | 
|                         |  |                    |       |  |                    |  |       |                       |  |  |       |  |  |       |       |  |     |  |       |  |  |  |       | 
|Total                    |  |                    | 1,397 |  |                    |  | 1,158 |                       |  |  | 2,079 |  |  |       | 1,250 |  |     |  | 3,476 |  |  |  | 2,408 | 
|                         |  |                    |       |  |                    |  |       |                       |  |  |       |  |  |       |       |  |     |  |       |  |  |  |       | 



|(1) | Includes certain other properties described under Other Properties above.
|--- | ---------------------------------------------------------------------------

|(2) | For purposes of this table, the Williston Hunter U.S. information includes the North Dakota legacy properties as described under Item 2. PropertiesWilliston
BasinNorth Dakota Legacy Properties above.
|--- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

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



|                         |       |                  |         |     |  |  |         | 
|------------------------ | ----- | ---------------- | ------- | --- |  |  | ------- | 
|Year Ending
December 31, |       | Expiring Acreage |        
|                         | Gross |                  |         | Net | 
|2012                     |       |                  | 105,799 |     |  |  | 45,228  | 
|2013                     |       |                  | 134,763 |     |  |  | 71,947  | 
|2014                     |       |                  | 81,188  |     |  |  | 18,402  | 
|2015                     |       |                  | 67,046  |     |  |  | 22,298  | 
|                         |       |                  |         |     |  |  |         | 
|Total                    |       |                  | 388,796 |     |  |  | 157,875 | 
|                         |       |                  |         |     |  |  |         | 

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 our activities in the Marcellus Shale where we also utilize the drilling equipment of our subsidiary, Alpha Hunter
Drilling, LLC.



|                     |  |       |       |   |      |  |       |       |  |  |       |   |  |       |       |   |     |  |      |   |  |  |      |  
|-------------------- |  | ----- | ----- | - | ---- |  | ----- | ----- |  |  | ----- | - |  | ----- | ----- | - | --- |  | ---- | - |  |  | ---- | -
|                     |  | 2011  |       |   | 2010 |  |       | 2009  | 
|                     |  | Gross |       |   | Net  |  |       | Gross |  |  | Net   |   |  | Gross |       |   | Net | 
|Exploratory Wells:   |  |       |       |   |      |  |       |       |  |  |       |   |  |       |       |   |     |  |      |   |  |  |      |  
|Productive           |  |       | 0     |   |      |  | 0     |       |  |  | 8     |   |  |       | 6.67  |   |     |  | 3    |   |  |  | 0.70 |  
|Unproductive         |  |       | 0     |   |      |  | 0     |       |  |  | 0     |   |  |       | 0.00  |   |     |  | 1    |   |  |  | 0.10 |  
|                     |  |       |       |   |      |  |       |       |  |  |       |   |  |       |       |   |     |  |      |   |  |  |      |  
|Total                |  |       | 0     |   |      |  | 0     |       |  |  | 8     |   |  |       | 6.67  |   |     |  | 4    |   |  |  | 0.80 |  
|Developmental Wells: |  |       | 98    |   |      |  | 46.73 |       |  |  | 67    |   |  |       | 6.70  |   |     |  | 27   |   |  |  | 3.80 |  
|Total Wells:         |  |       |       |   |      |  |       |       |  |  |       |   |  |       |       |   |     |  |      |   |  |  |      |  
|Productive           |  |       | 98    |   |      |  | 46.73 |       |  |  | 75    |   |  |       | 13.37 |   |     |  | 30   |   |  |  | 4.50 |  
|Unproductive         |  |       | 0     |   |      |  | 0     |       |  |  | 0     |   |  |       | 0.00  |   |     |  | 1    |   |  |  | 0.10 |  
|                     |  |       |       |   |      |  |       |       |  |  |       |   |  |       |       |   |     |  |      |   |  |  |      |  
|Total                |  |       | 98    |   |      |  | 46.73 |       |  |  | 75    |   |  |       | 13.37 |   |     |  | 31   |   |  |  | 4.60 |  
|                     |  |       |       |   |      |  |       |       |  |  |       |   |  |       |       |   |     |  |      |   |  |  |      |  
|Success Ratio(1)     |  |       | 100.0 | % |      |  | 100.0 | %     |  |  | 100.0 | % |  |       | 100.0 | % |     |  | 96.8 | % |  |  | 97.8 | %



|(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 February 27, 2012, we had 41 gross (11.2 net) wells in the process of drilling or completing.



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##### Table of Contents

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 certain segments of our operations as required by SEC rules. 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. Property disposed of that is treated as discontinued operations has been excluded from such periods.



|                                        |  |      |             |  |      |   |           |      |  |   |           | 
|--------------------------------------- |  | ---- | ----------- |  | ---- | - | --------- | ---- |  | - | --------- | 
|                                        |  | 2011 |             |  | 2010 |   |           | 2009 | 
|Buffalo Field(1)                        |  |      |             |  |      |   |           |      |  |   |           | 
|Oil Production (Bbls)                   |  |      | 4,130.5     |  |      |   |          |      |  |   |          | 
|Natural Gas Production (Mcf)            |  |      | 1,979,841.8 |  |      |   |          |      |  |   |          | 
|NGL Production (Bbls)                   |  |      |            |  |      |   |          |      |  |   |          | 
|Total Production (Boe)                  |  |      | 334,104.1   |  |      |   |          |      |  |   |          | 
|Oil Average Sales Price                 |  | $    | 80.90       |  |      | $ |          |      |  |   |          | 
|Natural Gas Average Sales Price         |  | $    | 4.39        |  |      | $ |          |      |  |   |          | 
|NGL Average Sales Price                 |  |      |            |  |      |   |          |      |  |   |          | 
|Average Lease Operating Expense per Boe |  | $    | 54.04       |  |      | $ |          |      |  |   |          | 
|Total Company                           |  |      |             |  |      |   |           |      |  |   |           | 
|Oil Production (Bbls)                   |  |      | 775,641.5   |  |      |   | 316,119.6 |      |  |   | 114,590.0 | 
|Natural Gas Production (Mcf)            |  |      | 6,854,946.7 |  |      |   | 952,174.7 |      |  |   | 191,151.0 | 
|NGL Production (Bbls)                   |  |      | 92,982.4    |  |      |   |          |      |  |   |          | 
|Total Production (Boe)                  |  |      | 2,011,113   |  |      |   | 474,817.3 |      |  |   | 146,449.0 | 
|Oil Average Sales Price                 |  | $    | 90.32       |  |      | $ | 72.41     |      |  | $ | 53.56     | 
|Natural Gas Average Sales Price         |  | $    | 4.59        |  |      | $ | 5.07      |      |  | $ | 2.46      | 
|NGL Average Sales Price                 |  | $    | 51.30       |  |      |   |          |      |  |   |          | 
|Average Lease Operating Expense per Boe |  | $    | 13.46       |  |      | $ | 21.90     |      |  | $ | 26.48     | 



|(1) | This field was part of the assets acquired in the PostRock asset acquisitions. This field consists of 13,293 gross (10,389 net) acres in Wetzel County, West
Virginia with 13 gross (11.5 net) producing wells as of February 27, 2012.
|--- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

Title to Properties

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



| |  |  | customary royalty interests;
| | - |  | ----------------------------



| |  |  | liens incident to operating agreements and for current taxes;
| | - |  | -------------------------------------------------------------



| |  |  | obligations or duties under applicable laws;
| | - |  | --------------------------------------------



| |  |  | development obligations under oil and gas leases;
| | - |  | -------------------------------------------------



| |  |  | net profit interests;
| | - |  | ---------------------



| |  |  | overriding royalty interests;
| | - |  | -----------------------------



| |  |  | non-surface occupancy leases; and
| | - |  | ---------------------------------



| |  |  | lessor consents to placement of wells.
| | - |  | --------------------------------------



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##### Table of Contents

Non-GAAP Measures; Reconciliations

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

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

The standardized measure of discounted future net cash flows relating to our total proved oil and gas reserves is as
follows (in thousands):



|                                                                                    |  |                        |           |  
|----------------------------------------------------------------------------------- |  | ---------------------- | --------- | -
|                                                                                    |  | As
ofDecember 31, 2011 |          
|                                                                                    |  | (Unaudited)            |          
|Future cash inflows                                                                 |  | $                      | 2,409,249 |  
|Future production costs                                                             |  |                        | (765,048  | )
|Future development costs                                                            |  |                        | (330,007  | )
|Future income tax expense                                                           |  |                        | (253,721  | )
|                                                                                    |  |                        |           |  
|Future net cash flows                                                               |  |                        | 1,060,473 |  
|10% annual discount for estimated timing of cash flows                              |  |                        | (586,077  | )
|                                                                                    |  |                        |           |  
|Standardized measure of discounted future net cash flows related to proved reserves |  | $                      | 474,396   |  
|                                                                                    |  |                        |           |  
|Reconciliation of Non-GAAP Measure                                                  |  |                        |           |  
|PV-10                                                                               |  | $                      | 616,870   |  
|Less: Income taxes                                                                  |  |                        |           |  
|Undiscounted future income taxes                                                    |  |                        | (253,721  | )
|10% discount factor                                                                 |  |                        | 111,247   |  
|                                                                                    |  |                        |           |  
|Future discounted income taxes                                                      |  |                        | (142,474  | )
|                                                                                    |  |                        |           |  
|Standardized measure of discounted future net cash flows                            |  | $                      | 474,396   |  
|                                                                                    |  |                        |           |  



|Item 3. | LEGAL PROCEEDINGS
|------- | -----------------

We are not a party to any legal proceedings which management believes will have a material adverse effect on our consolidated results of operations or
financial condition.



|Item 4. | MINE SAFETY DISCLOSURES.
|------- | ------------------------

Not applicable.



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PART II



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

Common Stock Trading Summary

Our common stock trades on the NYSE under the symbol MHR. Prior to January 3, 2011, our common stock traded on the NYSE Amex (formerly the American Stock Exchange). The following table
summarizes the high and low reported sales prices on days in which there were trades of our common stock on the NYSE or NYSE Amex for each quarterly period for the last two fiscal years. On February 27, 2012, the last reported sale price of our
common stock, as reported on the NYSE, was $7.24 per share.



|               |  |      |      |  |     |   |      | 
|-------------- |  | ---- | ---- |  | --- | - | ---- | 
|               |  | High |      |  | Low |  
|2011:          |  |      |      |  |     |   |      | 
|First quarter  |  | $    | 8.62 |  |     | $ | 6.44 | 
|Second quarter |  |      | 8.66 |  |     |   | 5.76 | 
|Third quarter  |  |      | 7.90 |  |     |   | 3.28 | 
|Fourth quarter |  |      | 5.59 |  |     |   | 2.33 | 
|2010:          |  |      |      |  |     |   |      | 
|First quarter  |  | $    | 3.29 |  |     | $ | 1.50 | 
|Second quarter |  |      | 5.49 |  |     |   | 3.00 | 
|Third quarter  |  |      | 4.85 |  |     |   | 3.75 | 
|Fourth quarter |  |      | 8.05 |  |     |   | 3.87 | 

Holders

As of February 27, 2012, based on information from our transfer agent, American Stock Transfer and Trust Company, we had 316 holders of record of the
outstanding shares of our common stock, which record holders included Cede & Co., as nominee of the Depository Trust and Clearing Corporation, or DTC. As of that same date, Cede & Co., as nominee of the DTC, was the sole holder of
record of the outstanding shares of our Series C Preferred Stock and Series D Preferred Stock. Cede & Co., as nominee of the DTC, holds securities, including our common and preferred stock, on behalf of numerous direct and indirect
beneficial owners.

Dividends

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



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Securities Authorized for Issuance Under Equity Compensation Plans

The following table provides information with respect to our common shares issuable under our equity compensation plans as of December 31, 2011:



|                                                           |  |                                                                                         |            |  |                                                                         |   |      |                                                                                                                                       |  |  |           | 
|---------------------------------------------------------- |  | --------------------------------------------------------------------------------------- | ---------- |  | ----------------------------------------------------------------------- | - | ---- | ------------------------------------------------------------------------------------------------------------------------------------- |  |  | --------- | 
|                                                           |  | Number of Securitiesto be
Issued UponExercise
ofOutstanding Options,Warrants and Rights |            |  | Weighted-AverageExercise Price
ofOutstanding Options,Warrants
andRights |   |      | Number of SecuritiesRemaining Available
forFuture Issuance UnderEquity Compensation Plans(Excluding SecuritiesReflected in Column(a)) | 
|                                                           |  | (a)                                                                                     |            |  | (b)                                                                     |   |      | (c)                                                                                                                                   | 
|Equity compensation plans approved by security holders     |  |                                                                                         | 12,603,805 |  |                                                                         | $ | 5.64 |                                                                                                                                       |  |  | 5,123,985 | 
|Equity compensation plans not approved by security holders |  |                                                                                         |           |  |                                                                         | $ |     |                                                                                                                                       |  |  |          | 
|                                                           |  |                                                                                         |            |  |                                                                         |   |      |                                                                                                                                       |  |  |           | 
|Total                                                      |  |                                                                                         | 12,603,805 |  |                                                                         | $ | 5.64 |                                                                                                                                       |  |  | 5,123,985 | 

The Companys stock incentive plan provides for the grant of stock options, shares of restricted stock, unrestricted
shares of stock, performance stock and stock appreciation rights. Awards under the stock incentive plan may be made to any employee, officer, or director of the Company or any subsidiary or to consultants and advisors to the Company or any
subsidiary. For additional information regarding our stock incentive plan, see Note 10Share Based Compensation to our consolidated financial statements.

Recent Sales of Unregistered Securities

During the year ended December 31, 2011, the
Company sold from time to time an aggregate of 813,857 shares of its common stock pursuant to the exercise of certain warrants, as follows:

(a) The Company sold an aggregate of 771,812 shares of its common stock pursuant to the exercise of certain warrants issued by the Company in 2006, at an exercise price of $3.00 per share, for total
gross proceeds of approximately $2,315,416. The warrants were issued by the Company in connection with a private placement by the Company of units, consisting of shares of common stock and warrants to purchase shares of common stock, to fund the
purchase of certain assets by the Company.

(b) The Company sold an aggregate of 42,045 shares of common stock pursuant to
the exercise of certain warrants issued by the Company in November 2009, at an exercise price of $2.50 per share, for total gross proceeds of approximately $105,113. The warrants were issued by the Company in connection with an offering by the
Company of units, consisting of shares of common stock and warrants to purchase shares of common stock, to a limited number of investors for cash, which was registered under the Securities Act. These investors consisted of certain directors and
officers of the Company and certain of their friends and associates.

In addition, during the year ended December 31, 2011:

(c) The Company issued 946,314 shares of common stock pursuant to the PostRock asset acquisitions.

(d) The Company issued 166,000 shares of common stock in payment of a lender commitment fee for the Eureka Hunter Term Loan.

(e) The Company issued 6,986,104 shares of common stock in connection with the acquisition of NGAS.

(f) The Company issued 38,131,846 shares of common stock pursuant to the acquisition of NuLoch.

(g) MHR Exchangeco Corporation issued 4,275,998 shares of stock exchangeable into common stock of the Company pursuant to the acquisition
of NuLoch.



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The shares described above were issued or sold by the Company in reliance on the exemption from registration
afforded by Section 4(2) of the Securities Act and/or Regulation D promulgated thereunder, except for the shares described in paragraphs (e), (f) and (g), which were issued or sold by the Company in reliance on the exemption from
registration afforded by Section 3(a)(10) of the Securities Act.

Share Performance Graph

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

The following graph illustrates changes over the five-year period ended December 31, 2011 in cumulative total stockholder return on our common stock
as measured against the cumulative total return of the S&P 500 Index and the Dow Jones U.S. Exploration and Production Index. The results assume $100 was invested on December 31, 2006, and that dividends were reinvested.

COMPARISON OF 5 YEAR CUMULATIVE TOTAL RETURN



LOGO



|                                    |  |              |        |  |      |  |        |      |  |  |       |  |  |      |        |  |      |  |        |  |  |  |        | 
|----------------------------------- |  | ------------ | ------ |  | ---- |  | ------ | ---- |  |  | ----- |  |  | ---- | ------ |  | ---- |  | ------ |  |  |  | ------ | 
|                                    |  | December 31, |       
|                                    |  | 2006         |        |  | 2007 |  |        | 2008 |  |  | 2009  |  |  | 2010 |        |  | 2011 | 
|Magnum Hunter Resources Corporation |  |              | 100.00 |  |      |  | 70.22  |      |  |  | 11.70 |  |  |      | 54.96  |  |      |  | 255.31 |  |  |  | 191.12 | 
|                                    |  |              |        |  |      |  |        |      |  |  |       |  |  |      |        |  |      |  |        |  |  |  |        | 
|S & P 500                           |  |              | 100.00 |  |      |  | 105.49 |      |  |  | 66.46 |  |  |      | 84.05  |  |      |  | 96.71  |  |  |  | 98.76  | 
|                                    |  |              |        |  |      |  |        |      |  |  |       |  |  |      |        |  |      |  |        |  |  |  |        | 
|Dow Jones US Expl & Production      |  |              | 100.00 |  |      |  | 143.66 |      |  |  | 86.02 |  |  |      | 120.92 |  |      |  | 141.15 |  |  |  | 135.24 | 



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|Item 6. | SELECTED FINANCIAL DATA
|------- | -----------------------

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



|                                             |  |                                       |           |   |      |   |          |      |  |   |         |   |  |      |         |   |  |   |         |  
|-------------------------------------------- |  | ------------------------------------- | --------- | - | ---- | - | -------- | ---- |  | - | ------- | - |  | ---- | ------- | - |  | - | ------- | -
|                                             |  | Year Ended December 31,               |          
|                                             |  | 2011                                  |           |   | 2010 |   |          | 2009 |  |   | 2008    |   |  | 2007 |        
|                                             |  | (In thousands, except per-share data) |          
|Income Statement Data                        |  |                                       |           |   |      |   |          |      |  |   |         |   |  |      |         |   |  |   |         |  
|Revenues                                     |  | $                                     | 129,178   |   |      | $ | 32,724   |      |  | $ | 6,844   |   |  | $    | 11,590  |   |  | $ | 6,638   |  
|Loss from continuing operations              |  |                                       | (76,661   | ) |      |   | (22,257  | )    |  |   | (15,569 | ) |  |      | (9,468  | ) |  |   | (5,781  | )
|Income from discontinued operations          |  |                                       |          |   |      |   | 8,457    |      |  |   | 445     |   |  |      | 2,582   |   |  |   | 242     |  
|Net loss                                     |  |                                       | (76,661   | ) |      |   | (13,800  | )    |  |   | (15,124 | ) |  |      | (6,886  | ) |  |   | (5,539  | )
|Dividends on preferred stock                 |  |                                       | (14,007   | ) |      |   | (2,467   | )    |  |   | (26     | ) |  |      | (734    | ) |  |   | (511    | )
|Net loss attributable to common shareholders |  | $                                     | (90,668   | ) |      | $ | (16,267  | )    |  | $ | (15,150 | ) |  | $    | (7,620  | ) |  | $ | (6,050  | )
|Basic and Diluted Earnings (Loss) Per Share  |  |                                       |           |   |      |   |          |      |  |   |         |   |  |      |         |   |  |   |         |  
|Continuing operations                        |  | $                                     | (0.80     | ) |      | $ | ( 0.38   | )    |  | $ | (0.40   | ) |  | $    | (0.28   | ) |  | $ | (0.30   | )
|Discontinued operations                      |  |                                       |          |   |      |   | 0.13     |      |  |   | 0.01    |   |  |      | 0.07    |   |  |   | 0.02    |  
|                                             |  |                                       |           |   |      |   |          |      |  |   |         |   |  |      |         |   |  |   |         |  
|Net loss per share                           |  | $                                     | (0.80     | ) |      | $ | (0.25    | )    |  | $ | (0.39   | ) |  | $    | (0.21   | ) |  | $ | (0.28   | )
|                                             |  |                                       |           |   |      |   |          |      |  |   |         |   |  |      |         |   |  |   |         |  
|Statement of Cash Flows Data                 |  |                                       |           |   |      |   |          |      |  |   |         |   |  |      |         |   |  |   |         |  
|Net cash provided by (used in)               |  |                                       |           |   |      |   |          |      |  |   |         |   |  |      |         |   |  |   |         |  
|Operating activities                         |  | $                                     | 33,838    |   |      | $ | (1,167   | )    |  | $ | 3,372   |   |  |      | 3,437   |   |  | $ | 854     |  
|Investing activities                         |  |                                       | (361,715  | ) |      |   | (118,281 | )    |  |   | (16,624 | ) |  |      | (10,379 | ) |  |   | (29,964 | )
|Financing activities                         |  |                                       | 342,193   |   |      |   | 117,720  |      |  |   | 9,413   |   |  |      | (2,338  | ) |  |   | 40,225  |  
|Balance Sheet Data                           |  |                                       |           |   |      |   |          |      |  |   |         |   |  |      |         |   |  |   |         |  
|Cash and cash equivalents                    |  | $                                     | 14,851    |   |      | $ | 554      |      |  | $ | 2,282   |   |  | $    | 6,121   |   |  | $ | 15,400  |  
|Other current assets                         |  |                                       | 62,462    |   |      |   | 12,572   |      |  |   | 4,591   |   |  |      | 4,059   |   |  |   | 3,329   |  
|Property, equipment, net, successful efforts |  |                                       | 1,078,506 |   |      |   | 232,601  |      |  |   | 46,410  |   |  |      | 39,134  |   |  |   | 42,482  |  
|Method                                       |  |                                       |           |   |      |   |          |      |  |   |         |   |  |      |         |   |  |   |         |  
|Other assets                                 |  |                                       | 12,585    |   |      |   | 3,240    |      |  |   | 13,301  |   |  |      | 12,351  |   |  |   | 5,152   |  
|                                             |  |                                       |           |   |      |   |          |      |  |   |         |   |  |      |         |   |  |   |         |  
|Total assets                                 |  | $                                     | 1,168,404 |   |      | $ | 248,967  |      |  | $ | 66,584  |   |  | $    | 61,665  |   |  | $ | 66,363  |  
|                                             |  |                                       |           |   |      |   |          |      |  |   |         |   |  |      |         |   |  |   |         |  
|Current liabilities                          |  | $                                     | 167,319   |   |      | $ | 44,235   |      |  | $ | 6,219   |   |  | $    | 3,497   |   |  | $ | 14,274  |  
|Long-term debt                               |  |                                       | 286,064   |   |      |   | 26,019   |      |  |   | 13,000  |   |  |      | 21,500  |   |  |   |        |  
|Other long-term liabilities                  |  |                                       | 124,369   |   |      |   | 5,155    |      |  |   | 2,673   |   |  |      | 1,590   |   |  |   | 2,108   |  
|Redeemable preferred stock                   |  |                                       | 100,000   |   |      |   | 70,236   |      |  |   | 5,374   |   |  |      |        |   |  |   | 7,232   |  
|Shareholders equity                         |  |                                       | 490,652   |   |      |   | 103,322  |      |  |   | 39,318  |   |  |      | 35,078  |   |  |   | 42,749  |  
|                                             |  |                                       |           |   |      |   |          |      |  |   |         |   |  |      |         |   |  |   |         |  
|Total liabilities and shareholders equity   |  | $                                     | 1,168,404 |   |      | $ | 248,967  |      |  | $ | 66,584  |   |  | $    | 61,665  |   |  | $ | 66,363  |  
|                                             |  |                                       |           |   |      |   |          |      |  |   |         |   |  |      |         |   |  |   |         |  



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|Item 7. | MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
|------- | -------------------------------------------------------------------------------------

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

General and Business Overview

We are an
independent oil and gas company engaged in the exploration for and the exploitation, acquisition, development and production of crude oil, natural gas and natural gas liquids, primarily in the states of West Virginia, Ohio, Texas, Kentucky and North
Dakota and in Saskatchewan, Canada. We are also engaged in midstream operations involving the gathering of natural gas through our ownership and operation of a gas gathering system in West Virginia and Ohio, referred to as our Eureka Hunter Pipeline
System. We are presently active in three of the most prolific unconventional shale resource plays in North America, namely the Marcellus/Utica Shales in West Virginia and Ohio, the Eagle Ford Shale in south Texas and the Williston Basin/Bakken Shale
in North Dakota and Saskatchewan, Canada.

In May 2009, we restructured our management team and completely refocused our business strategy.
Our business strategy is to exploit our inventory of lower risk drilling locations and acquire undeveloped leases and long-lived proved reserves with significant exploitation and development opportunities primarily located in unconventional resource
plays. Over the past three years, we have substantially increased our assets and production base through a combination of acquisitions, joint ventures and ongoing development drilling efforts; our percentage of operated properties has increased
significantly; our inventory of acreage and drilling locations in resource plays has grown dramatically; and our management team has been expanded. We are focused on the further development and exploitation of our core unconventional resource plays,
the acquisition of additional operated properties in our core operating regions, and selective expansion of our midstream operations.

2011
Recap and 2012 Outlook

Post Rock Asset Acquisitions. On December 24, 2010, the Companys subsidiary, Triad Hunter,
entered into a transaction for the acquisition of certain Marcellus Shale oil and gas properties and leasehold mineral interests located in Wetzel and Lewis Counties, West Virginia from affiliates of PostRock Energy Corporation.

On December 30, 2010, Triad Hunter closed on the first phase of the transaction for $31.0 million consisting of (i) $13.9 million in cash and
(ii) approximately 2.3 million newly issued restricted common shares (valued at approximately $17.1 million using a price of $7.58 per share). On January 14, 2011, Triad Hunter closed on the second phase of the transaction for the
acquisition of certain Marcellus Shale assets located in Lewis County for a total purchase price of $13.3 million. The purchase price consisted of (i) $5.8 million in cash and (ii) 946,314 newly issued restricted common shares of Magnum
Hunter (valued at approximately $7.5 million based on a closing stock price of $7.97 per share). On June 16, 2011, Triad Hunter closed on the third phase of the transaction for the acquisition of certain Marcellus Shale assets located in Lewis
County for a total purchase price of $4.9 million in cash before considering applicable adjustments.

Windsor Asset Acquisition.On April 7, 2011, Triad Hunter entered into an agreement with Windsor Marcellus LLC, or Windsor, pursuant to which Triad Hunter agreed to purchase certain oil and gas properties and leasehold mineral interests and related assets
located in Wetzel County, West Virginia for total consideration of $20.0 million in cash. The closing of the acquisition of the Windsor assets occurred on April 7, 2011. The Windsor assets included approximately 2,225 net contiguous acres. The
fair value of the net assets acquired from Windsor, based on our preliminary assessment, approximated the $20.0 million in consideration paid.



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NGAS Acquisition.On April 13, 2011, the Company completed the acquisition of all of the
outstanding common shares of 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 per share on April 13, 2011), and $1.2 million in liability for NGAS warrants, of which $1.0 million was paid out upon exercise of the cash option and 138,388 warrants are outstanding that are exercisable for common
stock of the Company. Including the repayment at closing of debt assumed, total cash payments in connection with the acquisition were $62.3 million. 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. Additionally, the name of another subsidiary, NGAS Securities, Inc. was changed to Energy Hunter Securities, Inc. The fair value of the net assets acquired from
NGAS, based on our preliminary assessment, approximated the $124.5 million in consideration paid.

NuLoch Acquisition.On
May 3, 2011, the Company completed the acquisition of all of the outstanding common shares of 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
per share 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 fair value of the net assets acquired from NuLoch, based on our preliminary assessment, approximated the $430.5 million in consideration paid.

Expansion of Credit Facilities. Our lenders significantly expanded our MHR Senior Revolving Credit Facility through six separate borrowing base increases over the last 12 months. At
January 1, 2011, the MHR Senior Revolving Credit Facility had a borrowing base of $71.5 million. As a result of the six borrowing base increases, the borrowing base under this facility is now $235 million. In addition, in 2011, we obtained our
MHR Term Loan Facility, pursuant to which we obtained a $100 million term loan, which closed and was fully funded in September 2011. Also in 2011, we obtained our Eureka Hunter Credit Facilities in the total amount of $150 million for Eureka Hunter
Pipeline, LLC, or Eureka Hunter, our wholly-owned subsidiary which owns and operates our Eureka Hunter Pipeline System. The Eureka Hunter Credit Facilities were established to fund Eureka Hunters pipeline development capital expenditures on a
non-recourse basis to Magnum Hunter. The Eureka Hunter Credit Facilities consist of (i) a revolving credit facility in an aggregate principal amount of up to $100 million (with an initial committed amount of $25 million) and (ii) a $50
million term loan facility, both of which closed in August 2011. For more information regarding our credit facilities, see Credit Facilities below.

Marcellus Shale Gas Processing Arrangements.In October 2011, Triad Hunter entered into certain midstream services agreements with MarkWest Liberty Midstream & Resources, L.L.C. and
an affiliate, collectively MarkWest Liberty, pursuant to which MarkWest Liberty will provide long-term gas processing and related services for natural gas produced in northwest West Virginia by both Triad Hunter and other producers that is gathered
through our Eureka Hunter Pipeline System. In October 2011, Eureka Hunter and MarkWest Liberty entered into a mutual cooperation agreement whereby both companies agreed to jointly develop natural gas-related services to support Marcellus Shale
producers in a significant geographic area in northwest West Virginia. Pursuant to this agreement, Eureka Hunter sold its 200 mmcfe per day capacity Thomas Russell cryogenic natural gas processing plant, which was then under construction, to
MarkWest Liberty. MarkWest Liberty intends to install this new plant, the Mobley 2 plant, adjacent to MarkWest Libertys 120 mmcfe per day capacity natural gas processing plant, the Mobley 1 plant, near Logansport, West Virginia. We anticipate
that the Mobley 1 plant will be in commercial operation during the third quarter of 2012 and the Mobley 2 plant will be in commercial operation during the fourth quarter of 2012. MarkWest Liberty will also provide natural gas liquids handling
and fractionation services for Mobley plant product. These agreements with MarkWest Liberty will allow Eureka Hunter to offer third party producers in the Marcellus Shale not only gas gathering services through our Eureka Hunter Pipeline System, but
also access to natural gas processing at MarkWest Libertys Mobley complex.



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Eureka Hunter plans to extend its Eureka Hunter Pipeline System to the Mobley processing complex before
July 1, 2012 to enable it to deliver unprocessed natural gas production to both Mobley plants for processing. Eureka Hunter will be gathering both Triad Hunters and other third parties natural gas production for delivery to the
Mobley processing complex. Initial delivery volumes from Eureka Hunter to the Mobley complex are currently estimated to be in the 50 to 75 mmbtu per day range. Additionally, natural gas production processed at the Mobley complex will be able to
access both the Columbia Gas Transmission and the Equitrans interstate pipeline systems.

Equity Financings.We raised
substantial cash in the total amount of $146.8 million in net proceeds, which are net of commissions, through equity transactions during 2011 through February 27, 2012. Those transactions included:



| |  |  | $13.9 million in net proceeds from common equity issuances, at an average price of $8.27 per share;
| | - |  | ---------------------------------------------------------------------------------------------------



| |  |  | $29.2 million in net proceeds from the issuance of our Series C Preferred Stock, at a price of $25.00 per share;
| | - |  | ----------------------------------------------------------------------------------------------------------------



| |  |  | $7.6 million in net proceeds from the exercise of warrants and common stock options; and
| | - |  | ----------------------------------------------------------------------------------------



| |  |  | $96.1 million in net proceeds from the issuance of our Series D Preferred Stock.
| | - |  | --------------------------------------------------------------------------------

We plan to continue raising both preferred and common equity in the future depending on our working capital needs, capital expenditure program,
acquisition activities, and the overall capital markets.

Core Upstream Properties

Eagle Ford Shale.The Company made its initial entry into the Eagle Ford Shale through the acquisition of Sharon Resources, Inc. in October
2009. We subsequently expanded our Eagle Ford Shale position through additional leasing activities and entry into two joint ventures, one with Hunt Oil Company in May 2010, and the other with a private independent oil and gas company in October
2010. Our Eagle Ford Shale properties are held primarily by our wholly-owned subsidiary, Eagle Ford Hunter, Inc.

As of February 27,
2012, our Eagle Ford Shale properties included approximately 54,000 gross (24,000 net) acres primarily targeting the Eagle Ford Shale oil window, principally in Gonzales and Lavaca Counties, Texas. As of December 31, 2011, proved reserves
attributable to our Eagle Ford Shale properties were 5.4 mmboe on an SEC basis, of which 94% were oil and 24% were classified as proved developed producing, and 5.4 mmboe on a NYMEX basis. As of February 27, 2012, our Eagle Ford Shale
properties included 18 gross (10 net) productive wells, of which we operated 14.

Williston Basin.The Company made its entry
into the Williston Basin through the acquisition of interests in waterflood properties in North Dakota from a private independent oil and gas company in December 2006. We expanded our position in the Williston Basin with the acquisition of NuLoch in
May 2011. The acquired NuLoch properties included operated properties in Alberta and Saskatchewan, Canada and non-operated properties in North Dakota.

As of February 27, 2012, our Williston Basin properties included approximately 413,003 gross (122,561 net) acres. As of December 31, 2011, proved reserves attributable to our Williston
Basin properties were 8.9 mmboe on an SEC basis, of which 94% were oil and 42% were classified as proved developed producing, and 8.8 mmboe on an NYMEX basis. As of February 27, 2012, the Williston Basin properties included approximately 288
gross (98.9 net) productive wells.

Appalachian Basin.The Company made its entry into the Appalachian Basin in February 2010
through the acquisition by our wholly-owned subsidiary, Triad Hunter, of substantially all the assets of privately-held Triad



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Energy. In 2010 and 2011, Triad Hunter expanded its position in the Marcellus Shale area of the Appalachian Basin through multiple transactions, including the PostRock asset acquisitions, the
Windsor asset acquisition and the Stone Energy joint venture. The Company further expanded its presence in the southern Appalachian Basin through the acquisition of NGAS in April 2011. Triad Hunter recently expanded its leasehold position in the
Utica Shale through an acquisition of approximately 15,558 gross (12,186 net) acres in southeastern Ohio.

As of February 27, 2012, our
Appalachian Basin properties included a total of approximately 484,412 gross (412,323 net) acres, located primarily in the Marcellus Shale, Utica Shale and southern Appalachian Basin. At December 31, 2011, proved reserves attributable to our
Appalachian Basin properties were 29.9 mmboe on an SEC basis, of which 27% were oil and 59% were classified as proved developed producing, and 30.2 mmboe a NYMEX basis. As of February 27, 2012, the Appalachian Basin properties included
approximately 3,112 gross (2,257 net) productive wells, of which we operated approximately 88%.

As of February 27, 2012, we had
approximately 58,426 net acres in the Marcellus Shale area of West Virginia and Ohio. Our Marcellus Shale acreage is located principally in Tyler, Pleasants, Doddridge, Wetzel and Lewis Counties, West Virginia and in Washington, Monroe and
Noble Counties, Ohio. As of February 27, 2012, the Company operated 33 vertical Marcellus Shale wells and 16 horizontal Marcellus Shale wells. As of February 27, 2012, approximately 63% of our leases in the Marcellus Shale area were held
by production.

As of February 27, 2012, Triad Hunter owned mineral rights to a total of approximately 61,151 net acres that are
presently prospective for the Utica Shale. Approximately 17,375 of these net acres are located in Ohio (which include the acreage acquired in February 2012 and the balance of which overlaps our Marcellus Shale acreage), and approximately 43,776 of
the net acres are located in West Virginia (all of which overlaps our Marcellus Shale acreage).

As of February 27, 2012, our properties
located in the southern Appalachian Basin included approximately 367,140 gross (313,124 net) lease acres located primarily in Kentucky. Our primary production from these properties comes from the Devonian Shale formation and the Mississippian Weir
sandstone.

Midstream

Eureka Hunter Pipeline System. Our acquisition of assets from Triad Energy in 2010 included important infrastructure assets for the
efficient development of the Companys Marcellus Shale and Utica Shale unconventional resources. As of February 27, 2012, these assets include approximately 207 miles of pipeline, gathering systems and/or rights-of-way, which we are
currently developing, located in northwestern West Virginia and southeastern Ohio, in the Marcellus and Utica Shales. We expect to have sufficient pipeline capacity to gather significant quantities of Company-produced natural gas from our Marcellus
Shale and Utica Shale development programs, as well as substantial volumes of third-party gas.

MarkWest Processing
Agreement.In October 2011, Triad Hunter entered into certain midstream services agreements with MarkWest Liberty pursuant to which MarkWest Liberty will provide long-term gas processing and related services for natural gas
produced in northwest West Virginia gathered by Eureka Hunter for both Triad Hunter and other producers through the Eureka Hunter Pipeline System. In October 2011, Eureka Hunter and MarkWest Liberty entered into a mutual cooperation agreement
whereby both companies agreed to jointly develop natural gas-related services to support Marcellus Shale producers in a significant geographic area in northwest West Virginia. Pursuant to this agreement, Eureka Hunter sold its 200 mmcfe per day
capacity Thomas Russell cryogenic natural gas processing plant, which was then under construction, to MarkWest Liberty. MarkWest Liberty intends to install this new plant, the Mobley 2 plant, adjacent to MarkWest Libertys 120 mmcfe per day
capacity natural gas processing plant, the Mobley 1 plant, near Logansport, West Virginia. We anticipate that the Mobley 1 plant will be in commercial operation during the third quarter of 2012 and the Mobley 2 plant will be in commercial
operation during the fourth quarter of 2012. MarkWest Liberty will also provide natural gas liquids handling and fractionation services for plant product. Natural gas production



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processed at the Mobley complex will be able to access both the Columbia Gas Transmission and the Equitrans interstate pipeline systems. These arrangements with MarkWest Liberty will allow Eureka
Hunter to offer third party producers in the Marcellus Shale not only gas gathering services through the Eureka Hunter Pipeline System, but also access to natural gas processing at MarkWest Libertys Mobley complex.

Equipment and Services

Our wholly-owned
subsidiary, Alpha Hunter Drilling, LLC, currently owns and operates five drilling rigs capable of drilling 6,000 to 10,000 feet, which are primarily used for vertical section (top-hole) air drilling. The drilling rigs are used for both the
Companys Appalachian Basin operations and to provide drilling services to third parties. The Companys fleet consists of three Schramm T200XD drilling rigs and two Schramm T130XD drilling rigs. 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.

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 special, 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; and
| | - |  | --------------------------------------------------------------------------------------------------------



| |  |  | 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 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 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.
| | - |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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Proved Reserves

On December 31, 2008, the SEC released a Final Rule,Modernization of Oil and Gas Reporting, approving revisions designed to modernize oil and gas reserve reporting requirements. The new
reserve rules first became effective for our financial statements for the year ended December 31, 2009 and our 2009 year-end proved reserve estimates. The most significant revisions to the reporting requirements include:



| |  |  | Commodity prices. Economic producibility of reserves is now based on the unweighted, arithmetic average of the closing price on the first
day of the month for the 12-month period prior to fiscal year end, unless prices are defined by contractual arrangements;
| | - |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Undeveloped oil and gas reserves. Reserves may be classified as proved undeveloped for undrilled areas beyond one offsetting
drilling unit from a producing well if there is reasonable certainty that the quantities will be recovered;
| | - |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Reliable technology. The rules now permit the use of new technologies to establish the reasonable certainty of proved reserves if those
technologies have been demonstrated empirically to lead to reliable conclusions about reserves volumes;
| | - |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Unproved reserves. Probable and possible reserves may be disclosed separately on a voluntary basis;
| | - |  | ---------------------------------------------------------------------------------------------------



| |  |  | Preparation of reserves estimates. Disclosure is required regarding the internal controls used to assure objectivity in the reserves
estimation process and the qualifications of the technical person primarily responsible for preparing reserves estimates; and
| | - |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Third party reports. We are now required to file with the SEC the report of any third party used to prepare or audit our reserve estimates.
| | - |  | -------------------------------------------------------------------------------------------------------------------------------------------

In addition, in January 2010, FASB issued Accounting Standards Update 2010-03, or the Update, Oil and Gas Reserve
Estimation and Disclosures, to provide consistency with the new reserve rules. The Update amends existing standards to align the reserves estimation and disclosure requirements under GAAP with the requirements in the SECs reserve rules.
We adopted the new standards effective December 31, 2009. The new standards are applied prospectively as a change in estimate.

For the
year ended December 31, 2011, we engaged Cawley, Gillespie & Associates, Inc. and AJM Deloitte and Touche, LLP, independent petroleum engineers, to prepare independent estimates of the extent and value of the proved reserves associated
with certain of our oil and gas properties in accordance with guidelines established by the SEC, including the recent 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, 2011, were estimated based on the unweighted, arithmetic average of the closing price on the first day of each month for the 12-month period prior to December 31, 2011 for oil
and natural gas in accordance with the new reserve rules. The average price used for oil was $96.19 and for natural gas was $4.11.

See also
Items 1.Business and 2. PropertiesProved Reserves and Note 13Other Information to our consolidated financial statements for additional information regarding our estimated proved reserves.



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Derivative Instruments and Commodity Derivative Activities

Unrealized gains and losses, at fair value, 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. Changes in the fair value of our commodity derivative contracts are recorded in earnings as they occur and included in other income (expense) on our consolidated
statements of operations. 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 our internal valuations 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.

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.

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. For qualifying cash-flow commodity derivatives, the gain or loss on the derivative is deferred in accumulated
other comprehensive (loss) income to the extent the commodity derivative is effective. The ineffective portion of the commodity derivative is recognized immediately in the statement of operations. Gains and losses on commodity derivative instruments
included in accumulated other comprehensive (loss) income are reclassified to oil and gas sales revenue in the period that the related production is delivered. Derivative contracts that do not qualify for commodity derivative accounting treatment
are recorded as derivative assets and liabilities at fair value in the balance sheet, and the associated unrealized gains and losses are recorded as current income or expense in the statement of operations.

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 changes in such fair value in earnings on our consolidated statements of operations under the caption entitled Gain (loss) on derivative
contracts.

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. We recorded
(i) a realized loss from the settlement of derivative contracts of $2.1 million for the year ended December 31, 2011, (ii) a realized gain from the settlement of derivative contracts of $3.9 million for the year ended
December 31, 2010 and (iii) a realized gain from the settlement of derivative contracts of $5.4 million for the year ended December 31, 2009. Realized gains and losses result from actual cash settlements received or paid under the
derivative contracts. For the year ended December 31, 2011, we recognized an unrealized loss of $4.2 million from the change in the fair value of commodity derivatives. For the year ended December 31, 2010, we recognized an unrealized loss
of $3.1 million from the change in the fair value of commodity derivatives. For the year ended December 31, 2009, we recognized an unrealized loss of $7.7 million from the change in the fair value of commodity derivatives. 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. A hypothetical 10% increase in the NYMEX floating prices would have resulted in a $24.0 million decrease in the December 31, 2011 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 $22.4 million decrease in the December 31, 2011 fair value recorded on our balance sheet and would have partially
offset the loss 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 to our consolidated financial statements for additional information on our derivative instruments.



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Asset Retirement Obligation

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

Our liability is determined using significant assumptions, including current estimates of plugging and abandonment costs, annual inflation of
these costs, the productive lives of wells and our risk-adjusted interest rate. Changes in any of these assumptions can result in significant revisions to the estimated asset retirement obligation. Our liability for asset retirement obligations was
approximately $20.1 million and $4.5 million at December 31, 2011 and 2010, respectively. See Note 8Asset Retirement Obligations to our consolidated financial statements for more information.

Share-Based Compensation

Our
stock incentive plan allows grants of stock, options, and other stock-based awards to employees and outside directors. Grants of awards may increase our general and administrative expenses subject to the size and timing of the grants. For the years
ended December 31, 2011, 2010, and 2009, we recognized approximately $23.1 million, $6.4 million, and $3.1 million in non-cash stock compensation, respectively. See Note 10Share Based Compensation to our consolidated
financial statements for additional information.

Valuation of Property and Equipment

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 oil and gas properties, be assessed for potential impairment in their carrying values whenever events or changes in circumstances indicate such
impairment may have occurred. An impairment charge to current operations is recognized when the estimated undiscounted future net cash flows of the asset are less than its carrying value. Any such impairment is recognized based on the
differences in the carrying value and estimated fair value of the impaired asset.

The guidance provides for future revenue from the
Companys oil and gas production to be estimated based upon prices at which management reasonably estimates such products will be sold. These estimates of future product prices may differ from current market prices of oil and gas. Any downward
revisions to managements estimates of future production or product prices could result in an impairment of the Companys 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. Due to the regularly scheduled impairment reviews by management, the Company recognized a
non-cash, pre-tax charge against earnings of approximately $22.9 million, $0.3 million, and $0.6 million, for the years ended December 31, 2011, 2010, and 2009, respectively. The 2011 impairment of proved oil and gas properties was calculated
on a field by field basis under the successful efforts accounting method. The 2011 impairment was recorded based upon the estimated fair value of a 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. See Note 2Summary of Significant Accounting Policies to our
consolidated financial statements for additional information.



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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.

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

We account for
income taxes under the liability method. Deferred tax assets and liabilities are determined based on differences between financial reporting and tax bases of assets and liabilities and are measured using the enacted tax rates and laws that will be
in effect when the differences are expected to reverse. We measure and record income tax contingency accruals in accordance with ASC 740, Income Taxes.

We recognize liabilities for uncertain income tax positions based on a two-step process. The first step is to evaluate the tax position for recognition by determining if the weight of available evidence
indicates that it is more likely than not that the position will be sustained on audit, including resolution of related appeals or litigation processes, if any. The second step requires us to estimate and measure the tax benefit as the largest
amount that is more than 50% likely to be realized upon ultimate settlement. It is inherently difficult and subjective to estimate such amounts, as we must determine the probability of various possible outcomes. We reevaluate these uncertain tax
positions on a quarterly basis or when new information becomes available to management. These reevaluations are based on factors including, but not limited to, changes in facts or circumstances, changes in tax law, successfully settled issues under
audit, expirations due to statutes, and new audit activity. Such a change in recognition or measurement could result in the recognition of a tax benefit or an increase to the tax accrual.

We classify interest related to income tax liabilities as income tax expense, and if applicable, penalties are recognized as a component of income tax expense. The income tax liabilities and accrued
interest and penalties that are anticipated to be due within one year of the balance sheet date are presented as current liabilities in our consolidated balance sheets.See Note 11Income Taxes to our consolidated
financial statements for additional information.

Recently Issued Accounting Pronouncements

In May 2011, the FASB issued ASU 2011-04, Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs. The
amended guidance changes several aspects of the fair value measurement guidance in ASC 820, Fair Value Measurement, further clarifying how to measure and disclose fair value. This guidance amends the application of the highest and best
use concept to be used only in the measurement of fair value of nonfinancial assets, clarifies that the measurement of the fair value of equity-classified financial instruments should be performed from the perspective of a market participant
who holds the instrument as an asset, clarifies that an entity that manages a group of financial assets and liabilities on the basis of its net risk exposure can measure those financial instruments on the basis of its net exposure to those risks,
and



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clarifies when premiums and discounts should be taken into account when measuring fair value. The fair value disclosure requirements also were amended. The amendment is effective for the Company
at the beginning of January 2012, with early adoption prohibited. The adoption of this amendment is not expected to materially affect the Companys financial statements.

In June 2011, the FASB issued ASU 2011-05, Presentation of Comprehensive Income which amended requirements for the presentation of other comprehensive income (OCI), requiring presentation of comprehensive
income in either a single, continuous statement of comprehensive income or on separate but consecutive statements, the statement of operations and the statement of OCI. The amendment is effective for the Company at the beginning of fiscal year 2013
with early adoption permitted. The adoption of this guidance will not impact the Companys financial position, results of operations or cash flows and will only impact the presentation of OCI on the financial statements.

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, 2011, 2010, and 2009. Although the impact of inflation has been insignificant in recent
years, it is still a factor in the U.S. economy and may increase the cost to acquire or replace property, plant and equipment. It may also increase the cost of labor or supplies. To the extent permitted by competition, regulation and our existing
agreements, we have and will continue to pass along increased costs to our customers in the form of higher prices.



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Results of Operations

The following table sets forth summary information regarding oil, natural gas, and 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 section of this report for explanations of the terms used below.



|                                        |  |              |         |  |      |   |        |      |  |   |       | 
|--------------------------------------- |  | ------------ | ------- |  | ---- | - | ------ | ---- |  | - | ----- | 
|                                        |  | Years Ended  |        
|                                        |  | December 31, |        
|                                        |  | 2011         |         |  | 2010 |   |        | 2009 | 
|Oil and gas revenue and production      |  |              |         |  |      |   |        |      |  |   |       | 
|Revenues (in thousands)                 |  |              |         |  |      |   |        |      |  |   |       | 
|OilUnited States                       |  | $            | 60,193  |  |      | $ | 22,892 |      |  | $ | 6,138 | 
|OilCanada                              |  |              | 9,864   |  |      |   |       |      |  |   |      | 
|GasUnited States                       |  |              | 30,605  |  |      |   | 4823   |      |  |   | 469   | 
|GasCanada                              |  |              | 834     |  |      |   |       |      |  |   |      | 
|NGLsUnited States                      |  |              | 4,737   |  |      |   |       |      |  |   |      | 
|NGLsCanada                             |  |              | 33      |  |      |   |       |      |  |   |      | 
|                                        |  |              |         |  |      |   |        |      |  |   |       | 
|Total oil and gas sales                 |  | $            | 106,266 |  |      | $ | 27,715 |      |  | $ | 6,607 | 
|Production                              |  |              |         |  |      |   |        |      |  |   |       | 
|Oil (mbbls)US                          |  |              | 671     |  |      |   | 316    |      |  |   | 115   | 
|Oil (mbbls)Canada                      |  |              | 105     |  |      |   |       |      |  |   |      | 
|Gas (mmcfs)US                          |  |              | 6,654   |  |      |   | 952    |      |  |   | 191   | 
|Gas (mmcfs)Canada                      |  |              | 201     |  |      |   |       |      |  |   |      | 
|NGLs (gal)US                           |  |              | 3,875   |  |      |   |       |      |  |   |      | 
|NGLs (gal)Canada                       |  |              | 30      |  |      |   |       |      |  |   |      | 
|Total (mboe)                            |  |              | 2,011   |  |      |   | 475    |      |  |   | 146   | 
|Total (boe/d)                           |  |              | 5,510   |  |      |   | 1,301  |      |  |   | 401   | 
|Average prices                          |  |              |         |  |      |   |        |      |  |   |       | 
|Oil (per bbl)US                        |  | $            | 89.76   |  |      | $ | 72.41  |      |  | $ | 53.56 | 
|Oil (per bbl)Canada                    |  |              | 93.92   |  |      |   |       |      |  |   |      | 
|Gas (per mcf)US                        |  |              | 4.60    |  |      |   | 5.07   |      |  |   | 2.46  | 
|Gas (per mcf)Canada                    |  |              | 4.15    |  |      |   |       |      |  |   |      | 
|NGL (per boe)US                        |  |              | 51.35   |  |      |   |       |      |  |   |      | 
|NGL (per boe)Canada                    |  |              | 46.08   |  |      |   |       |      |  |   |      | 
|Total average price (per boe)           |  | $            | 52.84   |  |      | $ | 58.37  |      |  | $ | 45.11 | 
|Costs and expenses (per boe)            |  |              |         |  |      |   |        |      |  |   |       | 
|Lease operating                         |  | $            | 13.46   |  |      | $ | 21.90  |      |  | $ | 26.48 | 
|Severance tax and marketing             |  |              | 3.72    |  |      |   | 4.85   |      |  |   | 3.41  | 
|Exploration                             |  |              | 0.76    |  |      |   | 1.97   |      |  |   | 5.40  | 
|Impairment of properties                |  |              | 11.39   |  |      |   | 0.64   |      |  |   | 4.33  | 
|General and administrative1             |  |              | 31.60   |  |      |   | 52.44  |      |  |   | 57.98 | 
|Depletion, depreciation and accretion   |  |              | 24.41   |  |      |   | 18.79  |      |  |   | 21.63 | 
|Midstream and oilfield service segments |  |              |         |  |      |   |        |      |  |   |       | 
|(in thousands)                          |  |              |         |  |      |   |        |      |  |   |       | 
|Oilfield services segment revenue       |  | $            | 22,472  |  |      | $ | 5,027  |      |  | $ |      | 
|Midstream operations segment revenue    |  | $            | 2,491   |  |      | $ | 414    |      |  | $ |      | 
|Oilfield services segment expense       |  | $            | 19,428  |  |      | $ | 5,001  |      |  | $ |      | 
|Midstream operations segment expense    |  | $            | 3,012   |  |      | $ | 330    |      |  |   |       | 



|(1) | General and administrative expense includes:
|--- | --------------------------------------------

| | (i) | acquisition related expenses of $8.9 million ($4.42 per boe) in 2011, $2.2 million ($4.69 per boe) in 2010, and $1.0 million ($7.08 per boe) in 2009; and
| | --- | ---------------------------------------------------------------------------------------------------------------------------------------------------------



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| | (ii) | non-cash stock compensation of $25.1 million ($12.46 per boe) in 2011 and $6.3 million ($13.32 per boe) in 2010, and $3.1 million ($21.11 per boe) in 2009.
| | ---- | -----------------------------------------------------------------------------------------------------------------------------------------------------------

Years ended December 31, 2011 and 2010

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

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

Canadian Upstream segmentWilliston Basin/Bakken/Three Forks
Sanish/Madison. 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 284%, or $78.6 million, for the year ended December 31, 2011 to $106.3 million from $27.7 million for the year ended December 31, 2010. The increase in oil and gas sales principally resulted from increases in our
oil and natural gas production as a result of acquisitions and new drilling completed throughout the year in the unconventional resource plays. The average price we received for our production decreased from $58.37 per boe to $52.84 per boe, or
9.5%. Of the $78.6 million increase in revenues, approximately $10.6 million was attributable to an increase in oil prices partially offset by a decrease in gas prices, and $68.0 million was attributable to the increase in production
volumes of 1,536 mboe in 2011. The prices we receive for our products are generally tied to commodity index prices. We periodically enter into commodity derivative contracts in an attempt to offset some of the variability in prices (see the
discussion of commodity derivative activities below).

Oilfield services revenue. Oilfield services revenue increased by 350%, or $17.5
million, for the year ended December 31, 2011 to $22.5 million from $5.0 million for the year ended December 31, 2010. Oilfield services revenues for the year ended December 31, 2011 comprised $13.0 million in water disposal service
revenue, $9.3 million of drilling services, and $170,000 in operator fees compared to $1.6 million of water disposal revenue and $3.4 million of drilling revenue for the year ended December 31, 2010. The increase in water disposal revenue
primarily resulted from a contract with a large, integrated producer, and the increase in drilling revenue resulted in an increase in activity of service contracts with third party producers.

Midstream operationsEureka Hunter Pipeline Revenue.Revenue from the Eureka Hunter Pipeline segment increased by $2.1 million, or 525%, for the year ended December 31, 2011 to $2.5
million from $414,000 for the year ended December 31, 2010. The increase in revenues resulted from the increased volume of natural gas products transported by the pipeline network and gathering system, as Eureka Hunter gathered approximately
7.2 million mmbtu in 2011 compared to approximately 20,021 mmbtu in 2010.



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Other income. Other revenues decreased by $56,000 for the year ended December 31, 2011.

Lease operating expense. Our lease operating expenses, or LOE, increased $16.7 million, or 177%, for the year ended
December 31, 2011 to $27.1 million ($13.47 per boe) from $10.4 million ($21.90 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 $33.6 million, reduced by lower cost per boe produced, which offset the volume effect by $16.9 million. The decrease in overall LOE per boe cost is due to the impact of the lower per boe cost of the new production brought online during
2011 through our of the ongoing drilling program in our unconventional resource plays.

Severance taxes and marketing. Our
severance taxes and marketing increased by $5.2 million, or 224%, for the year ended December 31, 2010 to $7.5 million from $2.3 million for the year ended December 31, 2010. The increase in production taxes and marketing was due to the
increase in oil and gas sales as explained above.

Exploration. We recorded $1.5 million of exploration expense for the year ended
December 31, 2011, compared to $936,000 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 oil and gas properties.We review for impairment our long-lived assets to be held and used, including proved and
unproved 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 $22.9
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 totaling $21.8 million 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 the 2010 year. We also incurred impairment charges associated with our undeveloped acreage of $306,000 and $802,000 in our Eagle
Ford Shale and Appalachian Basin regions, respectively, due to expiring acreage that we chose not to develop. The 2010 impairment was primarily due to a write-down of our investment in the Giddings Field.

Depletion, depreciation and accretion. Our depletion, depreciation and accretion expense, or DD&A, increased $40.2 million, or 428%, to
$49.1 million for the year ended December 31, 2011 from $8.9 million for the year ended December 31, 2010 due to increased production in 2011. Our DD&A per boe increased by $5.62, or 29.9%, to $24.41 per boe for the year ended
December 31, 2011, compared to $18.79 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 new Eagle Ford Shale, Marcellus Shale and
Bakken Shale wells, which are horizontally drilled wells and require more expensive completion techniques than traditional, vertically-drilled wells.

General and administrative. Our general and administrative expenses, or G&A, increased $38.7 million, or 155%, to $63.6 million ($31.60 per boe) for the year ended
December 31, 2011 from $24.9 million ($52.44 per boe) for the year ended December 31, 2010. G&A expenses increased overall during 2011 due to expansion activities of the Company. Non-cash stock compensation totaled approximately
$25.1 million ($12.46 per boe) for the year ended December 31, 2011 and $6.3 million ($13.32 per boe) for the year ended December 31, 2010. Also included in in G&A for 2011 are acquisition-related costs of $8.9 million ($4.42 per boe)
for the 2011 period, which were for legal, consulting, and other charges principally related to the acquisitions of NGAS and NuLoch. In 2010, we had $2.2 million ($4.69 per boe) of acquisition-related expenses related to the acquisition of Triad.
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 $8.5 million, or 243%, to $12.0 million for the year
ended December 31, 2011 from $3.5 million for the year ended December 31, 2010. Approximately $2.7 million of this increase is the result of a non-cash write off of the unamortized balance of deferred financing fees from the credit
facility that was replaced by the MHR Senior Revolving Credit Facility in April 2011. Approximately $1.0 million of the increase is the result of amortization of financing costs related to



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the MHR Senior Revolving Credit Facility, the Eureka Hunter Term Loan and the MHR Term Loan Facility. The remaining $4.8 million increase is the result of our higher average debt level during
2011 and the increased interest due to the MHR Term Loan Facility entered into during September of 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 changes in 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 this interest whenever we make distributions to ourselves from the
subsidiary company.

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

Loss from continuing operations. We had a loss from continuing operations of $76.7 million
in 2011 versus a loss of $22.3 million in 2010, an increase of $54.4 million in loss, or 244%. This was due to an increase in operating loss of $40.0 million, principally due to an increase in G&A expense and DD&A expense.

Income from discontinued operations. 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 $6.6 million and reclassification of $1.9 million of operating income less interest expense associated
with the property to discontinued operations.

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



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NGAS. Our net loss per share from continuing operations was $0.80 per share for the year ended December 31, 2011, compared to a loss from continuing operations of $0.38 per share for the
year ended December 31, 2010.

Years ended December 31, 2010 and 2009

Oil and gas production.Production increased by 329 mboe to 475 mboe for the year ended December 31, 2010 from 146 mboe for the year ended
December 31, 2009, or 225%. Production for 2010 on a boe basis was 67% oil and 33% natural gas compared to 78% oil and 22% natural gas for 2009. The change in the percent of oil and gas produced was due to the acquisition of Triad
Energys assets. Our average daily production on a boe basis was 1,301 boe per day during 2010 compared to 401 boe per day for the 2009 year representing an overall increase of 900 boe per day. The increase in production in 2010 compared to
2009 is primarily attributable to the acquisition of the Triad Energy assets in the Appalachian region which closed in February 2010 and continuing exploration and development efforts in other fields. Triad Hunter accounted for 285 mboe of the
increase in production in 2010. The production results are further explained by geographic region in the following discussion.

Oil and gas
sales. Oil and gas sales increased $21.1 million, or 319%, for the year ended December 31, 2010 to $27.7 million from $6.6 million for the year ended December 31, 2009. The increase in oil and gas sales principally
resulted from increases in our oil and natural gas production as a result of acquisition activity and exploratory drilling done throughout the year. The average price we received for our production increased from $45.11 per boe to $58.37 per boe, a
29% increase. Of the $21.1 million increase in revenues, approximately $8.4 million was attributable to an increase in oil and gas prices and $12.7 million was attributable to the 329 mboe increase in production volumes from in 2010. 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.

Field operations revenue and expense. Field operations revenue was $4.7 million and field operations expense was
$4.4 million for the 2010 year. The increases in both revenue and expense in 2010 were due to the acquisition of the Triad Energy assets and include revenue and expenses from services provided to third parties for drilling, well servicing, natural
gas transportation, salt water disposal and operating services.

Other income. Other income for the year ended December 31,
2010 was $0.3 million, all resulting from Triad Hunters sale of used pipe. Other income for the year ended December 31, 2009 included $0.2 million in a liquidated damage penalty assessed against an operating partner.

Lease operating expense. Our LOE increased $6.5 million, or 168%, for the year ended December 31, 2010 to $10.4 million ($21.90 per
boe) from $3.9 million ($26.48 per boe) for the year ended December 31, 2009. The increase in total LOE is attributable to increased volume produced, which accounted for an increase in cost of $8.7 million, reduced by lower cost per boe
produced, which offset the volume effect by $2.2 million. The decrease in the per boe cost is due to the impact of the lower cost per boe produced of the Triad Energy assets acquired in 2010 compared to our Williston Basin secondary recovery
operating costs.

Severance taxes and marketing. Our severance taxes and marketing increased by $1.8 million, or 361%, for the
year ended December 31, 2010 to $2.3 million from $499,000 for the year ended December 31, 2009. The increase in production taxes and marketing was due to the increase in oil and gas sales as explained above.

Exploration. We recorded $936,000 of exploration expense for the year ended December 31, 2010, compared to $791,000 for the year ended
December 31, 2009. We experienced higher geological and geophysical costs in 2010 as a result of the acquisition of Triad Energys assets. The 2009 period included exploratory dry hole expense of $538,000 versus none in 2010.

Impairment of oil and gas properties. We review for impairment our long-lived assets to be held and used, including proved and unproved oil
and gas properties accounted for under the successful efforts method of



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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 $306,000 and $634,000 in 2010 and 2009,
respectively. The 2010 impairment was primarily due to a write-down of our investment in the Giddings Field based on reserve report economics. The 2009 impairment resulted from a writedown of $634,000 of unproved acreage costs in the Boomerang and
LeBlanc Prospect areas, which we do not expect to drill.

Depletion, depreciation and accretion. Our DD&A increased $5.8
million, or 182%, to $8.9 million for the year ended December 31, 2010 from $3.2 million for the year ended December 31, 2009 due to increased production in 2010. Our DD&A per boe decreased by $2.84, or 13.1%, to $18.79 per boe
for the year ended December 31, 2010, compared to $21.63 per boe for the year ended December 31, 2009. The decrease in DD&A per boe was primarily attributable to the increase in proved developed producing reserves and total proved
reserves at a lower average investment cost per unit at December 31, 2010 compared to December 31, 2009.

General and
administrative. Our G&A increased $16.4 million, or 193%, to $24.9 million ($52.44 per boe) for the year ended December 31, 2010 from $8.5 million ($57.98 per boe) for the year ended December 31, 2009. Our
G&A increased in 2010 primarily as a result of the Triad Energy assets acquisition and a higher level of corporate activity. Our G&A for 2010 included higher share-based compensation, as well as higher salaries and related employee benefit
costs attributable to an increase in employees from the prior year period, higher rent and office costs, and consulting and professional services, all due to the increased level of activity which began in the first quarter of 2010 and is continuing.
Non-cash G&A expenses totaled $6.3 million and $3.1 million for the 2010 and 2009 periods, respectively, and represent noncash stock compensation granted to our employees. Our G&A expenses also increased in 2010 due to acquisition related
expenses, specifically the Triad Energy asset acquisition, which closed on February 12, 2010, as well as other acquisitions and divestitures completed during the year and amounted to $1.3 million in 2010. These costs were expensed due to the
requirements of ASC 805 which states that acquisition costs must be expensed rather than capitalized as part of the cost of the asset being acquired for years beginning in 2009. Acquisition related expenses were $2.2 million in 2010 versus $1.0
million in 2009. Direct G&A attributable to Triad Hunter was $2.0 million of the increase in 2010.

Interest expense, net. Our
interest expense, net of interest income, increased $843,000, or 34%, to $3.5 million for the year ended December 31, 2010 from $2.7 million for the year ended December 31, 2009. This increase was substantially the result of our
higher average debt level during 2010 and the amortization of deferred finance costs related to the closing of our new senior credit facility.

Commodity derivative activities. Realized gains and losses from our commodity derivative activity increased our earnings by $3.9 million and
$5.4 million for the years ended December 31, 2010 and 2009, 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 $3.1 million for 2010 and $7.7 million for 2009. 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 changes in 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 gain of $814,000 and a loss of $2.3 million for the years ended December 31, 2010 and 2009, respectively.

Net loss attributable to non-controlling interest. Net income attributable to non-controlling interest was $129,000 in 2010 versus net loss
of $63,000 in 2009. 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 this interest whenever we make distributions to ourselves from the subsidiary company.



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Loss from Continuing Operations. We had a loss from continuing operations of $22.3 million in 2010
versus a loss of $15.6 million in 2009, an increase of $6.7 million in loss, or 43%. This was due to an increase in operating loss of $8.8 million, principally due to higher G&A expense and higher interest expense offset by a decline in loss
derivatives of $3.1 million.

Income from discontinued operations. 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 $6.6 million and reclassification of $1.9 million of operating
income less interest expense associated with the property to discontinued operations. We also reclassified $445,000 of Cinco Terry operating income less interest expense to discontinued operations for 2009.

Dividends on Preferred Stock. Dividends on our Series B and Series C Preferred Stock were $2.5 million in 2010 versus $26,000 in 2009. The
Series C Preferred Stock had a stated value of $70.2 million and $5.4 million at December 31, 2010 and 2009, respectively, and carries a cumulative dividend rate of 10.25% per annum. We commenced the issuance of Series C Preferred Stock in
December 2009. We redeemed all outstanding Series B Preferred Stock in June 2010.

Net loss attributable to common shareholders. Net
loss attributable to common shareholders was $16.3 million in 2010 versus $15.1 million in 2009. Our net loss per common share, basic and diluted was $0.25 per share in 2010 compared to $0.39 per share in 2009. Our weighted average shares
outstanding increased by 24,967,691 (64.1%) from 2009 to 2010, and was partially responsible in the decline of our net loss per share between the periods. Our net loss per share from continuing operations was $0.38 in 2010 versus $0.40 in 2009.
The $6.7 million increase in loss from continuing operations was offset by the increase in weighted average shares outstanding. We had income per share from discontinued operations of $0.13 in 2010 versus $0.01 in 2009, primarily due to the gain on
sale of Cinco Terry.

Liquidity and Capital Resources

We generally rely on cash generated from operations, borrowings under our 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 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 revolving credit facility will be available or acceptable on our terms, 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.

At December 31, 2011, the Company was not in compliance with a covenant under its credit facilities requiring a ratio of consolidated current assets
to consolidated current liabilities of not less than 1.0 to 1.0. The bank group provided the Company with a waiver of that December 31, 2011 covenant violation but the Company is required to meet the quarterly measurements for the covenant
throughout 2012, which management believes is probable.

We intend to fund 2012 capital expenditures, excluding any acquisitions,
primarily out of internally-generated cash flows and, as necessary, borrowings under our credit facilities. We may also raise additional funds in the



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public debt and equity markets. As of December 31, 2011, we had $58.0 million available to borrow under our revolving credit facility.

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 sale of common and preferred stock and the proceeds from exercises of warrants, along with our $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 was used to fund our acquisitions and drilling program, repay debt under our revolving credit facility, and pay deferred financing costs on our amended and restated 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 sale of common and preferred stock and the proceeds from exercises of warrants, along with our $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
on our amended and restated credit facility.

For the year ended December 31, 2009, our primary sources of cash were from financing and
operating activities and cash on hand at the beginning of the year. Approximately $19.1 million of cash from sale of common and preferred stock, $3.4 million of cash from operating activities and $6.1 million of cash on hand was used to fund
our acquisitions and drilling program, repay debt under our revolving credit facility, and purchase new derivative contracts.

In comparing
2011 and 2010, our cash flows from provided by operations increased in 2011 to $33.8 million from a use of $1.2 million in 2010 primarily due to the increase in revenue.

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



|                                                      |  |                          |          |   |      |   |          |      |  |   |         |  
|----------------------------------------------------- |  | ------------------------ | -------- | - | ---- | - | -------- | ---- |  | - | ------- | -
|                                                      |  | Years Ended December 31, |         
|                                                      |  | 2011                     |          |   | 2010 |   |          | 2009 | 
|                                                      |  | (In thousands)           |         
|Cash flows provided by (used in) operating activities |  | $                        | 33,838   |   |      | $ | (1,167   | )    |  | $ | 3,373   |  
|Cash flows used in investing activities               |  |                          | (361,715 | ) |      |   | (118,281 | )    |  |   | (16,624 | )
|Cash flows provided by financing activities           |  |                          | 342,193  |   |      |   | 117,720  |      |  |   | 9,413   |  
|                                                      |  |                          |          |   |      |   |          |      |  |   |         |  
|Effect of foreign currency translation                |  |                          | (19      | ) |      |   |         |      |  |   |        |  
|Net increase (decrease) in cash and cash equivalents  |  | $                        | 14,297   |   |      | $ | (1,727   | )    |  | $ | (3,839  | )
|                                                      |  |                          |          |   |      |   |          |      |  |   |         |  

We define liquidity as funds available under our revolving credit facility plus year-end cash and cash equivalents. At
December 31, 2011, we had $142.0 million in long-term debt outstanding under our revolving credit facility, compared to $30.0 million in long-term debt outstanding under the revolving credit facility at December 31, 2010. The
following table summarizes our liquidity position at December 31, 2011 compared to December 31, 2010:



|                                                      |  |                 |          |   |              |   |         |              |  |   |         |  
|----------------------------------------------------- |  | --------------- | -------- | - | ------------ | - | ------- | ------------ |  | - | ------- | -
|                                                      |  | At December 31, |         
|                                                      |  | 2011            |          |   | 2010         |  
|                                                      |  | (In thousands)  |         
|                                                      |  | MagnumHunter    |          |   | EurekaHunter |   |         | MagnumHunter | 
|Borrowing base under senior revolving credit facility |  | $               | 200,000  |   |              | $ | 75,000  |              |  | $ | 71,500  |  
|Cash and cash equivalents                             |  |                 | 13,131   |   |              |   | 1,720   |              |  |   | 554     |  
|Borrowing under the senior revolving credit facility  |  |                 | (142,000 | ) |              |   |        |              |  |   | (33,200 | )
|Borrowing under Eureka Hunter credit facility         |  |                 |         |   |              |   | (31,000 | )            |  |   |        |  
|                                                      |  |                 |          |   |              |   |         |              |  |   |         |  
|Liquidity                                             |  | $               | 71,131   |   |              | $ | 45,720  |              |  | $ | 38,854  |  
|                                                      |  |                 |          |   |              |   |         |              |  |   |         |  



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There are several factors that will affect our liquidity in 2012. We expect to have increased operating cash
flows as a result of the NGAS and NuLoch acquisitions and the successful results of our 2011 drilling program. We also expect to have increased salary and other administrative costs associated with the increased number of employees resulting from
our acquisitions. On February 14, 2012, the Companys borrowing base under the MHR Senior Revolving Credit Facility was increased to $235 million from $200 million.

Operating Activities

For the year ended December 31, 2011, our cash flow
provided by operating activities was $33.8 million compared to cash used in operating activities of $1.2 million in 2010, an increase in cash provided of $35.0 million. The increase in total revenues of $96.5 million was partially offset by an
increase in G&A of $38.7 million, an increase in LOE of $16.7 million and an increase in field operating expense of $12.6 million. Our cash flow used by operating activities for the year ended 2010 included net income of $8.5 million from
discontinued operations which includes the gain on sale of discontinued operations of $6.7 million and will not have a material impact on future cash flows from operating activities.

Investing Activities

We had $292.4 million in capital expenditures in 2011 versus
$80.1 million in 2010 and $14.6 million in 2009. The Company used $60.4 million in cash in the NGAS acquisition, net of cash acquired of $1.9 million and $18.1 million in cash in the NuLoch acquisition, net of cash acquired of $640,000. During 2011,
the Company used $42,000 for deposits on equipment, and we received proceeds from the sale of assets of $8.7 million. Our 2011 capital expenditures included $20 million in cash for the acquisition of the Wetzel County assets from Windsor Marcellus,
LLC, $4.9 million in cash in the third phase of the acquisition of assets from PostRock, and $267.5 million for capital expenditures under our 2011 capital expenditures budget.

Other uses of funds for investing activities in 2010 were $59.5 million to acquire the Triad Energy assets. Other sources of funds from investing activities in 2010 were net proceeds from the sale of our
interests in the Cinco Terry property for $21.2 million net of adjustments and the use of $1.8 million in previous drilling advances to other operators.

Financing Activities

We borrowed $493.9 million under our credit facilities and
other debt agreements in 2011 compared to $101.6 million in 2010 and $25.7 million in 2009. We repaid $242.5 million, $84.9 million, and $34.2 million of amounts outstanding under our revolving credit facility for the years ended
December 31, 2011, 2010, and 2009, respectively. In 2011, we realized $7.6 million from the exercise of common stock options and warrants. We issued 1,190,544 shares of our Series C Perpetual Preferred Stock in the 2011 period for net proceeds
of $29.1 million, and we issued 1,437,558 shares of our Series D Preferred Stock in the 2011 period for net proceeds of $65.7 million. We also paid dividends of $14.0 million and used cash of $11.6 million for payment of deferred financing costs
during the 2011 period.

In 2010 we received $38.7 million in net proceeds from the sale of approximately 10.8 million shares of our
common stock, $63.4 million in net proceeds from the issuance of approximately 2.6 million shares of our Series C Preferred Stock and $16.1 million from the exercise of warrants. In 2010, we also paid dividends of $2.5 million, $11.3 million in
cash upon redemption of Series B Preferred Stock, and $604,000 for shares loaned to the Companys stock ownership plan. In 2009, we also received $14.1 million in net proceeds from the sale of approximately 8.9 million shares of our common
stock (some of which were issued along with approximately 1.7 million common stock warrants) and $5.0 million in net proceeds from the issuance of approximately 215,000 shares of our Series C Preferred Stock.

We believe that cash flows from operations and borrowings under our revolving credit facility and other debt agreements will finance substantially all of
our capital needs through 2012. We may also use our revolving credit



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facility for possible acquisitions and temporary working capital needs. Further, we may decide to access the public or private equity or debt markets for potential acquisitions, working capital
or other liquidity needs, if such financing is available on acceptable terms. In November 2010, we filed a shelf registration statement with the SEC registering up to $250 million of common stock, preferred stock, warrants and debt securities.
The registration statement was declared effective by the SEC on October 15, 2009. In June 2011, we filed another shelf registration statement with the SEC registering up to $400 million of common stock, preferred stock warrants and debt
securities, which replaced the prior shelf registration statement. This registration statement was declared effective by the SEC on January 18, 2012.

2012 Preliminary Capital Expenditures Budget

The following table summarizes our
preliminary estimated capital expenditures for 2012. We intend to fund 2012 capital expenditures, excluding any acquisitions, primarily out of internally-generated cash flows and, as necessary, borrowings under our credit facilities and public
issuance of equity securities.



|                           |  |                             |         | 
|-------------------------- |  | --------------------------- | ------- | 
|                           |  | Year EndingDecember 31,2012 |        
|                           |  | (In thousands)              |        
|Upstream Operations        |  |                             |         | 
|Williston Basin drilling   |  | $                           | 50,000  | 
|Appalachian Basin drilling |  |                             | 50,000  | 
|Eagle Ford Shale drilling  |  |                             | 50,000  | 
|Midstream Operations       |  |                             |         | 
|Eureka Hunter Pipeline     |  |                             | 50,000  | 
|                           |  |                             |         | 
|Total capital expenditures |  | $                           | 200,000 | 
|                           |  |                             |         | 

Our capital expenditures budget for 2012 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.On April 13, 2011, the Company entered into a Second Amended and Restated
Credit Agreement, referred to as the MHR Senior Revolving Credit Facility. The MHR Senior Revolving Credit Facility amended and restated, in its entirety, that certain Amended and Restated Credit Agreement dated February 12, 2010.

The MHR Senior Revolving Credit Facility provides for an asset-based, senior secured revolving credit facility maturing April 13, 2016. The initial
borrowing base was set at $120 million upon the completion of the Companys acquisition of NGAS. The borrowing base was subsequently increased to $145 million upon the completion of the Companys acquisition of NuLoch. 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 $250 million. The borrowing base is subject to such periodic redeterminations commencing November 1, 2011. The borrowing base is currently set at $235 million. At December 31, 2011, the Company
was not in compliance with covenant under the Facility requiring a ratio of consolidated current assets to consolidated current liabilities of not less than 1.0 to 1.0. The lenders provided the Company with a waiver of that December 31, 2011
covenant violation but the Company is required to meet the quarterly measurements for the covenant throughout 2012, which management believes is probable.



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The facility may be used for loans and, subject to a $10,000,000 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
LIBO Rate for a one month interest period on such day plus 1.0%; or (ii) the adjusted LIBO Rate, 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 3.25% for adjusted LIBO Rate loans.

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

The MHR Senior Revolving Credit Facility contains negative covenants that,
among other things, restrict the ability of the Company to, with certain exceptions: (1) incur indebtedness; (2) grant liens; (3) make certain restricted payments; (4) change the nature of its business; (5) dispose of its
assets; (6) enter into mergers, consolidations or similar transactions; (7) make investments, loans or advances; (8) pay cash dividends, unless certain conditions are met, and subject to a basket of $20,000,000 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 (1) a ratio of consolidated
current assets to consolidated current liabilities of not less than 1.0 to 1.0 or of not less than 1.05 to 1.00 commencing with the fiscal quarter ending June 30, 2012 if the amounts owed under the MHR Term Loan Facility have not been repaid in
full as of such date; (2) a ratio of EBITDAX to interest of not less than 2.5 to 1.0; and (3) a ratio of total debt to EBITDAX of not more than (a) 4.25 to 1.0 for the fiscal quarter ending December 31, 2011 and (b) 4.0 to
1.0 for each fiscal quarter ending thereafter. The Company is also required to enter into certain commodity hedging agreements pursuant to the terms of the facility. As stated above, at December 31, 2011, the Company was not in compliance with
the covenant requiring a ratio of consolidated current assets to consolidated current liabilities of not less than 1.0 to 1.0.

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, which liens include those properties acquired through the acquisitions of
NGAS and NuLoch.

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.

MHR Term Loan Facility.On September 28, 2011, the Company entered into a Second Lien Term Loan Credit Agreement, referred to as the
MHR Term Loan Facility.

The MHR Term Loan Facility provides for a term loan credit facility, referred to as the term loan facility maturing
on October 13, 2016, in an aggregate principal amount of $100 million, which was fully drawn on September 28, 2011. Amounts repaid under the term loan facility may not be redrawn in the future.



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Borrowings under the term loan facility will, at the Companys election, bear interest at either:
(i) an ABR equal to the higher of (A) the Prime Rate, (B) the Federal Funds Effective Rate plus 0.5% per annum and (C) the LIBO Rate for a one month interest period in effect on such day plus 1.0%; or (ii) the Adjusted
LIBO Rate, which is the rate stated on Reuters BBA Libor Rates LIBOR01, provided that such amount shall not be less than 1.0% per annum through June 30, 2012 and not less than 2.0% per annum for any period after June 30, 2012;
plus in each of the cases described in clauses (i) and (ii) above, an applicable margin of 6.0% for ABR loans and 7.0% for Adjusted LIBO Rate loans for periods through June 30, 2012 and 7.0% for ABR loans and 8.0% for Adjusted LIBO
Rate loans for periods after June 30, 2012.

Overdue amounts shall bear interest at a rate equal to 2.0% per annum plus the rate
applicable to ABR loans.

The Company may elect to prepay amounts due under the term loan facility without penalty during the first 12 months.
The Company will be subject to a 2.0% penalty of the principal amount being prepaid during the second year of the term loan facility and a 1.0% penalty of the principal amount being prepaid during the third year of the term loan facility. Any
optional prepayments made after the third year of the term loan facility will not be subject to an additional prepayment premium or penalty.

The Company is subject to mandatory prepayments under the term loan facility for certain percentages of the net cash proceeds received as a result of:
(i) future issuances of certain debt securities, including those convertible into the Companys common stock or other equity interests; (ii) sales or other dispositions of the Companys property and assets subject to customary
reinvestment provisions and certain other exceptions; and (iii) future issuances of the Companys equity interests including its common stock, preferred stock and other convertible securities subject to certain exceptions.

The term loan 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 $20,000,000 per year available for payment of dividends on preferred stock; and (9) enter into
transactions with affiliates.

The term loan facility also requires the Company to satisfy certain financial covenants, including maintaining
(1) a ratio of current assets to current liabilities of not less than (a) 0.85 to 1.0 for each fiscal quarter ending on or before March 31, 2012 and (b) 1.0 to 1.0 for each fiscal quarter ending thereafter; (2) a ratio of
its total reserve value (as such term is defined in the term loan facility) to total indebtedness under the MHR Senior Revolving Credit Facility and MHR Term Loan Facility of not less than 1.5 to 1.0; (3) a ratio of EBITDAX to interest expense
of not less than 2.125 to 1.0 commencing with the fiscal quarter ending September 30, 2011; and (4) a ratio of total debt to EBITDAX of not more than (a) 5.25 to 1.0 for the fiscal quarter ending September 30, 2011; (b) 5.00
to 1.0 for the fiscal quarter ended December 31, 2011; and (c) 4.75 to 1.0 for each fiscal quarter ending thereafter. The Company was out of compliance with the ratio of current assets to current liabilities covenant at December 31,
2011 as described above.

The obligations of the Company under the term loan 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.

The Companys obligations under the term loan facility have been secured by the grant of a second priority lien on substantially all of the assets of the Company and its restricted subsidiaries,
including the oil and gas properties of the Company and its restricted subsidiaries.



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In connection with the term loan 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 term loan facility are unconditionally guaranteed
by such restricted subsidiaries.

Eureka Hunter Credit Facilities.On August 16, 2011, Eureka Hunter, a wholly owned
subsidiary of the Company, entered into (i) a First Lien Credit Agreement, referred to as the Eureka Hunter Revolver on the revolver, by and among Eureka Hunter, 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 Hunter Term Loan on the term loan, by and among Eureka Hunter, 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 Hunter Revolver and the Eureka Hunter Term Loan are collectively referred to as the Eureka Hunter Credit Facilities).

The Eureka Hunter 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 Hunter. The Eureka Hunter Term Loan provides for a $50 million term loan, secured by a second lien on substantially all of the assets of Eureka Hunter. 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. On August 16, 2011, Eureka Hunter drew $31 million under the term loan, $21
million of which was distributed to the Company to repay existing corporate indebtedness. Both the revolver and the term loan are non-recourse to Magnum Hunter.

The terms of the Eureka Hunter Revolver 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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 LIBO Rate (as defined in the Eureka Hunter 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 LIBO Rate, plus an applicable margin ranging from 2.25% to 3.25%.
| | - |  | ------------------------------------------------------------------------------

Borrowings under the term loan will bear interest at 9.75% per annum in cash, plus 2.75% (increasing to 3.75% on and at all times when Eureka Hunter
and its subsidiaries incur indebtedness (other than the term loan) in excess of $1,000,000) of which may be paid, at the sole option of Eureka Hunter, in cash or in shares of restricted common stock of the Company.

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 Hunter Credit
Facilities contain negative covenants that, among other things, restrict the ability of Eureka Hunter 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.



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The Eureka Hunter Credit Facilities also require Eureka Hunter 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) not less than 1.0 to 1.0 for the fiscal quarter ending
March 31, 2012, to (ii) (A) for the term loan, not less than 2.75 to 1.0 for the fiscal quarter ending December 31, 2014 and thereafter, and (B) for the revolver, not less than 2.75 to 1.0 for the fiscal quarter ending
December 31, 2014 and thereafter or, in the event any portion of the revolver has been drawn, not less than 3.0 to 1.0 for the fiscal quarter ending December 31, 2014;
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | a consolidated total debt to consolidated EBITDA ratio ranging from (i) not greater than 7.0 to 1.0 for the fiscal quarter ending March 31,
2012, to (ii) (A) for the term loan, not greater than 4.25 to 1.0 for the fiscal quarter ending December 31, 2014 and thereafter, and (B) for the revolver, not greater than 4.25 to 1.0 for the fiscal quarter ending
December 31, 2014 and thereafter or, in the event any portion of the revolver has been drawn, not greater than 4.0 to 1.0 for the fiscal quarter ending June 30, 2014; 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 (A) 3.5 to 1.0 for the fiscal quarters ending March 31, 2012 and June 30, 2012, and (B) 3.25 to 1.0 for each fiscal quarter thereafter.
| | - |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

The obligations of Eureka Hunter under both the revolver and the term loan may be accelerated upon the occurrence of an
event of default (as such term is defined in each of the facilities) under either 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 Hunter, and defaults by the Company which cause the acceleration of the Companys debt under its existing senior secured revolving credit facility administered by the Bank of Montreal.

In connection with the Eureka Hunter Credit Facilities, (i) Eureka Hunter and its existing subsidiary entered into customary ancillary agreements
and arrangements, which provide that the obligations of Eureka Hunter under the Eureka Hunter Credit Facilities are secured by substantially all of the assets of Eureka Hunter and such subsidiary, consisting primarily of pipelines, pipeline
rights-of-way, and a gas processing plant, and (ii) Triad Hunter, the sole parent of Eureka Hunter and a wholly 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 Triad Hunters equity interest in Eureka Hunter.

As of December 31, 2011, there was
$31.0 million outstanding on the Eureka Hunter Term Loan.

Related Party Transactions

During 2011, 2010, and 2009, 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 $463,000, $450,000, and $161,000, for the year ended December 31, 2011, 2010, and 2009, respectively.

During 2011, 2010, and 2009, we obtained accounting services and use of office space from GreenHunter Energy, Inc., an entity for which Mr. Evans is the Chairman, CEO and a major shareholder; for
which Ronald Ormand, our Chief Financial Officer and a director, is also a director; and for which David Krueger, our Chief Accounting Officer, is the Chief Financial Officer. Professional services expenses totaled $162,000, $212,000, and $30,000
for the year ended December 31, 2011, 2010, and 2009, respectively. All accounting services are now managed entirely by Magnum Hunter employees, who provide accounting services to GreenHunter Energy, Inc. for approximately $8,300 per month.



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We entered into a one year 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 year ended December 31, 2011, the Company paid rent of $36,000 pertaining to the lease.

During the year ended December 31, 2011, Eagle Ford Hunter, Inc., Triad Hunter and Hunter Disposal, LLC, wholly owned subsidiaries of the Company, rented storage tanks for disposal water and
equipment from GreenHunter Energy, Inc. Rental costs totaled $1.3 million, $0, and $0 for the years ended December 31, 2011, 2010 and 2009, respectively. Terms for the storage rental are comparable to those that could be obtained from third
parties in the marketplace. As of December 31, 2011, our net accounts payable to GreenHunter Energy, Inc. was $70,000.

On
October 13, 2011, the Company purchased an office building for $1.7 million from GreenHunter Energy, 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, a portion of which note 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 described
above.

On February 17, 2012, the Company, through its wholly owned subsidiary, Triad Hunter, LLC, closed on the sale of 100% of the
equity ownership interest of Hunter Disposal, LLC. The sale was made to GreenHunter Water, LLC, a wholly-owned subsidiary of GreenHunter Energy, Inc. The terms and conditions of the purchase agreement between the parties were approved by an
independent special committee of the Companys board of directors. The total sales price for this acquisition was approximately $8.8 million, subject to adjustment for certain working capital, earnings and other similar adjustments. The
consideration received included a combination of cash, GreenHunter Energy restricted common stock, GreenHunter Energy 10% cumulative preferred stock, and a convertible promissory note payable to the Company. 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.

Contractual Commitments

Our contractual
commitments consist of long-term debt, accrued interest on long-term debt, operating lease obligations, drilling contracts, asset retirement obligations, and employment agreements with executive officers.

Our long-term debt comprises borrowings under our MHR Senior Revolving Credit Facility, MHR Term Loan Facility and Eureka Hunter Term Loan, and term
equipment debt assumed in the Triad Energy and NGAS acquisitions. Interest on revolving debt is based on the rate applicable under our revolving credit facility, which was 3.55% at December 31, 2011. The term equipment debt has an average
interest rate of approximately 4.66% at December 31, 2011. See Note 9 in our condensed consolidated financial statements.

As of
December 31, 2011, we rent various office spaces in Houston, Texas, that total approximately 22,966 square feet at a cost of $37,925 per month for the remaining terms ranging from two to fifty-two months. Triad Hunter had various lease
commitments for periods ranging from three to seventy-four months at December 31, 2011, and with monthly payments of approximately $29,518 as of that date. Our Williston Hunter subsidiaries have office spaces in Calgary, Alberta and Denver,
Colorado that have a combined monthly payment of $31,517.

On May 24, 2011, the Company entered into a total depth drilling contract. Our
remaining maximum liability under the drilling contract, which would apply if we terminated the contract before the end of its term, was $315,000 as of December 31, 2011.

On June 24, 2011, the Company entered into a forty month drilling contract from July 1, 2011, through October 31, 2014. Our remaining maximum liability under the drilling contract, which
would apply if we terminated the contract before the end of its term, was approximately $16.6 million as of December 31, 2011.



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On June 29, 2011, the Company entered into a twelve month drilling contract. Our remaining maximum
liability under the drilling contract, which would apply if we terminated the contract before the end of its term, was approximately $1.0 million as of December 31, 2011.

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

We have outstanding employment agreements with three of our senior officers for terms ranging from four to nine months. Our maximum commitment under the
employment agreements, which would apply if the employees covered by these agreements were all terminated without cause, was approximately $963,000 at December 31, 2011.

The following table summarizes these commitments as of December 31, 2011 (in thousands):



|                                           |  |       |         |  |      |   |        |             |  |   |             |  |  |            |         |  |  |   |        | 
|------------------------------------------ |  | ----- | ------- |  | ---- | - | ------ | ----------- |  | - | ----------- |  |  | ---------- | ------- |  |  | - | ------ | 
|Contractual Obligations                    |  | Total |         |  | 2012 |   |        | 2013 - 2014 |  |   | 2015 - 2016 |  |  | After 2016 |        
|Long-term debt(1)                          |  | $     | 290,745 |  |      | $ | 4,681  |             |  | $ | 4,953       |  |  | $          | 248,858 |  |  | $ | 32,253 | 
|Interest on long-term debt(2)              |  |       | 88,547  |  |      |   | 17,100 |             |  |   | 34,054      |  |  |            | 30,245  |  |  |   | 7,148  | 
|Operating lease obligations(3)             |  |       | 2,990   |  |      |   | 850    |             |  |   | 1,322       |  |  |            | 521     |  |  |   | 297    | 
|Asset retirement obligations(4)            |  |       | 20,612  |  |      |   | 1,897  |             |  |   | 742         |  |  |            | 1,340   |  |  |   | 16,633 | 
|Employment agreements with senior officers |  |       | 963     |  |      |   | 963    |             |  |   |            |  |  |            |        |  |  |   |       | 
|Drilling contract commitment               |  |       | 17,875  |  |      |   | 7,155  |             |  |   | 10,720      |  |  |            |        |  |  |   |       | 
|                                           |  |       |         |  |      |   |        |             |  |   |             |  |  |            |         |  |  |   |        | 
|Total                                      |  | $     | 421,732 |  |      | $ | 32,646 |             |  | $ | 51,791      |  |  | $          | 280,964 |  |  | $ | 56,331 | 
|                                           |  |       |         |  |      |   |        |             |  |   |             |  |  |            |         |  |  |   |        | 



|(1) | See Note 9 to our consolidated financial statements for a discussion of our long-term debt.
|--- | -------------------------------------------------------------------------------------------

|(2) | Interest payments have been calculated by applying the interest rate of 3.55% effective at December 31, 2011, on our revolving credit facility debt and 8% to the
outstanding term debt balance at December 31, 2011.
|--- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

|(3) | Operating lease obligations are for office space and equipment.
|--- | ---------------------------------------------------------------

|(4) | See Note 8 to our consolidated financial statements for a discussion of our asset retirement 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 December 31, 2011, 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 materially affect our liquidity or availability of, or requirements for, capital resources.



|Item 7A. | QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
|-------- | -----------------------------------------------------------

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



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Proved Reserves

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 geosciences 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, 2011 were estimated based on the unweighted, arithmetic average of the closing price on the first day of each month for the 12-month period prior to December 31, 2011 for natural gas, oil, and ngls, in accordance with new
reserve rules.

Changes in commodity prices and operation costs may also affect the overall evaluation of reservoirs. A hypothetical 10%
decline in our December 31, 2011 estimated proved reserves would have increased our depletion expense by approximately $5.5 million for the year ended December 31, 2011.

Commodity Price Risk

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

We 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 as they occur.

At December 31, 2011, we have the following commodity derivative positions outstanding:



|                       |  |                     |  |           |        |  |                 |                
|---------------------- |  | ------------------- |  | --------- | ------ |  | --------------- | ---------------
|Natural Gas            |  | Period              |  | MMBTU/day |        |  | Price per MMBTU
|Collars                |  | Jan 2012 - Dec 2012 |  |           | 11,910 |  |                 | $4.58 - $6.42  
|                       |  | Jan 2013 - Dec 2013 |  |           | 12,500 |  |                 | $4.50 - $5.96  
|Swaps                  |  | Jan 2012 - Dec 2012 |  |           | 6,100  |  |                 | $4.16          
|                       |  | Jan 2013 - Dec 2013 |  |           | 6,000  |  |                 | $4.13          
|Ceilings sold (call)   |  | Jan 2014 - Dec 2014 |  |           | 16,000 |  |                 | $5.91          
|                       |  |                     | 
|Crude Oil              |  | Period              |  | Bbls/day  |        |  | Price per Bbl  
|Collars                |  | Jan 2012 - Dec 2012 |  |           | 3,000  |  |                 | $81.69 - $98.92
|                       |  | Jan 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
|Floors sold (put)      |  | Jan 2012 - Dec 2012 |  |           | 50     |  |                 | $55.00         
|Floors purchased (put) |  | Jan 2012 - Dec 2012 |  |           | 153    |  |                 | $80.00         

At December 31, 2011 and 2010, the fair value of our open derivative contracts was a net liability of approximately
$5.0 million, and an asset of $778,000, respectively.

Currently, Bank of Montreal, KeyBank National Association, Credit Suisse Energy, LLC,
UBS AG London Branch, and Deutsche Bank AG London Branch are currently 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



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the term of the commodity derivatives positions. All counterparties are participants in our revolving credit facility, and the collateral for the outstanding borrowings under our revolving credit
facility is used as collateral for our commodity derivatives.

Unrealized gains and losses, at fair value, 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. Changes in the fair value of our commodity derivative contracts are recorded in earnings as they occur
and included in other income (expense) on our consolidated statements of operations. 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, call, and put contracts using industry-standard option pricing models and observable market inputs. We use our internal valuations to determine the fair values of the contracts that
are reflected on our consolidated balance sheets. Realized gains and losses are also included in other income (expense) on our consolidated statements of operations.

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 changes in such fair value in earnings on our consolidated statements of operations under the caption entitled Gain (loss) on derivative contracts.

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. We recorded (i) a realized loss from the
settlement of derivative contracts of $2.1 million for the year ended December 31, 2011, (ii) a realized gain from the settlement of derivative contracts of $3.9 million for the year ended December 31, 2010, and (iii) a realized
gain from the settlement of derivative contracts of $5.4 million for the year ended December 31, 2009. Realized gains and losses result from actual cash settlements received or paid under the derivative contracts. For the year ended
December 31, 2011, we recognized an unrealized loss of $4.2 million from the change in the fair value of commodity derivatives. For the year ended December 31, 2010, we recognized an unrealized loss of $3.1 million from the change in
the fair value of commodity derivatives. For the year ended December 31, 2009, we recognized an unrealized loss of $7.7 million from the change in the fair value of commodity derivatives. 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. A hypothetical 10% increase
in the NYMEX floating prices would have resulted in a $24.0 million decrease in the December 31, 2011 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 $22.4 million decrease in the December 31, 2011 fair value recorded on our balance sheet and would have partially offset the loss on commodity derivatives in our
statement of operations by the corresponding amount. See Note 2Summary of Significant Accounting Policies, Note 3Fair Value of Financial Instruments, and Note 4Financial Instruments and
Derivatives to our consolidated financial statements for additional information on our derivative instruments.

To estimate the fair
value of our commodity derivatives positions, we use market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique.
These inputs can be readily observable, market corroborated or generally unobservable. We primarily apply the market approach for recurring fair value measurements and attempt to use the best available information. We determine the fair value based
upon the hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and lowest priority to
unobservable inputs (Level 3 measurement). The three levels of fair value hierarchy are as follows:



| |  |  | Level 1Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. At December 31, 2011, we
had no Level 1 measurements.
| | - |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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| |  |  | Level 2Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as
of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices
for commodities, time value, volatility factors and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Our derivatives, which consist primarily of commodity swaps and collars, are
valued using commodity market data which is derived by combining raw inputs and quantitative models and processes to generate forward curves. Where observable inputs are available, directly or indirectly, for substantially the full term of the asset
or liability, the instrument is categorized in Level 2. At December 31, 2011, all of our commodity derivatives were valued using Level 2 measurements.
| | - |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Level 3Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with
internally developed methodologies that result in managements best estimate of fair value. At December 31, 2011, our Level 3 measurements were used to calculate our asset retirement obligation and our impairment analysis of proved
properties at December 31, 2011.
| | - |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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|Item 8. | Financial Statements And Supplementary Data
|------- | -------------------------------------------

INDEX TO FINANCIAL STATEMENTS



|                                                                                                                |  |  |      | 
|--------------------------------------------------------------------------------------------------------------- |  |  | ---- | 
|Report of Independent Registered Public Accounting Firm                                                         |  |  | F-2  | 
|Condensed Consolidated Balance Sheets at December 31, 2011 and 2010                                             |  |  | F-5  | 
|Condensed Consolidated Statements of Operations for the years ended December 
31, 2011, 2010, and 2009          |  |  | F-6  | 
|Consolidated Statements of Other Comprehensive Income for the years ended December 
31, 2011, 2010, and 2009    |  |  | F-7  | 
|Condensed Consolidated Statement of Shareholders Equity for the years ended December 
31, 2011, 2010, and 2009 |  |  | F-8  | 
|Condensed Consolidated Statement of Cash Flows for the years ended December 31, 2011, 2010, and
2009            |  |  | F-10 | 
|Notes to Financial Statements                                                                                   |  |  | F-11 | 



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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 2010, and the related consolidated statements of operations, comprehensive income, stockholders equity, and cash
flows for each of the three years in the period ended December 31, 2011. Our audits also included the financial statement schedule of the Company listed in Item 15(a). These financial statements and financial statement schedule are the
responsibility of the Companys management. Our responsibility is to express an opinion on these financial statements based on our audits.

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

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial
position of the Company as of December 31, 2011 and 2010, and the results of its operations and cash flows for each of the three years in the period ended December 31, 2011, in conformity with accounting principles generally accepted in
the United States of America. Also, in our opinion, the related financial statement schedule, when considered in relation to the consolidated financial statements taken as a whole, present fairly in all material respects the information set forth
therein.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the
Companys internal control over financial reporting as of December 31, 2011, based on criteria established in Internal ControlIntegrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission, and
our report dated February 29, 2012 expressed an unqualified opinion on the effectiveness of the Companys internal control over financial reporting.

/s/ Hein & Associates LLP

Dallas, Texas

February 29, 2012



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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders

Magnum Hunter Resources Corporation

We have
audited Magnum Hunter Resources Corporation and subsidiaries (collectively, the Company) internal control over financial reporting as of December 31, 2011, based on criteria established in Internal ControlIntegrated
Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company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.

As
described in Managements Report on Internal Control Over Financial Reporting, management has excluded Williston Hunter Canada, Inc., Williston Hunter, Inc., and Magnum Hunter Production, Inc. from its assessment of internal control over
financial reporting as of December 31, 2011, because they were acquired by the Company in a purchase business combinations during 2011. We have also excluded Williston Hunter Canada, Inc., Williston Hunter Inc., and Magnum Hunter Production,
Inc. from our audit of internal control over financial reporting. Williston Hunter Canada, Inc., Williston Hunter Inc., and Magnum Hunter Production, Inc. are wholly owned subsidiaries whose total assets and net income represent approximately 34%
and 35%, respectively, of the related consolidated financial statement amounts as of and for the year ended December 31, 2011.

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 (a) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect
the transactions and dispositions of the assets of the company; (b) 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 (c) provide reasonable assurance regarding prevention or timely detection of
unauthorized acquisition, use, or disposition of the companys assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any
evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.



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In our opinion, the Company maintained, in all material respects, effective internal control over financial
reporting as of December 31, 2011, based on criteria established in Internal ControlIntegrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets
of Magnum Hunter Resources Corporation and subsidiaries as of December 31, 2011 and 2010, and the related consolidated statements of operations, changes in stockholders equity, and cash flows for each of the three years in the period
ended December 31, 2011 and our report dated February 29, 2012 expressed an unqualified opinion thereon.

/s/ Hein &
Associates

Dallas, Texas

February 29, 2012



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MAGNUM HUNTER RESOURCES CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands, except shares and per-share data)



|                                                                                                                                                                                                                                                             |  |              |           |   |      |   |         |  
|------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------ |  | ------------ | --------- | - | ---- | - | ------- | -
|                                                                                                                                                                                                                                                             |  | December 31, |          
|                                                                                                                                                                                                                                                             |  | 2011         |           |   | 2010 |  
|ASSETS                                                                                                                                                                                                                                                       |  |              |           |   |      |   |         |  
|CURRENT ASSETS:                                                                                                                                                                                                                                              |  |              |           |   |      |   |         |  
|Cash and cash equivalents                                                                                                                                                                                                                                    |  | $            | 14,851    |   |      | $ | 554     |  
|Accounts receivable                                                                                                                                                                                                                                          |  |              | 50,476    |   |      |   | 11,705  |  
|Derivative assets                                                                                                                                                                                                                                            |  |              | 5,732     |   |      |   |        |  
|Prepaids and other current assets                                                                                                                                                                                                                            |  |              | 6,254     |   |      |   | 867     |  
|                                                                                                                                                                                                                                                             |  |              |           |   |      |   |         |  
|Total current assets                                                                                                                                                                                                                                         |  |              | 77,313    |   |      |   | 13,126  |  
|                                                                                                                                                                                                                                                             |  |              |           |   |      |   |         |  
|PROPERTY AND EQUIPMENT:                                                                                                                                                                                                                                      |  |              |           |   |      |   |         |  
|Oil and natural gas properties, successful efforts accounting                                                                                                                                                                                                |  |              | 962,965   |   |      |   | 189,912 |  
|Gas gathering and other equipment                                                                                                                                                                                                                            |  |              | 115,541   |   |      |   | 42,689  |  
|                                                                                                                                                                                                                                                             |  |              |           |   |      |   |         |  
|Total property and equipment                                                                                                                                                                                                                                 |  |              | 1,078,506 |   |      |   | 232,601 |  
|OTHER ASSETS:                                                                                                                                                                                                                                                |  |              |           |   |      |   |         |  
|Deferred financing costs, net of amortization of $958 and $1,237 respectively                                                                                                                                                                                |  |              | 10,642    |   |      |   | 2,678   |  
|Derivatives and other long-term assets                                                                                                                                                                                                                       |  |              | 1,943     |   |      |   | 562     |  
|                                                                                                                                                                                                                                                             |  |              |           |   |      |   |         |  
|Total Assets                                                                                                                                                                                                                                                 |  | $            | 1,168,404 |   |      | $ | 248,967 |  
|                                                                                                                                                                                                                                                             |  |              |           |   |      |   |         |  
|LIABILITIES AND STOCKHOLDERS EQUITY                                                                                                                                                                                                                         |  |              |           |   |      |   |         |  
|CURRENT LIABILITIES:                                                                                                                                                                                                                                         |  |              |           |   |      |   |         |  
|Current portion of notes payable                                                                                                                                                                                                                             |  | $            | 4,681     |   |      | $ | 7,132   |  
|Accounts payable                                                                                                                                                                                                                                             |  |              | 139,052   |   |      |   | 33,319  |  
|Accrued liabilities                                                                                                                                                                                                                                          |  |              | 5,656     |   |      |   | 435     |  
|Revenue payable                                                                                                                                                                                                                                              |  |              | 10,781    |   |      |   | 2,630   |  
|Derivatives and other current liabilities                                                                                                                                                                                                                    |  |              | 7,149     |   |      |   | 719     |  
|                                                                                                                                                                                                                                                             |  |              |           |   |      |   |         |  
|Total current liabilities                                                                                                                                                                                                                                    |  |              | 167,319   |   |      |   | 44,235  |  
|Notes payable, less current portion                                                                                                                                                                                                                          |  |              | 286,064   |   |      |   | 26,019  |  
|Asset retirement obligation                                                                                                                                                                                                                                  |  |              | 20,116    |   |      |   | 4,455   |  
|Deferred tax liability                                                                                                                                                                                                                                       |  |              | 95,299    |   |      |   |        |  
|Derivatives and other long term liabilities                                                                                                                                                                                                                  |  |              | 8,954     |   |      |   | 700     |  
|                                                                                                                                                                                                                                                             |  |              |           |   |      |   |         |  
|Total liabilities                                                                                                                                                                                                                                            |  |              | 577,752   |   |      |   | 75,409  |  
|                                                                                                                                                                                                                                                             |  |              |           |   |      |   |         |  
|COMMITMENTS AND CONTINGENCIES (Note 14)                                                                                                                                                                                                                      |  |              |           |   |      |   |         |  
|REDEEMABLE PREFERRED STOCK:                                                                                                                                                                                                                                  |  |              |           |   |      |   |         |  
|Series C Cumulative Perpetual Preferred Stock, cumulative dividend rate 10.25% per annum, 4,000,000 authorized, 4,000,000
and 2,809,456 issued & outstanding as of December 31, 2011 and 2010, respectively, with liquidation preference of $25.00 per share |  |              | 100,000   |   |      |   | 70,236  |  
|                                                                                                                                                                                                                                                             |  |              |           |   |      |   |         |  
|SHAREHOLDERS EQUITY:                                                                                                                                                                                                                                        |  |              |           |   |      |   |         |  
|Preferred stock, 10,000,000 shares authorized                                                                                                                                                                                                                |  |              |          |   |      |   |        |  
|Series D Cumulative Preferred Stock, cumulative dividend rate 8.0% per annum, 5,750,000 authorized, 1,437,558 and none
issued & outstanding as of December 31, 2011 and December 31, 2010, respectively, with liquidation preference of $50.00 per share     |  |              | 71,878    |   |      |   |        |  
|Common stock, $0.01 par value; 250,000,000 shares authorized, 130,270,295 and 74,863,135 shares issued and 129,803,374 and
74,863,135 outstanding as of December 31, 2011 and 2010, respectively                                                             |  |              | 1,298     |   |      |   | 749     |  
|Exchangeable common stock, par value $0.01 per share, 3,693,871 and none issued & outstanding as of December 31,
2011 and December 31, 2010, respectively                                                                                                    |  |              | 37        |   |      |   |        |  
|Additional paid in capital                                                                                                                                                                                                                                   |  |              | 569,690   |   |      |   | 152,439 |  
|Accumulated deficit                                                                                                                                                                                                                                          |  |              | (140,070  | ) |      |   | (49,402 | )
|Accumulated other comprehensive income                                                                                                                                                                                                                       |  |              | (12,463   | ) |      |   |        |  
|Treasury Stock, at cost, 761,652 shares                                                                                                                                                                                                                      |  |              | (1,310    | ) |      |   | (1,310  | )
|Unearned common stock in KSOP, at cost                                                                                                                                                                                                                       |  |              | (604      | ) |      |   | (604    | )
|                                                                                                                                                                                                                                                             |  |              |           |   |      |   |         |  
|Total Magnum Hunter Resources Corporation shareholders equity                                                                                                                                                                                               |  |              | 488,456   |   |      |   | 101,872 |  
|Noncontrolling interest                                                                                                                                                                                                                                      |  |              | 2,196     |   |      |   | 1,450   |  
|                                                                                                                                                                                                                                                             |  |              |           |   |      |   |         |  
|Total Shareholders Equity                                                                                                                                                                                                                                   |  |              | 490,652   |   |      |   | 103,322 |  
|                                                                                                                                                                                                                                                             |  |              |           |   |      |   |         |  
|Total Liabilities and Shareholders Equity                                                                                                                                                                                                                   |  | $            | 1,168,404 |   |      | $ | 248,967 |  
|                                                                                                                                                                                                                                                             |  |              |           |   |      |   |         |  



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MAGNUM HUNTER RESOURCES CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except shares and per-share data)



|                                                                                        |  |                         |             |   |      |   |            |      |  |   |            |  
|--------------------------------------------------------------------------------------- |  | ----------------------- | ----------- | - | ---- | - | ---------- | ---- |  | - | ---------- | -
|                                                                                        |  | Year Ended December 31, |            
|                                                                                        |  | 2011                    |             |   | 2010 |   |            | 2009 | 
|REVENUE:                                                                                |  |                         |             |   |      |   |            |      |  |   |            |  
|Oil and gas sales                                                                       |  | $                       | 106,266     |   |      | $ | 27,715     |      |  | $ | 6,607      |  
|Field operations and other                                                              |  |                         | 22,912      |   |      |   | 5,009      |      |  |   | 237        |  
|                                                                                        |  |                         |             |   |      |   |            |      |  |   |            |  
|Total revenue                                                                           |  |                         | 129,178     |   |      |   | 32,724     |      |  |   | 6,844      |  
|                                                                                        |  |                         |             |   |      |   |            |      |  |   |            |  
|                                                                                        |  |                         |            
|EXPENSES:                                                                               |  |                         |             |   |      |   |            |      |  |   |            |  
|Lease operating expenses                                                                |  |                         | 27,067      |   |      |   | 10,399     |      |  |   | 3,879      |  
|Severance taxes and marketing                                                           |  |                         | 7,475       |   |      |   | 2,305      |      |  |   | 500        |  
|Exploration                                                                             |  |                         | 1,537       |   |      |   | 936        |      |  |   | 790        |  
|Field Operations                                                                        |  |                         | 16,938      |   |      |   | 4,363      |      |  |   |           |  
|Impairment of unproved oil & gas properties                                             |  |                         | 1,108       |   |      |   |           |      |  |   | 634        |  
|Impairment of proved oil & gas properties                                               |  |                         | 21,792      |   |      |   | 306        |      |  |   |           |  
|Depreciation, depletion and accretion                                                   |  |                         | 49,090      |   |      |   | 8,923      |      |  |   | 3,168      |  
|General and administrative                                                              |  |                         | 63,561      |   |      |   | 24,901     |      |  |   | 8,490      |  
|                                                                                        |  |                         |             |   |      |   |            |      |  |   |            |  
|Total expenses                                                                          |  |                         | 188,568     |   |      |   | 52,133     |      |  |   | 17,461     |  
|                                                                                        |  |                         |             |   |      |   |            |      |  |   |            |  
|OPERATING LOSS                                                                          |  |                         | (59,390     | ) |      |   | (19,409    | )    |  |   | (10,617    | )
|                                                                                        |  |                         |            
|OTHER INCOME (EXPENSE):                                                                 |  |                         |             |   |      |   |            |      |  |   |            |  
|Interest income                                                                         |  |                         | 27          |   |      |   | 61         |      |  |   | 1          |  
|Interest expense                                                                        |  |                         | (12,005     | ) |      |   | (3,594     | )    |  |   | (2,691     | )
|Gain (loss) on derivative contracts                                                     |  |                         | (6,346      | ) |      |   | 814        |      |  |   | (2,325     | )
|Other                                                                                   |  |                         | 606         |   |      |   |           |      |  |   |           |  
|                                                                                        |  |                         |             |   |      |   |            |      |  |   |            |  
|Total other income and expense                                                          |  |                         | (17,718     | ) |      |   | (2,719     | )    |  |   | (5,015     | )
|Loss from continuing operations before non-controlling interest                         |  |                         | (77,108     | ) |      |   | (22,128    | )    |  |   | (15,632    | )
|Income tax benefit                                                                      |  |                         | 696         |   |      |   |           |      |  |   |           |  
|Net (income) loss attributable to non-controlling interest                              |  |                         | (249        | ) |      |   | (129       | )    |  |   | 63         |  
|                                                                                        |  |                         |             |   |      |   |            |      |  |   |            |  
|Net loss attributable to Magnum Hunter Resources Corporation from continuing operations |  |                         | (76,661     | ) |      |   | (22,257    | )    |  |   | (15,569    | )
|Income from discontinued operations                                                     |  |                         |            |   |      |   | 8,457      |      |  |   | 445        |  
|                                                                                        |  |                         |             |   |      |   |            |      |  |   |            |  
|Net loss                                                                                |  |                         | (76,661     | ) |      |   | (13,800    | )    |  |   | (15,124    | )
|Dividends on Preferred Stock                                                            |  |                         | (14,007     | ) |      |   | (2,467     | )    |  |   | (26        | )
|                                                                                        |  |                         |             |   |      |   |            |      |  |   |            |  
|Net loss attributable to common shareholders                                            |  | $                       | (90,668     | ) |      | $ | (16,267    | )    |  | $ | (15,150    | )
|                                                                                        |  |                         |             |   |      |   |            |      |  |   |            |  
|Weighted average number of common shares outstanding, basic and diluted                 |  |                         | 113,154,270 |   |      |   | 63,921,525 |      |  |   | 38,953,834 |  
|                                                                                        |  |                         |             |   |      |   |            |      |  |   |            |  
|Net loss from continuing operations                                                     |  | $                       | (0.80       | ) |      | $ | (0.38      | )    |  | $ | (0.40      | )
|                                                                                        |  |                         |             |   |      |   |            |      |  |   |            |  
|Net income from discontinued operations                                                 |  | $                       |            |   |      | $ | 0.13       |      |  | $ | 0.01       |  
|                                                                                        |  |                         |             |   |      |   |            |      |  |   |            |  
|Net loss per common share, basic and diluted                                            |  | $                       | (0.80       | ) |      | $ | (0.25      | )    |  | $ | (0.39      | )
|                                                                                        |  |                         |             |   |      |   |            |      |  |   |            |  



F-6



---

##### Table of Contents

MAGNUM HUNTER RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF OTHER COMPREHENSIVE INCOME

(In thousands, except shares and per-share data)



|                                                         |  |                         |         |   |      |   |         |      |  |   |         |  
|-------------------------------------------------------- |  | ----------------------- | ------- | - | ---- | - | ------- | ---- |  | - | ------- | -
|                                                         |  | Year ended December 31, |        
|                                                         |  | 2011                    |         |   | 2010 |   |         | 2009 | 
|Net income (loss)                                        |  | $                       | (76,661 | ) |      | $ | (13,800 | )    |  | $ | (15,124 | )
|Foreign currency translation                             |  |                         | (12,477 | ) |      |   |        |      |  |   |        |  
|Unrealized gain (loss) on available for sale investments |  |                         | 14      |   |      |   |        |      |  |   |        |  
|                                                         |  |                         |         |   |      |   |         |      |  |   |         |  
|Total comprehensive loss                                 |  | $                       | (89,124 | ) |      | $ | (13,800 | )    |  | $ | (15,124 | )
|                                                         |  |                         |         |   |      |   |         |      |  |   |         |  



F-7



---

##### Table of Contents

MAGNUM HUNTER RESOURCES CORPORATION

CONDENSED CONSOLIDATED STATEMENT OF SHAREHOLDERS EQUITY

(In thousands)



|                                                                                     |  |                          |        |  |                                           |  |   |                                           |  |  |                |  |  |             |        |   |                          |   |     |                        |  |   |                          |  |  |                    |   |  |                                      |   |        |               |  |   |                             |   |  |                         |   |  |                          |   |        |   |  |   |      |   |  |   |       |   |  |   |         |  
|------------------------------------------------------------------------------------ |  | ------------------------ | ------ |  | ----------------------------------------- |  | - | ----------------------------------------- |  |  | -------------- |  |  | ----------- | ------ | - | ------------------------ | - | --- | ---------------------- |  | - | ------------------------ |  |  | ------------------ | - |  | ------------------------------------ | - | ------ | ------------- |  | - | --------------------------- | - |  | ----------------------- | - |  | ------------------------ | - | ------ | - |  | - | ---- | - |  | - | ----- | - |  | - | ------- | -
|                                                                                     |  | Numberof Sharesof Common |        |  | Numberof Shares ofExchangeableCommonStock |  |   | Number ofShares ofSeries 
DPreferredStock |  |  | DepositonTriad |  |  | CommonStock |        |   | Exchang-eableCommonStock |   |     | Series DPreferredStock |  |   | AdditionalPaid inCapital |  |  | AccumulatedDeficit |   |  | AccumulatedOtherCompre-hensiveIncome |   |        | TreasuryStock |  |   | UnearnedCommonShares inKSOP |   |  | Non-controllingInterest |   |  | TotalShareholdersEquity |  
|BALANCE, January 1, 2009                                                             |  |                          | 36,768 |  |                                           |  |  |                                           |  |  |               |  |  | $           |       |   |                          | $ | 368 |                        |  | $ |                         |  |  | $                  |  |  |                                      | $ | 51,311 |               |  | $ | (17,986                     | ) |  |                         |  |  |                          | $ |       |   |  | $ |     |   |  | $ | 1,385 |   |  | $ | 35,078  |  
|Restricted stock issued to employees and directors                                   |  |                          | 1,886  |  |                                           |  |  |                                           |  |  |               |  |  |             |       |   |                          |   | 19  |                        |  |   |                         |  |  |                    |  |  |                                      |   | 1,362  |               |  |   |                            |   |  |                         |  |  |                          |   |       |   |  |   |     |   |  |   |      |   |  |   | 1,381   |  
|Stock compensation                                                                   |  |                          |       |  |                                           |  |  |                                           |  |  |               |  |  |             |       |   |                          |   |    |                        |  |   |                         |  |  |                    |  |  |                                      |   | 1,711  |               |  |   |                            |   |  |                         |  |  |                          |   |       |   |  |   |     |   |  |   |      |   |  |   | 1,711   |  
|Issued shares of common stock for acquisition of Sharon Resources, Inc.              |  |                          | 2,294  |  |                                           |  |  |                                           |  |  |               |  |  |             |       |   |                          |   | 23  |                        |  |   |                         |  |  |                    |  |  |                                      |   | 2,661  |               |  |   |                            |   |  |                         |  |  |                          |   |       |   |  |   |     |   |  |   |      |   |  |   | 2,684   |  
|Issued 214,950 shares of Series C Preferred Stock                                    |  |                          |       |  |                                           |  |  |                                           |  |  |               |  |  |             |       |   |                          |   |    |                        |  |   |                         |  |  |                    |  |  |                                      |   | (418   | )             |  |   |                            |   |  |                         |  |  |                          |   |       |   |  |   |     |   |  |   |      |   |  |   | (418    | )
|Issued 8,881,112 shares of Common Stock                                              |  |                          | 8,881  |  |                                           |  |  |                                           |  |  |               |  |  |             |       |   |                          |   | 89  |                        |  |   |                         |  |  |                    |  |  |                                      |   | 14,006 |               |  |   |                            |   |  |                         |  |  |                          |   |       |   |  |   |     |   |  |   |      |   |  |   | 14,095  |  
|Dividends on Series C Convertible Preferred                                          |  |                          |       |  |                                           |  |  |                                           |  |  |               |  |  |             |       |   |                          |   |    |                        |  |   |                         |  |  |                    |  |  |                                      |   |       |               |  |   | (25                         | ) |  |                         |  |  |                          |   |       |   |  |   |     |   |  |   |      |   |  |   | (25     | )
|Issued 761,652 shares as deposit on Triad Acquisition                                |  |                          | 762    |  |                                           |  |  |                                           |  |  |               |  |  |             | (1,310 | ) |                          |   | 7   |                        |  |   |                         |  |  |                    |  |  |                                      |   | 1,303  |               |  |   |                            |   |  |                         |  |  |                          |   |       |   |  |   |     |   |  |   |      |   |  |   |        |  
|Net loss                                                                             |  |                          |       |  |                                           |  |  |                                           |  |  |               |  |  |             |       |   |                          |   |    |                        |  |   |                         |  |  |                    |  |  |                                      |   |       |               |  |   | (15,124                     | ) |  |                         |  |  |                          |   |       |   |  |   |     |   |  |   | (64   | ) |  |   | (15,188 | )
|                                                                                     |  |                          |        |  |                                           |  |   |                                           |  |  |                |  |  |             |        |   |                          |   |     |                        |  |   |                          |  |  |                    |   |  |                                      |   |        |               |  |   |                             |   |  |                         |   |  |                          |   |        |   |  |   |      |   |  |   |       |   |  |   |         |  
|BALANCE, December 31, 2009                                                           |  |                          | 50,591 |  |                                           |  |  |                                           |  |  |               |  |  | $           | (1,310 | ) |                          | $ | 506 |                        |  | $ |                         |  |  | $                  |  |  |                                      | $ | 71,936 |               |  | $ | (33,135                     | ) |  | $                       |  |  |                          | $ |       |   |  | $ |     |   |  | $ | 1,321 |   |  | $ | 39,318  |  
|Restricted stock issued to employees and directors                                   |  |                          | 2,539  |  |                                           |  |  |                                           |  |  |               |  |  |             |       |   |                          |   | 25  |                        |  |   |                         |  |  |                    |  |  |                                      |   | 426    |               |  |   |                            |   |  |                         |  |  |                          |   |       |   |  |   |     |   |  |   |      |   |  |   | 451     |  
|Stock compensation                                                                   |  |                          |       |  |                                           |  |  |                                           |  |  |               |  |  |             |       |   |                          |   |    |                        |  |   |                         |  |  |                    |  |  |                                      |   | 5,929  |               |  |   |                            |   |  |                         |  |  |                          |   |       |   |  |   |     |   |  |   |      |   |  |   | 5,929   |  
|Stock Options surrendered by holder for cash payment                                 |  |                          |       |  |                                           |  |  |                                           |  |  |               |  |  |             |       |   |                          |   |    |                        |  |   |                         |  |  |                    |  |  |                                      |   | (116   | )             |  |   |                            |   |  |                         |  |  |                          |   |       |   |  |   |     |   |  |   |      |   |  |   | (116    | )
|Issued 55,932 shares of common stock for payment of services                         |  |                          | 56     |  |                                           |  |  |                                           |  |  |               |  |  |             |       |   |                          |   | 1   |                        |  |   |                         |  |  |                    |  |  |                                      |   | 164    |               |  |   |                            |   |  |                         |  |  |                          |   |       |   |  |   |     |   |  |   |      |   |  |   | 165     |  
|Issued shares of Series C Preferred Stock                                            |  |                          |       |  |                                           |  |  |                                           |  |  |               |  |  |             |       |   |                          |   |    |                        |  |   |                         |  |  |                    |  |  |                                      |   | (1,419 | )             |  |   |                            |   |  |                         |  |  |                          |   |       |   |  |   |     |   |  |   |      |   |  |   | (1,419  | )
|Issued shares of Common Stock for cash                                               |  |                          | 10,832 |  |                                           |  |  |                                           |  |  |               |  |  |             |       |   |                          |   | 108 |                        |  |   |                         |  |  |                    |  |  |                                      |   | 38,570 |               |  |   |                            |   |  |                         |  |  |                          |   |       |   |  |   |     |   |  |   |      |   |  |   | 38,678  |  
|Issued shares of Common Stock upon exercise of warrants                              |  |                          | 7,537  |  |                                           |  |  |                                           |  |  |               |  |  |             |       |   |                          |   | 75  |                        |  |   |                         |  |  |                    |  |  |                                      |   | 16,031 |               |  |   |                            |   |  |                         |  |  |                          |   |       |   |  |   |     |   |  |   |      |   |  |   | 16,106  |  
|Issued 52500 shares of common stock upon stock option exercise                       |  |                          | 53     |  |                                           |  |  |                                           |  |  |               |  |  |             |       |   |                          |   | 1   |                        |  |   |                         |  |  |                    |  |  |                                      |   | 125    |               |  |   |                            |   |  |                         |  |  |                          |   |       |   |  |   |     |   |  |   |      |   |  |   | 126     |  
|Issed shares of Common Stock upon redemption of Series B Convertible Preferred Stock |  |                          | 1,000  |  |                                           |  |  |                                           |  |  |               |  |  |             |       |   |                          |   | 10  |                        |  |   |                         |  |  |                    |  |  |                                      |   | 3,722  |               |  |   |                            |   |  |                         |  |  |                          |   |       |   |  |   |     |   |  |   |      |   |  |   | 3,732   |  
|Dividends on Series B Convertible Preferred                                          |  |                          |       |  |                                           |  |  |                                           |  |  |               |  |  |             |       |   |                          |   |    |                        |  |   |                         |  |  |                    |  |  |                                      |   |       |               |  |   | (131                        | ) |  |                         |  |  |                          |   |       |   |  |   |     |   |  |   |      |   |  |   | (131    | )
|Dividends on Series C Cumulative Perpetual Preferred                                 |  |                          |       |  |                                           |  |  |                                           |  |  |               |  |  |             |       |   |                          |   |    |                        |  |   |                         |  |  |                    |  |  |                                      |   |       |               |  |   | (2,336                      | ) |  |                         |  |  |                          |   |       |   |  |   |     |   |  |   |      |   |  |   | (2,336  | )
|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 2,255,046 shares of common stock for acquisition of assets                    |  |                          | 2,255  |  |                                           |  |  |                                           |  |  |               |  |  |             |       |   |                          |   | 23  |                        |  |   |                         |  |  |                    |  |  |                                      |   | 17,071 |               |  |   |                            |   |  |                         |  |  |                          |   |       |   |  |   |     |   |  |   |      |   |  |   | 17,094  |  
|Net loss                                                                             |  |                          |       |  |                                           |  |  |                                           |  |  |               |  |  |             |       |   |                          |   |    |                        |  |   |                         |  |  |                    |  |  |                                      |   |       |               |  |   | (13,800                     | ) |  |                         |  |  |                          |   |       |   |  |   |     |   |  |   | 129   |   |  |   | (13,671 | )
|                                                                                     |  |                          |        |  |                                           |  |   |                                           |  |  |                |  |  |             |        |   |                          |   |     |                        |  |   |                          |  |  |                    |   |  |                                      |   |        |               |  |   |                             |   |  |                         |   |  |                          |   |        |   |  |   |      |   |  |   |       |   |  |   |         |  



F-8



---

##### Table of Contents

|                                                                                                                                                   |  |                          |         |  |                                           |  |       |                                           |  |  |                |  |  |             |   |  |                          |   |       |                        |  |   |                          |   |  |                    |        |  |                                      |   |         |               |  |   |                             |   |  |                         |         |   |                          |   |        |   |  |   |      |   |  |   |       |  |  |   |         |  
|-------------------------------------------------------------------------------------------------------------------------------------------------- |  | ------------------------ | ------- |  | ----------------------------------------- |  | ----- | ----------------------------------------- |  |  | -------------- |  |  | ----------- | - |  | ------------------------ | - | ----- | ---------------------- |  | - | ------------------------ | - |  | ------------------ | ------ |  | ------------------------------------ | - | ------- | ------------- |  | - | --------------------------- | - |  | ----------------------- | ------- | - | ------------------------ | - | ------ | - |  | - | ---- | - |  | - | ----- |  |  | - | ------- | -
|                                                                                                                                                   |  | Numberof Sharesof Common |         |  | Numberof Shares ofExchangeableCommonStock |  |       | Number ofShares ofSeries 
DPreferredStock |  |  | DepositonTriad |  |  | CommonStock |   |  | Exchang-eableCommonStock |   |       | Series DPreferredStock |  |   | AdditionalPaid inCapital |   |  | AccumulatedDeficit |        |  | AccumulatedOtherCompre-hensiveIncome |   |         | TreasuryStock |  |   | UnearnedCommonShares inKSOP |   |  | Non-controllingInterest |         |   | TotalShareholdersEquity |  
|BALANCE, December 31, 2010                                                                                                                         |  |                          | 74,863  |  |                                           |  |      |                                           |  |  |               |  |  | $           |  |  |                          | $ | 749   |                        |  | $ |                         |   |  | $                  |       |  |                                      | $ | 152,439 |               |  | $ | (49,402                     | ) |  | $                       |        |   |                          | $ | (1,310 | ) |  | $ | (604 | ) |  | $ | 1,450 |  |  | $ | 103,322 |  
|Restricted stock issued to employees and directors                                                                                                 |  |                          | 121     |  |                                           |  |      |                                           |  |  |               |  |  |             |  |  |                          |   | 1     |                        |  |   |                         |   |  |                    |       |  |                                      |   | 413     |               |  |   |                            |   |  |                         |        |   |                          |   |       |   |  |   |     |   |  |   |      |  |  |   | 414     |  
|Stock compensation                                                                                                                                 |  |                          |        |  |                                           |  |      |                                           |  |  |               |  |  |             |  |  |                          |   |      |                        |  |   |                         |   |  |                    |       |  |                                      |   | 24,643  |               |  |   |                            |   |  |                         |        |   |                          |   |       |   |  |   |     |   |  |   |      |  |  |   | 24,643  |  
|Issued shares of Series C Preferred Stock for cash                                                                                                 |  |                          |        |  |                                           |  |      |                                           |  |  |               |  |  |             |  |  |                          |   |      |                        |  |   |                         |   |  |                    |       |  |                                      |   | (689    | )             |  |   |                            |   |  |                         |        |   |                          |   |       |   |  |   |     |   |  |   |      |  |  |   | (689    | )
|Issued shares of Common Stock for cash                                                                                                             |  |                          | 1,714   |  |                                           |  |      |                                           |  |  |               |  |  |             |  |  |                          |   | 17    |                        |  |   |                         |   |  |                    |       |  |                                      |   | 13,875  |               |  |   |                            |   |  |                         |        |   |                          |   |       |   |  |   |     |   |  |   |      |  |  |   | 13,892  |  
|Issued shares of Series D Preferred Stock for cash                                                                                                 |  |                          |        |  |                                           |  |      |                                           |  |  | 1,438          |  |  |             |  |  |                          |   |      |                        |  |   |                         |   |  |                    | 71,878 |  |                                      |   | (6,189  | )             |  |   |                            |   |  |                         |        |   |                          |   |       |   |  |   |     |   |  |   |      |  |  |   | 65,689  |  
|Issued shares of Common Stock upon warrant exercise                                                                                                |  |                          | 814     |  |                                           |  |      |                                           |  |  |               |  |  |             |  |  |                          |   | 8     |                        |  |   |                         |   |  |                    |       |  |                                      |   | 2,420   |               |  |   |                            |   |  |                         |        |   |                          |   |       |   |  |   |     |   |  |   |      |  |  |   | 2,428   |  
|Issued shares of common stock upon stock option exercise                                                                                           |  |                          | 5,479   |  |                                           |  |      |                                           |  |  |               |  |  |             |  |  |                          |   | 55    |                        |  |   |                         |   |  |                    |       |  |                                      |   | 5,135   |               |  |   |                            |   |  |                         |        |   |                          |   |       |   |  |   |     |   |  |   |      |  |  |   | 5,190   |  
|Dividends Preferred Stock                                                                                                                          |  |                          |        |  |                                           |  |      |                                           |  |  |               |  |  |             |  |  |                          |   |      |                        |  |   |                         |   |  |                    |       |  |                                      |   |        |               |  |   | (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 acquisition of assets                                                                                            |  |                          | 946     |  |                                           |  |      |                                           |  |  |               |  |  |             |  |  |                          |   | 9     |                        |  |   |                         |   |  |                    |       |  |                                      |   | 7,533   |               |  |   |                            |   |  |                         |        |   |                          |   |       |   |  |   |     |   |  |   |      |  |  |   | 7,542   |  
|Issued shares of common stock for acquisition of NGAS Resources                                                                                    |  |                          | 6,635   |  |                                           |  |      |                                           |  |  |               |  |  |             |  |  |                          |   | 66    |                        |  |   |                         |   |  |                    |       |  |                                      |   | 52,951  |               |  |   |                            |   |  |                         |        |   |                          |   |       |   |  |   |     |   |  |   |      |  |  |   | 53,017  |  
|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     |  
|Noncontrolling interest acquired in NGAS acquisition                                                                                               |  |                          |        |  |                                           |  |      |                                           |  |  |               |  |  |             |  |  |                          |   |      |                        |  |   |                         |   |  |                    |       |  |                                      |   |        |               |  |   |                            |   |  |                         |        |   |                          |   |       |   |  |   |     |   |  |   | 497   |  |  |   | 497     |  
|Issued shares of common stock for acquisition of NuLoch Resources                                                                                  |  |                          | 38,132  |  |                                           |  |      |                                           |  |  |               |  |  |             |  |  |                          |   | 381   |                        |  |   |                         |   |  |                    |       |  |                                      |   | 281,794 |               |  |   |                            |   |  |                         |        |   |                          |   |       |   |  |   |     |   |  |   |      |  |  |   | 282,175 |  
|Issued exchangeable shares for acquisition of NuLoch Resources                                                                                     |  |                          |        |  |                                           |  | 4,276 |                                           |  |  |               |  |  |             |  |  |                          |   |      |                        |  |   | 43                       |   |  |                    |       |  |                                      |   | 31,600  |               |  |   |                            |   |  |                         |        |   |                          |   |       |   |  |   |     |   |  |   |      |  |  |   | 31,643  |  
|Issued shared 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 | )
|Other comprehensive income:                                                                                                                        |  |                          |         |  |                                           |  |       |                                           |  |  |                |  |  |             |   |  |                          |   |       |                        |  |   |                          |   |  |                    |        |  |                                      |   |         |               |  |   |                             |   |  |                         |         |   |                          |   |        |   |  |   |      |   |  |   |       |  |  |   |         |  
|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          |  |  | $           |  |  |                          | $ | 1,298 |                        |  | $ | 37                       |   |  | $                  | 71,878 |  |                                      | $ | 569,690 |               |  | $ | (140,070                    | ) |  | $                       | (12,463 | ) |                          | $ | (1,310 | ) |  | $ | (604 | ) |  | $ | 2,196 |  |  | $ | 490,652 |  
|                                                                                                                                                   |  |                          |         |  |                                           |  |       |                                           |  |  |                |  |  |             |   |  |                          |   |       |                        |  |   |                          |   |  |                    |        |  |                                      |   |         |               |  |   |                             |   |  |                         |         |   |                          |   |        |   |  |   |      |   |  |   |       |  |  |   |         |  



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##### Table of Contents

MAGNUM HUNTER RESOURCES CORPORATION

CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS

(In thousands)



|                                                                                           |  |                         |          |   |      |   |          |      |  |   |         |  
|------------------------------------------------------------------------------------------ |  | ----------------------- | -------- | - | ---- | - | -------- | ---- |  | - | ------- | -
|                                                                                           |  | Year Ended December 31, |         
|                                                                                           |  | 2011                    |          |   | 2010 |   |          | 2009 | 
|Cash flows from operating activities                                                       |  |                         |          |   |      |   |          |      |  |   |         |  
|Net loss                                                                                   |  | $                       | (76,661  | ) |      | $ | (13,800  | )    |  | $ | (15,124 | )
|Adjustments to reconcile net loss to net cash provided by (used in) operating activities:  |  |                         |          |   |      |   |          |      |  |   |         |  
|Noncontrolling interest                                                                    |  |                         | 249      |   |      |   | 129      |      |  |   | (63     | )
|Depletion, depreciation, and accretion                                                     |  |                         | 49,090   |   |      |   | 10,346   |      |  |   | 4,500   |  
|Share-based compensation                                                                   |  |                         | 25,057   |   |      |   | 6,379    |      |  |   | 3,091   |  
|Asset Impairment                                                                           |  |                         | 22,900   |   |      |   | 306      |      |  |   | 634     |  
|Cash paid for plugging wells                                                               |  |                         | (8       | ) |      |   |         |      |  |   |        |  
|Exploratory costs                                                                          |  |                         |         |   |      |   |         |      |  |   | 647     |  
|Gain on sale of assets                                                                     |  |                         | (186     | ) |      |   | (6,731   | )    |  |   | (14     | )
|Unrealized (gain) loss on derivative contracts                                             |  |                         | 4,210    |   |      |   | 3,063    |      |  |   | 7,700   |  
|Amortization of deferred financing cost included in interest expense                       |  |                         | 3,636    |   |      |   | 1,201    |      |  |   | 1,234   |  
|Deferred Taxes                                                                             |  |                         | (696     | ) |      |   |         |      |  |   |        |  
|Changes in operating assets and liabilities:                                               |  |                         |          |   |      |   |          |      |  |   |         |  
|Accounts receivable and accrued revenue                                                    |  |                         | (25,075  | ) |      |   | (2,949   | )    |  |   | (1,909  | )
|Inventory                                                                                  |  |                         | (3,889   | ) |      |   |         |      |  |   |        |  
|Prepaid expenses and other current assets                                                  |  |                         | (124     | ) |      |   | 134      |      |  |   | (16     | )
|Accounts payable                                                                           |  |                         | 25,883   |   |      |   | 8,866    |      |  |   | 1,571   |  
|Revenue payable                                                                            |  |                         | 6,979    |   |      |   | 359      |      |  |   | 343     |  
|Accrued liabilities                                                                        |  |                         | 2,473    |   |      |   | (8,470   | )    |  |   | 779     |  
|                                                                                           |  |                         |          |   |      |   |          |      |  |   |         |  
|Net cash provided by (used in) operating activities                                        |  |                         | 33,838   |   |      |   | (1,167   | )    |  |   | 3,373   |  
|                                                                                           |  |                         |          |   |      |   |          |      |  |   |         |  
|Cash flows from investing activities                                                       |  |                         |          |   |      |   |          |      |  |   |         |  
|Capital expenditures and advances                                                          |  |                         | (291,942 | ) |      |   | (80,078  | )    |  |   | (14,602 | )
|Net cash paid in acquisition, net of cash received of $2,500; $0; and $235, respectively   |  |                         | (78,524  | ) |      |   | (59,500  | )    |  |   | 235     |  
|Change in restricted cash and deposits                                                     |  |                         | 42       |   |      |   | 59       |      |  |   | (56     | )
|Proceeds from sale of assets                                                               |  |                         | 8,709    |   |      |   | 21,238   |      |  |   | 500     |  
|Purchase of derivatives                                                                    |  |                         |         |   |      |   |         |      |  |   | (2,701  | )
|                                                                                           |  |                         |          |   |      |   |          |      |  |   |         |  
|Net cash used in investing activities                                                      |  |                         | (361,715 | ) |      |   | (118,281 | )    |  |   | (16,624 | )
|                                                                                           |  |                         |          |   |      |   |          |      |  |   |         |  
|Cash flows from financing activities                                                       |  |                         |          |   |      |   |          |      |  |   |         |  
|Net proceeds from sale of common stock and warrants                                        |  |                         | 13,892   |   |      |   | 38,678   |      |  |   | 14,095  |  
|Net proceeds from sale of preferred shares                                                 |  |                         | 94,764   |   |      |   | 63,444   |      |  |   | 4,956   |  
|Proceeds from exercise of warrants and options                                             |  |                         | 7,618    |   |      |   | 16,231   |      |  |   |        |  
|Purchase of company shares and loan to KSOP                                                |  |                         |         |   |      |   | (604     | )    |  |   |        |  
|Options surrendered for cash                                                               |  |                         |         |   |      |   | (116     | )    |  |   |        |  
|Preferred stock dividends paid                                                             |  |                         | (14,007  | ) |      |   | (2,492   | )    |  |   |        |  
|Principal repayments of debt                                                               |  |                         | (242,472 | ) |      |   | (84,886  | )    |  |   | (34,194 | )
|Proceeds from borrowings on debt                                                           |  |                         | 493,906  |   |      |   | 101,581  |      |  |   | 25,718  |  
|Payment on payable on sale of partnership                                                  |  |                         |         |   |      |   |         |      |  |   | (113    | )
|Payment of deferred financing costs                                                        |  |                         | (11,577  | ) |      |   | (2,866   | )    |  |   | (1,049  | )
|Cash paid upon conversion of Series B preferred stock                                      |  |                         |         |   |      |   | (11,250  | )    |  |   |        |  
|Change in other long-term liabilities                                                      |  |                         | 69       |   |      |   |         |      |  |   |        |  
|                                                                                           |  |                         |          |   |      |   |          |      |  |   |         |  
|Net cash provided by financing activities                                                  |  |                         | 342,193  |   |      |   | 117,720  |      |  |   | 9,413   |  
|                                                                                           |  |                         |          |   |      |   |          |      |  |   |         |  
|Effect of exchange rate changes on cash                                                    |  |                         | (19      | ) |      |   |         |      |  |   |        |  
|                                                                                           |  |                         |          |   |      |   |          |      |  |   |         |  
|Net change in cash and cash equivalents                                                    |  |                         | 14,297   |   |      |   | (1,728   | )    |  |   | (3,838  | )
|Cash and cash equivalents, beginning of year                                               |  |                         | 554      |   |      |   | 2,282    |      |  |   | 6,120   |  
|                                                                                           |  |                         |          |   |      |   |          |      |  |   |         |  
|Cash and cash equivalents, end of year                                                     |  | $                       | 14,851   |   |      | $ | 554      |      |  | $ | 2,282   |  
|                                                                                           |  |                         |          |   |      |   |          |      |  |   |         |  
|Cash paid for interest                                                                     |  | $                       | 7,952    |   |      | $ | 2,749    |      |  | $ | 2,142   |  
|                                                                                           |  |                         |          |   |      |   |          |      |  |   |         |  
|Noncash transactions                                                                       |  |                         |          |   |      |   |          |      |  |   |         |  
|Common stock issued for acquisitions                                                       |  | $                       | 345,537  |   |      | $ | 17,093   |      |  | $ | 2,685   |  
|                                                                                           |  |                         |          |   |      |   |          |      |  |   |         |  
|Series B Preferred stock issued for acquisition of Triad                                   |  | $                       |         |   |      | $ | 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    |      |  | $ |        |  
|                                                                                           |  |                         |          |   |      |   |          |      |  |   |         |  
|Accrued capital expenditures                                                               |  | $                       | 81,136   |   |      | $ | 23,218   |      |  | $ |        |  
|                                                                                           |  |                         |          |   |      |   |          |      |  |   |         |  
|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

NOTE 1ORGANIZATION AND NATURE OF OPERATIONS

Magnum Hunter Resources Corporation and subsidiaries (Magnum Hunter) (a Delaware Corporation) is a Houston, Texas based
independent exploration and production company engaged in the acquisition and development of producing properties, secondary enhanced oil recovery projects, and production of oil and natural gas in the United States.

On July 14, 2009, the Company formed a new subsidiary to purchase Magnum Hunter Resources, LP and the new subsidiary was merged into Petro
Resources Corporation in order to effect a name change from Petro Resources Corporation to Magnum Hunter Resources Corporation.

NOTE 2LIQUIDITY

At December 31, 2011, we had cash and cash equivalents of $14.9 million, of which $1.7 million of the cash was held by Eureka
Hunter and was only available for use by Eureka Hunter and not the Company as a whole, and working capital deficit of $90.0 million. For the year ended December 31, 2011, we had net loss attributable to common shareholders of
$90.7 million and a operating loss from continued operations of $76.7 million, including a $22.9 million impairment of long-lived assets (see Note 3).

We depend on our credit agreements, as described in Note 9, to fund a portion of our operating and capital needs. Under our senior revolving credit agreement, our borrowing base at December 31,
2011, based upon our proved reserves, was $200.0 million. At December 31, 2011, our remaining available borrowing capacity under the senior credit agreement was $58.0 million. On February 14, 2012, our borrowing base under our
senior revolving credit agreement was increased from $200 million to $235 million. See Note 17Subsequent Events for additional information. Pursuant to the terms of our senior revolving credit agreement, our borrowing base is to be
redetermined based upon our June 30, 2012 reserve report.

At December 31, 2011, we were not in compliance with the covenant
contained in our senior revolving and term loan credit agreements that requires we maintain certain ratios of current assets to current liabilities as described in Note 9. We have received a waiver of the covenant but must be in compliance with the
covenant for each quarterly measurement date in 2012, which we believe is probable.

We believe the combination of (i) cash on hand,
(ii) cash flow generated from the expected success of prior capital development projects, (iii) debt available under our credit agreements and (iv) our ability to access the equity markets, provide sufficient means to conduct our
operations, meet our contractual obligations, including our debt covenant requirements and undertake our capital expenditure program for the twelve months ending December 31, 2012.

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. (f/k/a Sharon Hunter Resources, Inc.), referred to as Sharon, Triad
Hunter, LLC, Alpha Hunter Drilling, LLC, Hunter Disposal, LLC, Eureka Hunter Pipeline, LLC, Eureka Hunter Pipeline Partners, LLC, Hunter Real Estate, LLC, NGAS Hunter, LLC (f/k/a MHR Acquisition Company I, LLC), Magnum Hunter Production, Inc. (f/k/a
NGAS 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 (f/k/a MHR Acquisition II, LLC),
NGAS Gathering, LLC, Sentra Corporation, Energy Hunter Securities, Inc (f/k/a NGAS Securities, Inc) and MHR Acquisition Company III, LLC. We also have consolidated our 87.5% controlling interest in PRC Williston, LLC, or PRC, with noncontrolling
interests recorded for the outside interest in PRC. The consolidated financial statements also reflect the interest 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.



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##### Table of Contents

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 in Note 2Estimates of Proved Oil and Gas Reserves, may have a material impact on the carrying value of oil and gas property.

Critical accounting policies are defined as those significant accounting policies that are most critical to an understanding of a companys financial condition and results of operation. We consider
an accounting estimate or judgment to be critical if (i) it requires assumptions to be made that were uncertain at the time the estimate was made, and (ii) changes in the estimate or different estimates that could have been selected could
have a material impact on our results of operations or financial condition.

Reclassification of Prior-Year Balances

Certain prior-year balances in the consolidated financial statements have been reclassified to correspond with current-year classifications.

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, 2011, 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 and long-term debt approximate fair value, as of December 31, 2011 and 2010. See
Note 4 for commodity derivative fair value disclosures.

Oil and Gas Properties

Capitalized Costs

Our oil and gas
properties were comprised of the following:



|                                            |  |                |           |   |      |   |         |  
|------------------------------------------- |  | -------------- | --------- | - | ---- | - | ------- | -
|                                            |  | December 31,   |          
|                                            |  | 2011           |           |   | 2010 |  
|                                            |  | (in thousands) |          
|Mineral interests in properties:            |  |                |           |   |      |   |         |  
|Unproved properties                         |  | $              | 424,610   |   |      | $ | 57,428  |  
|Proved properties                           |  |                | 221,115   |   |      |   | 84,968  |  
|Wells and related equipment and facilities  |  |                | 349,533   |   |      |   | 55,938  |  
|Uncompleted wells, equipment and facilities |  |                | 27,741    |   |      |   | 13,580  |  
|Advances                                    |  |                | 4,437     |   |      |   | 6       |  
|                                            |  |                |           |   |      |   |         |  
|Total costs                                 |  |                | 1,027,436 |   |      |   | 211,920 |  
|Less accumulated depreciation and depletion |  |                | (64,471   | ) |      |   | (22,008 | )
|                                            |  |                |           |   |      |   |         |  
|Net capitalized costs                       |  | $              | 962,965   |   |      | $ | 189,912 |  
|                                            |  |                |           |   |      |   |         |  



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##### Table of Contents

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. Geological and geophysical costs, including seismic studies and costs of carrying and retaining unproved properties are charged to expense as
incurred. We capitalize interest on expenditures for significant exploration and development projects that last more than six months while activities are in progress to bring the assets to their intended use. No interest was capitalized during the
periods presented.

On the sale or retirement of a complete unit of a proved property, the cost and related accumulated depreciation,
depletion, and amortization are eliminated from the property accounts, and the resultant gain or loss is recognized. On the retirement or sale of a partial unit of proved property, the cost is charged to accumulated depreciation, depletion, and
amortization with a resulting gain or loss recognized in income. A sale of a significant property 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.

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. Depreciation and depletion expense for oil and gas producing
property and related equipment was $42.5 million, $8.9 million, and $3.2 million for the years ended December 31, 2011, 2010, and 2009, respectively.

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. We recorded $1.1 million in unproved property impairment during the year ended December 31, 2011, comprising $306,000 and $802,000 in our Eagle Ford and Appalachian regions, respectively, due to expiring acreage that we chose not to
develop. We recorded none for the year ended December 31, 2010, and $0.6 million during the year ended December 31, 2009. The 2009 impairment resulted from a write-off of $0.4 million in acreage costs in the Boomerang Prospect in Kentucky
as well as a $0.2 million write-off on the LeBlanc Prospect in Louisiana and the West Greene Field in North Dakota.

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. Impairment of proved oil and gas properties was calculated on a field by field basis under the successful efforts accounting method. An impairment was recorded when the estimated fair value of a
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. We recorded $21.8 million in
impairment charges to our proved properties held by Magnum Hunter Production, our wholly-owned subsidiary, for the year ended December 31, 2011, a charge of $0.3 million on our Giddings Field proved properties based on our analysis for the year
ended December 31, 2010, and none for the year ended December 31, 2009.

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 found in the operating agreement that joint interest owners in a
property adopt. We record these advance payments in Advances in our property account and release this account when the actual expenditure is later billed to us by the operator.

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



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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, or 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, beginning December 31, 2009, 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. In prior years, such estimates had been based on year end prices and costs. 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 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 higher cost
fields.

Oil and Gas Operations

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.

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.



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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 based on certain publicly available indices. All transportation costs are included in marketing expense.

Accounts receivable
from joint interest owners consist of uncollateralized joint interest owner obligations due within 30 days of the invoice date. Accounts receivable, oil and gas sales, consist of uncollateralized accrued revenues due under normal trade terms,
generally requiring payment within 30 to 60 days of production. No interest is charged on past-due balances. Payments made on all accounts receivable are applied to the earliest unpaid items. 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. We had an allowance of $317,000 and $213,000 at December 31, 2011 and December 31, 2010, respectively.

Revenue Payable

Revenue
payable represents amounts collected from purchasers for oil and gas sales which are either revenues due to other revenue 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.

Advances from
Non-Operators

Advances from non-operators represent amounts collected in advance for joint operating activities. Such amounts are applied
to joint interest accounts receivable as related costs are incurred.

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.

Exploration expenses include dry hole costs, delay rentals, and geological and geophysical costs.

Dependence on Major Customers

For the
years ended December 31, 2011, 2010, and 2009, we sold substantially all of our oil and gas produced to seven purchasers. Additionally, substantially all of our accounts receivable related to oil and gas sales were due from those seven
purchasers at December 31, 2011 and 2010. We believe that there are potential alternative purchasers and that it may be necessary to establish relationships with new purchasers as 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 all of our purchasers are credit worthy.

Dependence on Suppliers

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



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Other Property

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 income in the period of disposition.

Our gas
gathering system assets and field servicing assets are carried at cost. 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.

Depreciation expense for other property and equipment was $6.6 million, $86,931, and $41,000, for the years ended December 31, 2011, 2010, 2009,
respectively.

Deferred Financing Costs

In connection with debt financings we paid $11.6 million and $2.9 million in fees in the years ended December 31, 2011, and 2010, respectively. These fees were recorded as deferred financing costs
and are being amortized over the life of the loans using the straight line method for debt is the form of a line of credit and effective interest method for term loans. Amortization of deferred financing costs for the years ended December 31,
2011, 2010, and 2009 were $3.6 million, $1.2 million, and $1.2 million, respectively.

Derivative Financial Instruments

We use commodity derivative financial instruments, typically options and swaps, to manage the risk associated with fluctuations in oil and gas prices.
Derivative instruments (including certain derivative instruments embedded in other contracts) are recorded in the balance sheet as either an asset or liability measured at its fair market value. Changes in the derivatives fair value are
recognized currently in earnings unless specific hedge criteria are met. Special accounting for qualifying hedges allows a derivatives gains and losses to offset related results on the hedged item in the income statement and requires that a
company must formally document, designate, and assess the effectiveness of transactions that receive hedge accounting. Our oil and gas price derivative contracts are not designated as hedges. These instruments have been marked-to-market through
earnings.

Asset Retirement Obligation

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

Our liability is determined using significant assumptions, including current estimates of plugging and abandonment costs, annual inflation of
these costs, the productive lives of wells and our risk-adjusted interest rate. Changes in any of these assumptions can result in significant revisions to the estimated asset retirement obligation. Our liability for asset retirement obligations was
approximately $20.6 million and $4.5 million at December 31, 2011 and 2010, respectively. See Note 8Asset Retirement Obligations to our consolidated financial statements for more information.

Share Based Compensation

The Company
estimates the fair value of share-based payment awards made to employees and directors, including stock options, restricted stock and employee stock purchases related to employee stock purchase plans,



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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

We account for income taxes under the liability method. Deferred tax assets and liabilities are determined based on differences between financial
reporting and tax bases of assets and liabilities and are measured using the enacted tax rates and laws that will be in effect when the differences are expected to reverse.

We recognize liabilities for uncertain income tax positions based on a two-step process. The first step is to evaluate the tax position for recognition by determining if the weight of available evidence
indicates that it is more likely than not that the position will be sustained on audit, including resolution of related appeals or litigation processes, if any. The second step requires us to estimate and measure the tax benefit as the largest
amount that is more than 50% likely to be realized upon ultimate settlement. It is inherently difficult and subjective to estimate such amounts, as we must determine the probability of various possible outcomes. We reevaluate these uncertain tax
positions on a quarterly basis or when new information becomes available to management. These reevaluations are based on factors including, but not limited to, changes in facts or circumstances, changes in tax law, successfully settled issues under
audit, expirations due to statutes, and new audit activity. Such a change in recognition or measurement could result in the recognition of a tax benefit or an increase to the tax accrual. We had no uncertain tax positions at December 31, 2011
or 2010.

We classify interest related to income tax liabilities as income tax expense, and if applicable, penalties are recognized as a
component of income tax expense. The income tax liabilities and accrued interest and penalties that are anticipated to be due within one year of the balance sheet date are presented as current liabilities in our consolidated balance sheets.

Loss per Common Share

Basic
net income or loss per common share is computed by dividing the net income or loss attributable to common stockholders 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 other 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 and common
stock options granted to our employees. There were 26,129,637 and 13,862,360 dilutive securities outstanding at December 31, 2011 and 2010, respectively. 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 net loss during the periods.

The following table summarizes the
types of potentially dilutive securities outstanding as of December 31, 2011 and 2010 (in thousands):



|                                          |  |              |        |  |      |  |        | 
|----------------------------------------- |  | ------------ | ------ |  | ---- |  | ------ | 
|                                          |  | December 31, |       
|                                          |  | 2011         |        |  | 2010 | 
|Warrants                                  |  |              | 13,526 |  |      |  | 963    | 
|Restricted Shares granted, not yet issued |  |              | 38     |  |      |  | 118    | 
|Common Stock Options                      |  |              | 12,566 |  |      |  | 12,781 | 



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Recently Issued Accounting Pronouncements

In May 2011, the FASB issued ASU 2011-04, Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs. The amended guidance changes several aspects of the fair
value measurement guidance in ASC 820, Fair Value Measurement, further clarifying how to measure and disclose fair value. This guidance amends the application of the highest and best use concept to be used only in the measurement of fair
value of nonfinancial assets, clarifies that the measurement of the fair value of equity-classified financial instruments should be performed from the perspective of a market participant who holds the instrument as an asset, clarifies that an entity
that manages a group of financial assets and liabilities on the basis of its net risk exposure can measure those financial instruments on the basis of its net exposure to those risks, and clarifies when premiums and discounts should be taken into
account when measuring fair value. The fair value disclosure requirements also were amended. The amendment is effective for the Company at the beginning of January 2012, with early adoption prohibited. The adoption of this amendment is not expected
to materially affect the Companys financial statements.

In June 2011, the FASB issued ASU 2011-05, Presentation of Comprehensive Income
which amended requirements for the presentation of other comprehensive income (OCI), requiring presentation of comprehensive income in either a single, continuous statement of comprehensive income or on separate but consecutive statements, the
statement of operations and the statement of OCI. The amendment is effective for the Company at the beginning of fiscal year 2013 with early adoption permitted. The Company elected early adoption of the guidance, which only impacted the presentation
of OCI on the financial statements.

In January 2010, the FASB issued ASC 2010-06, Improving Disclosures about Fair Value Measurements
(ASC 820-10). These new disclosures require entities to separately disclose amounts of significant transfers in and out of Level 1 and Level 2 fair value measurements and the reasons for the transfers. In addition, in the reconciliation for
fair value measurements for Level 3, entities should present separate information about purchases, sales, issuances, and settlements. This guidance is effective for interim and annual reporting periods beginning after December 15, 2009, except
for the disclosures about purchases, sales, issuances and settlements in the roll forward of activity in Level 3 fair value measurements. Those disclosures are effective for fiscal years beginning after December 15, 2010 and for interim periods
within those fiscal years. Our adoption of the disclosures did not have a material impact on our notes to the condensed consolidated financial statements. See Note 4  Fair Value of Financial Instruments for additional information.

Regulated Activities

Energy Hunter
Securities, Inc. 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 (Exchange Act). 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, 2011, Energy Hunter Securities, Inc. had net capital of $49,000 and aggregate indebtedness of $132,000.

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,
2011 and 2010, our gross revenue from Sentra Corporations regulated operations aggregating $61,000 and $0, respectively.

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



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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 during the years ended December 31, 2011 and 2010:

Level 1 Classification:

Available for Sale Securities

At December 31, 2011, the Company held common stock of a company publicly traded on the TSX Venture Exchange 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, 2011 and December 31, 2010, the Company had commodity derivative financial instruments in place. The Company does not apply
hedge accounting; therefore, the changes in fair value subsequent to the initial measurement are recorded as income or expense. 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 indexes, the instruments themselves are traded with
unrelated counterparties and are not openly traded on an exchange. See Note 4Financial Instruments and Derivatives, for additional information.

As of December 31, 2011, the Companys derivative contracts were with Bank of Montreal, Keybank National Association, Credit Suisse Energy, LLC, UBS AG London Branch, and Deutsche Bank AG London
Branch, which are participants in our revolving credit facility, and have investment grade credit ratings which are believed to have a minimal credit risk. As such, the Company is exposed to credit risk to the extent of nonperformance by the
counterparties in the derivative contracts discussed above; however, the Company does not anticipate such nonperformance.



|                                                                              |  |         |     |  |         |   |        |         |  |   |   | 
|----------------------------------------------------------------------------- |  | ------- | --- |  | ------- | - | ------ | ------- |  | - | - | 
|Fair value measurements on a recurring basis
December 31, 2011 (in thousands) | 
|                                                                              |  | Level 1 |     |  | Level 2 |   |        | Level 3 | 
|Available for sale securities                                                 |  | $       | 497 |  |         | $ |       |         |  | $ |  | 
|                                                                              |  |         |     |  |         |   |        |         |  |   |   | 
|Commodity derivatives                                                         |  | $       |    |  |         | $ | 6,924  |         |  | $ |  | 
|                                                                              |  |         |     |  |         |   |        |         |  |   |   | 
|Total assets at fair value                                                    |  | $       | 497 |  |         | $ | 6,924  |         |  | $ |  | 
|                                                                              |  |         |     |  |         |   |        |         |  |   |   | 
|Commodity derivatives                                                         |  | $       |    |  |         | $ | 11,912 |         |  | $ |  | 
|                                                                              |  |         |     |  |         |   |        |         |  |   |   | 
|Total liabilities at fair value                                               |  | $       |    |  |         | $ | 11,912 |         |  | $ |  | 
|                                                                              |  |         |     |  |         |   |        |         |  |   |   | 



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|                                                                              |  |         |   |  |         |   |     |         |  |   |   | 
|----------------------------------------------------------------------------- |  | ------- | - |  | ------- | - | --- | ------- |  | - | - | 
|Fair value measurements on a recurring basis
December 31, 2010 (in thousands) | 
|                                                                              |  | Level 1 |   |  | Level 2 |   |     | Level 3 | 
|Commodity derivatives                                                         |  | $       |  |  |         | $ |    |         |  | $ |  | 
|                                                                              |  |         |   |  |         |   |     |         |  |   |   | 
|Total assets as fair value                                                    |  | $       |  |  |         | $ |    |         |  | $ |  | 
|                                                                              |  |         |   |  |         |   |     |         |  |   |   | 
|Commodity derivatives                                                         |  | $       |  |  |         | $ | 778 |         |  | $ |  | 
|                                                                              |  |         |   |  |         |   |     |         |  |   |   | 
|Total liabilities at fair value                                               |  | $       |  |  |         | $ | 778 |         |  | $ |  | 
|                                                                              |  |         |   |  |         |   |     |         |  |   |   | 

NOTE 5FINANCIAL INSTRUMENTS AND DERIVATIVES

We enter into certain commodity derivative instruments 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. Our oil and gas operating revenues and cash flows are impacted by changes in commodity product prices, which are volatile and cannot be accurately predicted. Our
objective for holding these commodity derivatives is to protect the operating revenues and cash flows related to a portion of our future crude oil and natural gas sales from the risk of significant declines in commodity prices. We have not
designated any of our commodity derivatives as hedges under ASC 815.

As of December 31, 2011, the terms of our commodity derivatives
were:



|                     |  |        |                     |  |           |  |        |                 |  |              
|-------------------- |  | ------ | ------------------- |  | --------- |  | ------ | --------------- |  | -------------
|Natural Gas          |  | Period |                     |  | MMBTU/day |  |        | Price per MMBTU
|Collars              |  |        | Jan 2012 - Dec 2012 |  |           |  | 11,910 |                 |  | $4.58 - $6.42
|                     |  |        | Jan 2013 - Dec 2013 |  |           |  | 12,500 |                 |  | $4.50 - $5.96
|Swaps                |  |        | Jan 2012 - Dec 2012 |  |           |  | 6,100  |                 |  | $4.16        
|                     |  |        | Jan 2013 - Dec 2013 |  |           |  | 6,000  |                 |  | $4.13        
|Ceilings sold (call) |  |        | Jan 2014 - Dec 2014 |  |           |  | 16,000 |                 |  | $5.91        



|                       |  |        |                     |  |          |  |       |               |  |                
|---------------------- |  | ------ | ------------------- |  | -------- |  | ----- | ------------- |  | ---------------
|                       |  |        |                    
|Crude Oil              |  | Period |                     |  | Bbls/day |  |       | Price per Bbl
|Collars                |  |        | Jan 2012 - Dec 2012 |  |          |  | 3,000 |               |  | $81.69 - $98.92
|                       |  |        | Jan 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
|Floors sold (put)      |  |        | Jan 2012 - Dec 2012 |  |          |  | 50    |               |  | $55.00         
|Floors purchased (put) |  |        | Jan 2012 - Dec 2012 |  |          |  | 153   |               |  | $80.00         



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##### Table of Contents

The following table summarizes the fair value of our derivative contracts as of the dates indicated:



|                                          |  |                                            |  |                         |       |  |                              |   |       |                  |  |   |                  |   |  |   |        |  
|----------------------------------------- |  | ------------------------------------------ |  | ----------------------- | ----- |  | ---------------------------- | - | ----- | ---------------- |  | - | ---------------- | - |  | - | ------ | -
|In thousands Derivatives notdesignated as |  |                                            |  | Gross Derivative Assets |       |  | Gross Derivative Liabilities |  
|hedginginstruments                        |  | Balance Sheet Classification               |  | December 31,2011        |       |  | December 31,2010             |   |       | December 31,2011 |  |   | December 31,2010 |  
|Commodity                                 |  |                                            |  |                         |       |  |                              |   |       |                  |  |   |                  |   |  |   |        |  
|                                          |  | Current AssetsDerivatives                 |  | $                       | 5,732 |  |                              | $ | 1,743 |                  |  | $ |                 |   |  | $ |       |  
|                                          |  | Derivatives and Other Long Term Assets     |  |                         | 1,192 |  |                              |   | 500   |                  |  |   |                 |   |  |   |       |  
|                                          |  | Derivative and other Current Liabilities   |  |                         |      |  |                              |   |      |                  |  |   | (5,800           | ) |  |   | (2,462 | )
|                                          |  | Derivative and other Long Term Liabilities |  |                         |      |  |                              |   |      |                  |  |   | (6,112           | ) |  |   | (559   | )
|                                          |  |                                            |  |                         |       |  |                              |   |       |                  |  |   |                  |   |  |   |        |  
|Total                                     |  |                                            |  | $                       | 6,924 |  |                              | $ | 2,243 |                  |  | $ | (11,912          | ) |  | $ | (3,021 | )
|                                          |  |                                            |  |                         |       |  |                              |   |       |                  |  |   |                  |   |  |   |        |  

The following tables summarize the net gain (loss) on derivative contracts for the years ended December 31, 2011,
2010 and 2009:



|                     |  |                                 |        |   |      |   |        |      |  |   |        |  
|-------------------- |  | ------------------------------- | ------ | - | ---- | - | ------ | ---- |  | - | ------ | -
|                     |  | For the Year Ended December 31, |       
|                     |  | 2011                            |        |   | 2010 |   |        | 2009 | 
|                     |  | (in thousands)                  |       
|Realized gain (loss) |  | $                               | (2,136 | ) |      | $ | 3,877  |      |  | $ | 5,375  |  
|Unrealized loss      |  |                                 | (4,210 | ) |      |   | (3,063 | )    |  |   | (7,700 | )
|                     |  |                                 |        |   |      |   |        |      |  |   |        |  
|Net gain (loss)      |  | $                               | (6,346 | ) |      | $ | 814    |      |  | $ | (2,325 | )

NOTE 6ACQUISITIONS

Triad Hunter

On February 12, 2010, the Company completed the acquisition of
privately-held Triad Energy Corporation and certain of its affiliated entities, collectively referred to as Triad Hunter, an Appalachian Basin focused energy company, through a bankruptcy proceeding (the Triad Acquisition). The Triad
Acquisition was completed to expand the assets and operations of Magnum Hunter in the Appalachia region. We acquired substantially all of the assets of Triad Hunter, which primarily consisted of oil and gas property interests in approximately 2,000
operated wells and included over 87,000 net mineral acres located in the states of Kentucky, Ohio, and West Virginia, a natural gas pipeline (Eureka Hunter Pipeline), two commercial salt water disposal facilities, three drilling rigs, workover rigs,
and other oilfield equipment. These assets are now held by the Companys wholly-owned subsidiaries, Triad Hunter, LLC, Alpha Hunter Drilling, LLC, Hunter Disposal, LLC, Eureka Hunter Pipeline, LLC, and Hunter Real Estate, LLC.



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The acquisition of Triad Hunter 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 fair values of the net assets acquired as of December 31, 2010 (in thousands, except share information):



|                                                                |  |   |        |  
|--------------------------------------------------------------- |  | - | ------ | -
|Fair value of total purchase price:                             |  |   |        |  
|Cash consideration                                              |  | $ | 8,000  |  
|Payment of Triad Hunter senior and other debt                   |  |   | 55,211 |  
|Assumption of equipment indebtedness                            |  |   | 3,412  |  
|Issuance of $15,000,000 stated value Series B Preferred Stock   |  |   | 14,982 |  
|                                                                |  |   |        |  
|Total                                                           |  | $ | 81,605 |  
|                                                                |  |   |        |  
|Amounts recognized for assets acquired and liabilities assumed: |  |   |        |  
|Working capital                                                 |  | $ | 4,195  |  
|Proved oil and gas properties                                   |  |   | 49,708 |  
|Unproved oil and gas properties                                 |  |   | 12,386 |  
|Gas gathering system assets                                     |  |   | 10,000 |  
|Field servicing equipment                                       |  |   | 7,576  |  
|Asset retirement obligation                                     |  |   | (2,260 | )
|                                                                |  |   |        |  
|Total                                                           |  | $ | 81,605 |  
|                                                                |  |   |        |  
|Working capital acquired was as follows:                        |  |   |        |  
|Cash                                                            |  | $ | 3,711  |  
|Accounts receivable                                             |  |   | 2,404  |  
|Prepaid expenses                                                |  |   | 222    |  
|Inventory                                                       |  |   | 685    |  
|Other current assets                                            |  |   | 553    |  
|Accounts payable                                                |  |   | (1,087 | )
|Accrued liabilities                                             |  |   | (365   | )
|Revenue payable                                                 |  |   | (1,928 | )
|                                                                |  |   |        |  
|Total working capital acquired                                  |  | $ | 4,195  |  
|                                                                |  |   |        |  

Because Triad Hunter and certain of its affiliated entities had been operating under Chapter 11 of the Federal
Bankruptcy Code since December 2008, the acquisition agreement did not include customary indemnification provisions, but did contain closing conditions and representations and warranties that are typical for a transaction of this nature.

In connection with the Triad Acquisition and pursuant to the Bankruptcy Order on February 12, 2010, we issued, in the aggregate,
4,000,000 shares of our Series B Preferred Stock with a stated value of $15,000,000. In June 2010, all outstanding shares of Series B Preferred Stock were either converted into shares of common stock of the Company or redeemed by the Company
for cash. See Note 11  Shareholders Equity for additional information.

PostRock

On December 24, 2010, Magnum Hunter Resources Corporation and Triad Hunter, LLC entered into a Purchase and Sale Agreement, pursuant to which Triad
Hunter agreed to purchase certain oil and gas properties and leasehold mineral interests and related assets located in Wetzel and Lewis Counties, West Virginia and certain additional assets. The Purchase Agreement provided for the acquisition
to be completed in two phases. Both phases are effective as of November 1, 2010.



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The first phase of the acquisition closed on December 30, 2010. Total consideration paid in the first
closing was approximately $31.0 million which consisted of 2,255,046 shares of common stock valued at approximately $17.1 million on December 30, 2010 and a cash payment of approximately $13.9 million. See Note 10 Shareholders
Equity for additional information.

On January 14, 2011, we closed the second phase of the PostRock acquisition, which consisted of the
Lewis County assets, for total consideration of approximately $13.3 million which consisted of 946,314 shares of our restricted common stock valued at approximately $7.5 million and a cash payment of approximately $5.8 million.

On June 16, 2011, we closed a third phase of the PostRock acquisition comprising of assets located in Wetzel and Lewis Counties for a
total purchase price of $4.9 million in cash before considering applicable adjustments.

The acquisition of the PostRock assets is accounted
for using the acquisition method as set out in ASC 805, Business Combinations, which requires the net assets acquired to be recorded at their fair values. The fair value of the net assets acquired approximated the $49.3 million in
consideration paid.

Wetzel County, West Virginia Asset Acquisition

On April 7, 2011, the Company purchased oil and gas properties and related assets located in Wetzel County, West Virginia. The assets purchased included approximately 4,451 gross acres (2,225 net
acres) of oil and gas leases and mineral interests and existing wells with proven reserves.

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

On April 13,
2011, the Company completed the acquisition of all of the outstanding common shares of NGAS Resources, Inc, referred to as 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 fair value of the net assets acquired, approximated the $124.5 million in consideration paid or assumed.



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The following table summarizes the purchase price and the fair values of the net assets acquired from NGAS
at the date of acquisition as determined as of December 31, 2011 (in thousands, except 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

On May 3, 2011, the Company completed the acquisition of all of the outstanding common shares of NuLoch Resources, Inc., referred to as 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 fair value of the net assets acquired, based upon our preliminary estimate, approximated the $430.5 million in consideration paid or assumed.



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The following table summarizes the purchase price and the preliminary estimate of the fair values of the net
assets of NuLoch as of the date acquired as determined as of December 31, 2011 (in thousands):



|                                                                           |  |   |         |  
|-------------------------------------------------------------------------- |  | - | ------- | -
|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 | )
|                                                                           |  |   |         |  

The consolidated statement of operations includes Triad Hunters revenue of $21.3 million for the year ended
December 31, 2010 and Triad Hunters operating income of $3.2 million for the year ended December 31, 2010. Amounts attributable to Post Rock in the 2010 consolidated statement of operations were insignificant. The consolidated
statement of operations includes PostRocks revenue of $9.6 million for the year ended December 31, 2011 and PostRocks operating income of $3.2 million for the year ended December 31, 2011. The consolidated statement of
operations includes NGASs revenue of $17.6 million for the year ended December 31, 2011 and NGASs operating loss of $27.7 million for the year ended December 31, 2011. The consolidated statement of operations includes
NuLochs revenue of $18.5 million for the year ended December 31, 2011, and NuLochs operating income of $901 thousand for the year ended December 31, 2011.



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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, 2011, and 2010, as if the acquisitions of Triad Hunter, Post Rock, NGAS and NuLoch along with transactions necessary to finance the acquisitions, had occurred as of the beginning of 2010. 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.



|                                                             |  |                                 |          |   |      |   |         |  
|------------------------------------------------------------ |  | ------------------------------- | -------- | - | ---- | - | ------- | -
|                                                             |  | (in thousands, unaudited)       |         
|                                                             |  | For the Year Ended
December 31, |         
|                                                             |  | 2011                            |          |   | 2010 |  
|Total operating revenue                                      |  | $                               | 145,615  |   |      | $ | 100,506 |  
|Total operating costs and expenses                           |  |                                 | 218,407  |   |      |   | 139,725 |  
|                                                             |  |                                 |          |   |      |   |         |  
|Operating income (loss)                                      |  |                                 | (72,792  | ) |      |   | (39,219 | )
|Interest expense and other                                   |  |                                 | (17,900  | ) |      |   | 1,360   |  
|                                                             |  |                                 |          |   |      |   |         |  
|Net loss attributable to Magnum Hunter Resources Corporation |  |                                 | (90,692  | ) |      |   | (37,859 | )
|Dividends on preferred stock                                 |  |                                 | (14,007  | ) |      |   | (2,664  | )
|                                                             |  |                                 |          |   |      |   |         |  
|Net loss attributable to common stockholders                 |  | $                               | (104,699 | ) |      | $ | (40,523 | )
|                                                             |  |                                 |          |   |      |   |         |  
|Loss per common share, basic and diluted                     |  | $                               | (0.81    | ) |      | $ | (0.31   | )
|                                                             |  |                                 |          |   |      |   |         |  

NOTE 7DISCONTINUED OPERATIONS

On October 29, 2010, the Company entered into a definitive purchase and sale agreement with a subsidiary of Approach Resources,
Inc., referred to as Approach, for the sale to Approach of Magnum Hunters 10.0% non-operated working interest in the Cinco Terry property located in Crockett County, Texas, which closed on October 29, 2010. Total cash consideration of the
sale to Approach was $21.5 million, subject to customary adjustments. We recorded a gain of approximately $6.7 million on the disposal. The proceeds from the sale were used to pay down our revolving credit loan and to fund expenditures under our
capital budget. Our borrowing base under the revolving credit agreement was reduced to $65 million from $75 million, at that time, as a result of the sale. The operating results of the Cinco Terry property for the years ended December 31, 2010
and 2009 have been reclassified as discontinued operations in the consolidated statements of operations as detailed in the table below:



|                                                                  |  |                        |        |   |      |   |        |  
|----------------------------------------------------------------- |  | ---------------------- | ------ | - | ---- | - | ------ | -
|                                                                  |  | Year endedDecember 31, |       
|                                                                  |  | (in thousands)         |       
|                                                                  |  | 2010                   |        |   | 2009 |  
|Oil and Gas Sales and other revenues from discontinued operations |  | $                      | 4,850  |   |      | $ | 3,428  |  
|Operating expenses from discontinued operations                   |  |                        | (2,613 | ) |      |   | (2,338 | )
|Interest expense from discontinued operations                     |  |                        | (378   | ) |      |   | (645   | )
|Gain on sale of discontinued operations                           |  |                        | 6,660  |   |      |   |       |  
|Income tax expense on sale of discontinued operations             |  |                        | (62    | ) |      |   |       |  
|                                                                  |  |                        |        |   |      |   |        |  
|Income from discontinued operations                               |  | $                      | 8,457  |   |      | $ | 445    |  
|                                                                  |  |                        |        |   |      |   |        |  



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##### Table of Contents

NOTE 8ASSET RETIREMENT OBLIGATIONS

The following table summarizes the Companys asset retirement obligation transactions during the years ended December 31:



|                                                   |  |                |        |   |      |   |       |  
|-------------------------------------------------- |  | -------------- | ------ | - | ---- | - | ----- | -
|                                                   |  | (in thousands) |       
|                                                   |  | 2011           |        |   | 2010 |  
|Asset retirement obligation at beginning of period |  | $              | 4,455  |   |      | $ | 2,031 |  
|Assumed in Triad acquisition                       |  |                |       |   |      |   | 2,261 |  
|Assumed in PostRock acquisition                    |  |                |       |   |      |   | 17    |  
|Assumed in NGAS acquisition                        |  |                | 8,678  |   |      |   |      |  
|Assumed in NuLoch acquisition                      |  |                | 1,496  |   |      |   |      |  
|Liabilities incurred                               |  |                | 688    |   |      |   | 46    |  
|Liabilities settled                                |  |                | (14    | ) |      |   | (276  | )
|Accretion expense                                  |  |                | 882    |   |      |   | 376   |  
|Correction of prior year error                     |  |                | 2,660  |   |      |   |      |  
|Revisions in estimated liabilities                 |  |                | 1,766  |   |      |   |      |  
|                                                   |  |                |        |   |      |   |       |  
|Asset retirement obligation at end of period       |  |                | 20,611 |   |      |   | 4,455 |  
|Less: current portion                              |  |                | (495   | ) |      |   |      |  
|                                                   |  |                |        |   |      |   |       |  
|Asset retirement obligation at end of period       |  | $              | 20,116 |   |      | $ | 4,455 |  
|                                                   |  |                |        |   |      |   |       |  

NOTE 9NOTES PAYABLE

Notes payable at December 31, 2011 and 2010 consisted of the following:



|                                                                                                                             |  |                |         |   |      |   |         |  
|---------------------------------------------------------------------------------------------------------------------------- |  | -------------- | ------- | - | ---- | - | ------- | -
|                                                                                                                             |  | (in thousands) |        
|                                                                                                                             |  | 2011           |         |   | 2010 |  
|Various equipment and real estate notes payable with maturity dates April 2012 to August 2021, interest rates of
0.00%6.34% |  | $              | 17,745  |   |      | $ | 3,151   |  
|Eureka Hunter Pipeline, LLC second lien term loan due August 16, 2018, interest rate of 12.5%                                |  |                | 31,000  |   |      |   |        |  
|Second lien term loan due October 13, 2016, interest rate of 8% at December 31, 2011                                         |  |                | 100,000 |   |      |   |        |  
|Senior revolving credit facility due April 13, 2016, interest rate of 3.55% at December 31, 2011                             |  |                | 142,000 |   |      |   |        |  
|Senior revolving credit facility                                                                                             |  |                |         |   |      |   |         |  
|Tranche A at 4.5% due November 23, 2012                                                                                      |  |                |        |   |      |   | 23,500  |  
|Tranche B at 5.5%, due November 30, 2011                                                                                     |  |                |        |   |      |   | 6,500   |  
|                                                                                                                             |  |                |         |   |      |   |         |  
|                                                                                                                             |  | $              | 290,745 |   |      | $ | 33,151  |  
|Less: current portion                                                                                                        |  |                | (4,681  | ) |      |   | (7,132, | )
|                                                                                                                             |  |                |         |   |      |   |         |  
|Total Long-Term Debt                                                                                                         |  | $              | 286,064 |   |      | $ | 26,019  |  
|                                                                                                                             |  |                |         |   |      |   |         |  



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The following table presents the approximate annual maturities of debt:



|           |  |                |         | 
|---------- |  | -------------- | ------- | 
|           |  | (in thousands) |        
|2012       |  | $              | 4,681   | 
|2013       |  |                | 3,185   | 
|2014       |  |                | 1,768   | 
|2015       |  |                | 4,218   | 
|Thereafter |  |                | 276,893 | 
|           |  |                |         | 
|           |  | $              | 290,745 | 
|           |  |                |         | 

Notes Payable

On December 14, 2011, the Company entered into a term note for $3.9 million at an interest rate of 5.5%, due December 31, 2016, for the purchase of equipment.

On October 13, 2011, the Company purchased an office building for $1.7 million and entered into a term note with a financial institution for $1.4
million at an interest rate of 5.7% due on November 30, 2017.

On April 13, 2011 the Company assumed various notes payable for
equipment and a building upon the closing of the acquisition of NGAS. The notes have maturity dates ranging from September 2012 to April 2021 and bear interest rates of 0.00% to 5.875%. As of December 31, 2011, there was $6.0 million
outstanding on these notes.

In connection with the Triad acquisition in February 2010, the Company assumed various notes payable for
equipment which have a principal balance of $6.5 million at December 31, 2011 and are collateralized by the financed equipment.

Credit Facilities

MHR Senior
Revolving Credit Facility.On April 13, 2011, the Company entered into a Second Amended and Restated Credit Agreement, referred to as the MHR Senior Revolving Credit Facility. The MHR Senior Revolving Credit Facility amended and
restated, in its entirety, that certain Amended and Restated Credit Agreement dated February 12, 2010.

The MHR Senior Revolving Credit
Facility provides for an asset-based, senior secured revolving credit facility maturing April 13, 2016. The initial borrowing base was set at $120 million upon the completion of the Companys acquisition of NGAS. The borrowing base was
subsequently increased to $145 million upon the completion of the Companys acquisition of NuLoch, which closed on May 3, 2011. 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 $250 million. The borrowing base is subject to such
periodic redeterminations commencing November 1, 2011. The borrowing base is currently set at $235 million. At December 31, 2011, the Company was not in compliance with the covenant requiring a ratio of consolidated current assets to
consolidated current liabilities of not less than 1.0 to 1.0. The lenders provided the Company with a waiver of that December 31, 2011 covenant violation but the Company is required to meet the quarterly measurements for the covenant throughout
2012, which management believes is probable.

The facility may be used for loans and, subject to a $10,000,000 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 LIBO Rate for a one month interest period on such day plus 1.0%; or (ii) the adjusted LIBO



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##### Table of Contents

Rate, 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 3.25% for adjusted LIBO Rate loans.

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

The MHR Senior Revolving Credit Facility contains negative covenants that,
among other things, restrict the ability of the Company to, with certain exceptions: (1) incur indebtedness; (2) grant liens; (3) make certain restricted payments; (4) change the nature of its business; (5) dispose of its
assets; (6) enter into mergers, consolidations or similar transactions; (7) make investments, loans or advances; (8) pay cash dividends, unless certain conditions are met, and subject to a basket of $20,000,000 per year
available for payment of dividends on preferred stock; and (9) enter into transactions with affiliates. The Second Restated Credit Agreement also requires the Company to satisfy certain financial covenants, including maintaining (1) a
ratio of consolidated current assets to consolidated current liabilities of not less than 1.0 to 1.0 or of not less than 1.05 to 1.00 commencing with the fiscal quarter ending June 30, 2012 if the amounts owed under the Second Lien Credit
Agreement have not been repaid in full as of such date; (2) a ratio of EBITDAX to interest of not less than 2.5 to 1.0; and (3) a ratio of total debt to EBITDAX of not more than (a) 4.25 to 1.0 for the fiscal quarter ending
December 31, 2011 and (b) 4.0 to 1.0 for each fiscal quarter ending thereafter. The Company is also required to enter into certain commodity hedging agreements pursuant to the terms of the facility. At December 31, 2011, the Company
was not in compliance with a covenant under our MHR Senior Revolving Credit Facility requiring a ratio of consolidated current assets to consolidated current liabilities of not less than 1.0 to 1.0. The bank provided the Company with a waiver of
that December 31, 2011 covenant violation but the Company is required to meet the quarterly measurements for the covenant throughout 2012, which management believes is probable.

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 MHR Senior Revolving Credit 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, which liens include those properties acquired through the acquisition of NGAS, and additional liens were granted on the properties acquired upon the closing of the NuLoch acquisition.

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.

MHR Term Loan Facility.On September 28, 2011, the Company entered into a Second Lien Term Loan Credit Agreement, referred to as the
MHR Term Loan Facility 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 MHR Term Loan Facility provides for a term loan credit facility, referred to as
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. Amounts repaid under the Term Loan Facility may not be redrawn in the future.



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Borrowings under the Term Loan Facility will, at the Companys election, bear interest at either:
(i) an ABR equal to the higher of (A) the Prime Rate, (B) the Federal Funds Effective Rate plus 0.5% per annum and (C) the LIBO Rate for a one month interest period in effect on such day plus 1.0%; or (ii) the Adjusted
LIBO Rate, which is the rate stated on Reuters BBA Libor Rates LIBOR01, provided that such amount shall not be less than 1.0% per annum through June 30, 2012 and not less than 2.0% per annum for any period after June 30, 2012;
plus in each of the cases described in clauses (i) and (ii) above, an applicable margin of 6.0% for ABR loans and 7.0% for Adjusted LIBO Rate loans for periods through June 30, 2012 and 7.0% for ABR loans and 8.0% for Adjusted LIBO
Rate loans for periods after June 30, 2012.

Overdue amounts shall bear interest at a rate equal to 2.0% per annum plus the rate
applicable to ABR loans.

The Company may elect to prepay amounts due under the Term Loan Facility without penalty during the first 12 months.
The Company will be subject to a 2.0% penalty of the principal amount being prepaid during the second year of the Term Loan Facility and a 1.0% penalty of the principal amount being prepaid during the third year of the Term Loan Facility. Any
optional prepayments made after the third year of the Term Loan Facility will not be subject to an additional prepayment premium or penalty.

The Company is subject to mandatory prepayments under the Term Loan Facility for certain percentages of the net cash proceeds received as a result of:
(i) future issuances of certain debt securities, including those convertible into the Companys common stock or other equity interests; (ii) sales or other dispositions of the Companys property and assets subject to customary
reinvestment provisions and certain other exceptions; and (iii) future issuances of the Companys equity interests including its common stock, preferred stock and other convertible securities subject to certain exceptions.

The MHR Term Loan 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 $20,000,000 per year available for payment of dividends on preferred stock; and (9) enter into
transactions with affiliates.

The MHR Term Loan Facility also requires the Company to satisfy certain financial covenants, including
maintaining (1) a ratio of current assets to current liabilities of not less than (a) 0.85 to 1.0 for each fiscal quarter ending on or before March 31, 2012 and (b) 1.0 to 1.0 for each fiscal quarter ending thereafter; (2) a
ratio of its Total Reserve Value (as such term is defined in the MHR Term Loan Facility) to total indebtedness under the MHR Senior Revolving Credit Facility and MHR Term Loan Facility of not less than 1.5 to 1.0; (3) a ratio of EBITDAX to
interest expense of not less than 2.125 to 1.0 commencing with the fiscal quarter ending September 30, 2011; and (4) a ratio of total debt to EBITDAX of not more than (a) 5.25 to 1.0 for the fiscal quarter ending September 30,
2011; (b) 5.00 to 1.0 for the fiscal quarter ended December 31, 2011; and (c) 4.75 to 1.0 for each fiscal quarter ending thereafter. The Company was out of compliance with the ratio of current assets to current liabilities covenant at
December 31, 2011, and the bank group permanently waived this covenant violation as described above.

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 MHR Term Loan 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.

The Companys obligations under the MHR Term Loan Facility have been secured by the grant of a second priority lien on
substantially all of the assets of the Company and its restricted subsidiaries, including the oil and gas properties of the Company and its restricted subsidiaries.



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In connection with the MHR Term Loan 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 MHR Term Loan Facility are unconditionally
guaranteed by such restricted subsidiaries.

Eureka Hunter Credit Facilities.On August 16, 2011, Eureka Hunter, a wholly
owned subsidiary of the Company, entered into (i) a First Lien Credit Agreement, referred to as the Eureka Hunter Revolver, by and among Eureka Hunter, 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 Hunter Term Loan, by and among Eureka Hunter, 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 Hunter Revolver and the Eureka Hunter Term Loan being collectively referred to as the Eureka Hunter Credit Facilities).

The Eureka Hunter 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 Hunter. The Eureka Hunter term loan provides for a $50 million term loan, secured by a second lien on substantially all of the assets of Eureka Hunter. 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. On August 16, 2011, Eureka Hunter drew $31 million under the term loan, $21
million of which was distributed to the Company to repay existing corporate indebtedness. Both the revolver and the term loan are non-recourse to Magnum Hunter.

The terms of the Eureka Hunter Revolver 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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 LIBO Rate (as defined in the Eureka Hunter 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 LIBO Rate, plus an applicable margin ranging from 2.25% to 3.25%.
| | - |  | ------------------------------------------------------------------------------

Borrowings under the term loan will bear interest at 9.75% per annum in cash, plus 2.75% (increasing to 3.75% on and at all times when Eureka Hunter
and its subsidiaries incur indebtedness (other than the term loan) in excess of $1,000,000) of which may be paid, at the sole option of Eureka Hunter, in cash or in shares of $0.01 par value, restricted common stock of the Company.

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 Hunter Credit
Facilities contain negative covenants that, among other things, restrict the ability of Eureka Hunter 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.



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The Eureka Hunter Credit Facilities also require Eureka Hunter 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) not less than 1.0 to 1.0 for the fiscal quarter ending
March 31, 2012, to (ii) (A) for the term loan, not less than 2.75 to 1.0 for the fiscal quarter ending December 31, 2014 and thereafter, and (B) for the revolver, not less than 2.75 to 1.0 for the fiscal quarter ending
December 31, 2014 and thereafter or, in the event any portion of the revolver has been drawn, not less than 3.0 to 1.0 for the fiscal quarter ending December 31, 2014;
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | a consolidated total debt to consolidated EBITDA ratio ranging from (i) not greater than 7.0 to 1.0 for the fiscal quarter ending March 31,
2012, to (ii) (A) for the term loan, not greater than 4.25 to 1.0 for the fiscal quarter ending December 31, 2014 and thereafter, and (B) for the revolver, not greater than 4.25 to 1.0 for the fiscal quarter ending
December 31, 2014 and thereafter or, in the event any portion of the revolver has been drawn, not greater than 4.0 to 1.0 for the fiscal quarter ending June 30, 2014; 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 (A) 3.5 to 1.0 for the fiscal quarters ending March 31, 2012 and June 30, 2012, and (B) 3.25 to 1.0 for each fiscal quarter thereafter.
| | - |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

The obligations of Eureka Hunter under both the revolver and the term loan may be accelerated upon the occurrence of an
Event of Default (as such term is defined in each of the credit agreements) under either 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, and defaults by the Company which cause the acceleration of the Companys debt under its existing senior secured revolving credit facility administered by the Bank of Montreal.

In connection with the Eureka Hunter Credit Facilities, (i) Eureka Hunter and its existing subsidiary, entered into customary ancillary
agreements and arrangements, which provide that the obligations of Eureka Hunter under the Eureka Hunter Credit Facilities are secured by substantially all of the assets of Eureka Hunter and such subsidiary, consisting primarily of pipelines,
pipeline rights-of-way, and a gas processing plant, and (ii) Triad Hunter, the sole parent of Eureka Hunter and a wholly owned subsidiary of the Company, entered into customary ancillary agreements and arrangements, which granted the lenders
under the Credit Agreements a non-recourse security interest in Triad Hunters equity interest in Eureka Hunter.

As of December 31,
2011, there was $31.0 million outstanding on the Eureka Hunter Term Loan.

NOTE 10SHARE BASED COMPENSATION

Under the amended and restated 2006 Stock Incentive Plan, our common stock, common stock options, and stock appreciation rights may be
granted to employees and other persons who contribute to the success of Magnum Hunter. Currently, 20,000,000 shares of our common stock are authorized to be issued under the plan, and 2,272,210 shares have been issued as of December 31, 2011.

We recognized share-based compensation expense of $25.1 million, $6.4 million, and $3.1 million for the year ended December 31,
2011, 2010, and 2009 respectively.



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A summary of stock option and stock appreciation rights activity for the year ended December 31, 2011,
2010, and 2009 is presented below:



|                                   |  |        |            |   |                |   |      |        |  |  |                |   |  |        |      |  |                |  |           |   |  |   |      | 
|---------------------------------- |  | ------ | ---------- | - | -------------- | - | ---- | ------ |  |  | -------------- | - |  | ------ | ---- |  | -------------- |  | --------- | - |  | - | ---- | 
|                                   |  | 2011   |            |   | 2010           |   |      | 2009   | 
|                                   |  |        |            |   | Weighted-      |   |      |        |  |  | Weighted-      |   |  |        |      |  | Weighted-      | 
|                                   |  |        |            |   | Average        |   |      |        |  |  | Average        |   |  |        |      |  | Average        | 
|                                   |  | Shares |            |   | Exercise Price |   |      | Shares |  |  | Exercise Price |   |  | Shares |      |  | Exercise Price | 
|Outstanding at beginning of period |  |        | 12,779,282 |   |                | $ | 2.65 |        |  |  | 7,117,000      |   |  | $      | 0.93 |  |                |  | 1,035,000 |   |  | $ | 3.11 | 
|Granted                            |  |        | 5,601,792  |   |                | $ | 7.74 |        |  |  | 5,892,332      |   |  | $      | 4.70 |  |                |  | 6,107,000 |   |  | $ | 0.56 | 
|Exercised                          |  |        | (5,479,250 | ) |                | $ | 0.92 |        |  |  | (52,500        | ) |  | $      | 2.05 |  |                |  |          |   |  | $ |     | 
|Forfeited or expired               |  |        | (335,625   | ) |                | $ | 3.40 |        |  |  | (177,550       | ) |  | $      | 1.36 |  |                |  | (25,000   | ) |  | $ | 2.50 | 
|                                   |  |        |            |   |                |   |      |        |  |  |                |   |  |        |      |  |                |  |           |   |  |   |      | 
|Outstanding at end of period       |  |        | 12,566,199 |   |                | $ | 5.64 |        |  |  | 12,779,282     |   |  | $      | 2.65 |  |                |  | 7,117,000 |   |  | $ | 0.93 | 
|Exercisable at end of the year     |  |        | 6,915,417  |   |                | $ | 4.97 |        |  |  | 7,563,750      |   |  | $      | 1.29 |  |                |  | 4,776,750 |   |  | $ | 0.98 | 
|                                   |  |        |            |   |                |   |      |        |  |  |                |   |  |        |      |  |                |  |           |   |  |   |      | 

A summary of the Companys non-vested options and stock appreciation rights as of December 31, 2011, 2010, and
2009 is presented below:



|                                  |  |      |            |   |      |  |            |      |  |  |            |  
|--------------------------------- |  | ---- | ---------- | - | ---- |  | ---------- | ---- |  |  | ---------- | -
|Non-vested Options                |  | 2011 |            |   | 2010 |  |            | 2009 | 
|Non-vested at beginning of period |  |      | 5,215,532  |   |      |  | 2,340,250  |      |  |  | 432,500    |  
|Granted                           |  |      | 5,601,792  |   |      |  | 5,892,332  |      |  |  | 6,107,000  |  
|Vested                            |  |      | (4,832,417 | ) |      |  | (2,964,500 | )    |  |  | (4,174,250 | )
|Forfeited                         |  |      | (334,125   | ) |      |  | (52,550    | )    |  |  | (25,000    | )
|                                  |  |      |            |   |      |  |            |      |  |  |            |  
|Non-vested at end of period       |  |      | 5,650,782  |   |      |  | 5,215,532  |      |  |  | 2,340,250  |  
|                                  |  |      |            |   |      |  |            |      |  |  |            |  

Total unrecognized compensation cost related to the non-vested options was $9.2 million, $10.4 million, and $816 thousand
as of December 31, 2011, 2010, and 2009, respectively. The cost at December 31, 2011 is expected to be recognized over a weighted-average period of 1.29 years. At December 31, 2011, the aggregate intrinsic value for the outstanding
options was $12.3 million; and the weighted average remaining contract life was 6.12 years.

The assumptions used in the fair value method
calculation for the year ended December 31, 2011, 2010, and 2009 are disclosed in the following table:



|                                                                    |  |                         |  |            |  |            
|------------------------------------------------------------------- |  | ----------------------- |  | ---------- |  | -----------
|                                                                    |  | Year Ended December 31,
|                                                                    |  | 2011(1)                 |  | 2010(1)    |  | 2009(1)    
|Weighted average fair value per option granted during the period(2) |  | 4.28                    |  | 2.65       |  | 0.37       
|Assumptions(3) :                                                    |  |                         |  |            |  |            
|Weighted average stock price volatility                             |  | 64.29%                  |  | 79.32%     |  | 108  263% 
|Weighted average risk free rate of return                           |  | 2.04%                   |  | 1.78%      |  | 1.36 2.53%
|Weighted average expected term                                      |  | 6.36 years              |  | 4.24 years |  | 4.23 years 



|(1) | Our estimated future forfeiture rate is zero.
|--- | ---------------------------------------------

|(2) | Calculated using the Black-Scholes fair value based method for service and performance based grants and the Lattice Model for market based grants.
|--- | --------------------------------------------------------------------------------------------------------------------------------------------------

|(3) | The Company does not pay dividends on our common stock.
|--- | -------------------------------------------------------

During 2011, the Company granted 40,305 fully vested shares of common stock to the Companys board members as payment of annual and meeting fees. During 2011, the Company issued 27,099 of the shares
granted in 2011 and 94,044 previously vested shares.



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A summary of the Companys non-vested common shares granted under the 2006 Stock Incentive Plan as of
December 31, 2011, 2010, and 2009 is presented below:



|                                |  |        |          |   |                               |   |      |        |  |  |                               |   |  |        |      |  |                               |  |            |   |  |   |      | 
|------------------------------- |  | ------ | -------- | - | ----------------------------- | - | ---- | ------ |  |  | ----------------------------- | - |  | ------ | ---- |  | ----------------------------- |  | ---------- | - |  | - | ---- | 
|                                |  | 2011   |          |   | 2010                          |   |      | 2009   | 
|Non-vested Shares               |  | Shares |          |   | WeightedAveragePrice PerShare |   |      | Shares |  |  | WeightedAveragePrice PerShare |   |  | Shares |      |  | WeightedAveragePrice PerShare | 
|Non-vested at beginning of year |  |        | 300,074  |   |                               | $ | 4.43 |        |  |  | 2,310,000                     |   |  | $      | 0.44 |  |                               |  | 215,000    |   |  | $ | 2.04 | 
|Granted                         |  |        | 40,305   |   |                               | $ | 5.45 |        |  |  | 253,930                       |   |  | $      | 5.45 |  |                               |  | 4,168,181  |   |  | $ | 0.33 | 
|Vested                          |  |        | (185,330 | ) |                               | $ | 0.47 |        |  |  | (2,263,856                    | ) |  | $      | 0.47 |  |                               |  | (2,048,181 | ) |  | $ | 0.43 | 
|Forfeited                       |  |        |         |   |                               | $ |     |        |  |  |                              |   |  | $      |     |  |                               |  | (25,000    | ) |  | $ | 2.50 | 
|                                |  |        |          |   |                               |   |      |        |  |  |                               |   |  |        |      |  |                               |  |            |   |  |   |      | 
|Non-vested at end of year       |  |        | 155,049  |   |                               | $ | 4.43 |        |  |  | 300,074                       |   |  | $      | 4.43 |  |                               |  | 2,310,000  |   |  | $ | 0.44 | 
|                                |  |        |          |   |                               |   |      |        |  |  |                               |   |  |        |      |  |                               |  |            |   |  |   |      | 

Total unrecognized compensation cost related to the above non-vested shares amounted to $766 thousand, $1.2 million, and
$197 thousand as of December 31, 2011, 2010, and 2009, respectively. The unrecognized compensation cost at December 31, 2011 is expected to be recognized over a weighted-average period of 1.89 years.

NOTE 11SHAREHOLDERS EQUITY

Common Stock

During
the years ended December 31, 2011, 2010, and 2009, the Company issued 121,143, 2,539,317, and 1,886,200 shares, respectively, of the Companys common stock in correlation with share-based compensation which had fully vested to certain
senior management and officers of Company.

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 have with our sales agent for total new 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 the NYSE Amex 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 October 27, 2010, at the annual stockholders meeting, shareholders approved an amendment to the Companys Certificate of Incorporation that increased the Companys authorized
number of shares of Common Stock to 150,000,000 and approved the Magnum Hunter Resources Corporation Stock Incentive Plan, an amendment and restatement of the Companys 2006 Stock Incentive Plan which included increasing the authorized shares
to be issued under the plan to 15,000,000.

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 acquisition.

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 At the Market sales agreement (ATM) as described above.

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 on the closing of the second phase of the PostRock acquisition.



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On April 13, 2011, the Company issued 6,635,478 shares of common stock valued at approximately $53
million based on a closing stock price of $7.99 as consideration on 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 on the closing of the acquisition of NuLoch.

During the year ended
December 31, 2011, the Company issued 582,127 common shares upon the exchange of exchangeable shares of MHR Exchangeco Corporation, an indirect wholly-owned Canadian subsidiary of the Company which we originally issued as part of the NuLoch
Acquisition.

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 nine months ended September 30, 2011, 582,127 of the exchangeable shares have been exchanged for common
shares of the Company. As of December 31, 2011, 3,693,871 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 have 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 has a term of 3 years and (i) is 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) has 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, is 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, will be exercisable at any time on or after May 17, 2010 and have 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.

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.



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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, 2011, common
stock warrants exercisable for 138,388 shares of the Companys common stock, valued at approximately $190,000 were outstanding. The warrants consisted of 97,780 warrants with an exercise price of $15.13 and 40,608 warrants with an exercise
price of $19.04.

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.

A summary of warrant activity for the years ended December 31, 2011, 2010, and 2009 is presented below:



|                                 |  |        |            |   |                                |   |       |        |  |  |                                |   |  |        |      |  |                                |  |           |  |  |   |      | 
|-------------------------------- |  | ------ | ---------- | - | ------------------------------ | - | ----- | ------ |  |  | ------------------------------ | - |  | ------ | ---- |  | ------------------------------ |  | --------- |  |  | - | ---- | 
|                                 |  | 2011   |            |   | 2010                           |   |       | 2009   | 
|                                 |  | Shares |            |   | Weighted -AverageExercisePrice |   |       | Shares |  |  | Weighted -AverageExercisePrice |   |  | Shares |      |  | Weighted -AverageExercisePrice | 
|Outstanding at beginning of year |  |        | 963,034    |   |                                | $ | 2.91  |        |  |  | 8,577,688                      |   |  | $      | 2.15 |  |                                |  | 6,838,962 |  |  | $ | 2.15 | 
|Granted                          |  |        | 13,391,655 |   |                                | $ | 10.56 |        |  |  |                               |   |  | $      |     |  |                                |  | 1,738,726 |  |  | $ | 2.50 | 
|Exercised, forfeited, or expired |  |        | (828,857   | ) |                                | $ | 2.97  |        |  |  | (7,614,654                     | ) |  | $      | 2.14 |  |                                |  |          |  |  | $ |     | 
|                                 |  |        |            |   |                                |   |       |        |  |  |                                |   |  |        |      |  |                                |  |           |  |  |   |      | 
|Outstanding at end of year       |  |        | 13,525,832 |   |                                | $ | 10.48 |        |  |  | 963,034                        |   |  | $      | 2.91 |  |                                |  | 8,577,688 |  |  | $ | 2.22 | 
|Exercisable at end of year       |  |        | 13,525,832 |   |                                | $ | 10.48 |        |  |  | 963,034                        |   |  | $      | 2.91 |  |                                |  | 6,838,962 |  |  | $ | 2.15 | 

At December 31, 2011, the aggregate intrinsic value for warrants was $388 ,000; and the weighted average remaining
contract life was 1.79 years.

Series B Redeemable Convertible Preferred Stock

In connection with the Triad Acquisition and pursuant to the related Bankruptcy Order on February 12, 2010, we issued in the aggregate 4,000,000 shares of our Series B Preferred Stock, with an
aggregate liquidation preference of $15 million to the secured creditors of the Triad entities as partial consideration for the Triad Acquisition. These holders of Series B Preferred were secured creditors of Triad Hunter in its Chapter 11
bankruptcy proceeding and the Series B Preferred was issued to them in partial satisfaction of their secured claims against Triad Hunter. The Series B Preferred Stock ranked senior to the Companys common stock and to the Companys 10.25%
Series C Cumulative Perpetual Preferred Stock. Pursuant to the Certificate of Designation for the Series B Preferred Stock (the Certificate of Designation), the Series B Preferred Stock was entitled to dividends at a rate of
2.75% per annum payable quarterly (i) in shares of Series B Preferred Stock or (ii) subject to the receipt of any required consent under the Companys senior credit facility, in cash. In addition, the Series B Preferred Stock had
a liquidation preference equal to the greater of (i) $3.75 per share, plus accrued and unpaid dividends, or (ii) the amount payable per share of common stock which the holder of Series B Preferred Stock would have received if such Series B
Preferred Stock had been converted to common shares immediately prior to the liquidation event, plus accrued and unpaid dividends. At any time prior to the twentieth anniversary of the original issuance of Series B Preferred Stock, the holders of
shares of Series B Preferred Stock could convert any or all of their Series B Preferred Stock into shares of the Companys common stock at a conversion ratio of one share of Series B Preferred Stock to one share of common stock, subject to
certain



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adjustments. At any time following the second anniversary of the original issuance of Series B Preferred and prior to the twentieth anniversary of such original issuance, the holders of shares of
Series B Preferred stock could tender their shares for redemption to the Company for a redemption price of $3.75 per Series B share, as adjusted. In addition, the Company could redeem the Series B Preferred Stock at a price of $3.75 per share, plus
accrued and unpaid dividends, (a) at any time following February 12, 2012, or (b) if the average trading price of the Common Stock equaled or exceeded $4.74 per common share, as adjusted, for five consecutive trading days.

In June 2010, the Company redeemed 3,000,000 shares of our Series B Preferred Stock for a cash payment of approximately $11.3 million, and 1,000,000
shares of the Series B Preferred Stock were converted into 1,000,000 shares of our common stock. In June 2010, the Company retired the Series B Preferred Stock.

Series C Cumulative Perpetual 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 $26.00 per share during the first twelve months after December 14, 2009, $25.50 during the second twelve months after December 14, 2009, and $25.00
thereafter, except in certain circumstances when the acquirer is considered a qualifying public company. The Company will pay cumulative dividends 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 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
Cumulative Perpetual Preferred Stock. During the year ended December 31, 2011, the Company paid dividends of $10.2 million to holders of our Series C Cumulative Perpetual Preferred Stock. 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. 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.

Series D Cumulative 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 with a 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 $65.9 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. The
Company pays cumulative dividends 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, 2011, the Company paid dividends of $3.8 million to
holders of our Series D Cumulative Preferred Stock.



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##### Table of Contents

A summary of dividends paid by the Company for the years ended December 31, 2011, 2010, and 2009 is
presented below:



|                                     |  |                |         |   |      |  |        |      |  |  |     |  
|------------------------------------ |  | -------------- | ------- | - | ---- |  | ------ | ---- |  |  | --- | -
|                                     |  | (in thousands) |        
|                                     |  | 2011           |         |   | 2010 |  |        | 2009 | 
|Dividend on Series B Preferred Stock |  |                |        |   |      |  | (131   | )    |  |  |    |  
|Dividend on Series C Preferred Stock |  | $              | (10,248 | ) |      |  | (2,336 | )    |  |  | (26 | )
|Dividend on Series D Preferred Stock |  |                | (3,759  | ) |      |  |       |      |  |  |    |  
|                                     |  |                |         |   |      |  |        |      |  |  |     |  
|Total dividends on Preferred Stock   |  |                | (14,007 | ) |      |  | (2,467 | )    |  |  | (26 | )

Treasury Stock

On February 23, 2010 a total of 761,652 shares of common stock with a carrying value of $1,310,357, which were previously issued as a performance deposit on the Triad acquisition, were returned to
the Company and are now held as treasury shares.

Unearned Common Stock in KSOP

During the year ended December 31, 2010, the Company loaned 153,300 shares of our common stock to the KSOP plan at a total cost of $603,613.

Noncontrolling Interests

In connection with the Williston Basin acquisition in 2008, the Company entered into equity participation agreements with the 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 at this time is majority owned by Magnum Hunter Resources. The equity participation agreements were valued at $3,401,655
and accounted for as a noncontrolling interest in PRC Williston.



|                                               |  |                |       |  |      |   |       |      |  |   |       |  
|---------------------------------------------- |  | -------------- | ----- |  | ---- | - | ----- | ---- |  | - | ----- | -
|                                               |  | (in thousands) |      
|                                               |  | 2011           |       |  | 2010 |   |       | 2009 | 
|Noncontrolling interest at beginning of period |  | $              | 1,450 |  |      | $ | 1,321 |      |  | $ | 1,385 |  
|NGAS Acquisition                               |  |                | 497   |  |      |   |      |      |  |   |      |  
|Income/(Loss) to noncontrolling interest       |  |                | 249   |  |      |   | 129   |      |  |   | (64   | )
|                                               |  |                |       |  |      |   |       |      |  |   |       |  
|Noncontrolling interest at end of period       |  | $              | 2,196 |  |      | $ | 1,450 |      |  | $ | 1,321 |  
|                                               |  |                |       |  |      |   |       |      |  |   |       |  

NOTE 12INCOME TAXES

The total provision benefit for income taxes consists of the following:



|                  |  |                |      |   |      |   |    |      |  |   |   | 
|----------------- |  | -------------- | ---- | - | ---- | - | -- | ---- |  | - | - | 
|                  |  | 2011           |      |   | 2010 |   |    | 2009 | 
|                  |  | (in thousands) |     
|Current           |  |                |      |   |      |   |    |      |  |   |   | 
|State             |  | $              |     |   |      | $ | 63 |      |  | $ |  | 
|Deferred          |  |                |      |   |      |   |    |      |  |   |   | 
|Federal           |  |                | (513 | ) |      |   |   |      |  |   |  | 
|State             |  |                | (60  | ) |      |   |   |      |  |   |  | 
|Foreign           |  |                | (123 | ) |      |   |   |      |  |   |  | 
|                  |  |                |      |   |      |   |    |      |  |   |   | 
|Total tax expense |  | $              | (696 | ) |      | $ | 63 |      |  | $ |  | 
|                  |  |                |      |   |      |   |    |      |  |   |   | 



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##### Table of Contents

At December 31, 2011, we had available for U.S. federal income tax reporting purposes, net operating
loss carryforwards (NOL) for regular tax purposes of approximately $142 million which expires in varying amounts during the tax years 2019 through 2031 and foreign NOL of approximately $49 million which expire during the tax years 2015 through 2031.
We also have approximately $2.5 million of depletion carryover which has no expiration. Approximately $45 million 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 as discussed below. With the exception of the tax benefits related to the NuLoch acquisition, no provision for federal income tax benefit is reflected on the statement of operations for the years ended December 31, 2011, 2010,
and 2009, because we are uncertain as to our ability to utilize our NOL in the future. In May of 2011, we recorded a deferred tax liability in connection with the NuLoch acquisition and have recognized a deferred tax benefit due to the reversal of
timing differences during the year.

The NOL above includes $9 million of deductions for excess stock-based compensation. Excess stock-based
compensation deductions represent stock-based compensation that have generated tax deductions that have not yet resulted in a cash tax benefit because the Company has NOL carryforwards. The Company plans to recognize the federal NOL tax assets
associated with excess stock-based compensation tax deductions only when all other components of the federal NOL tax assets have been fully utilized. If and when the excess stock-based compensation related NOL tax assets are realized, the
benefit will be credited directly to equity. Internal Revenue Code, or I.R.C., Section 382 imposes additional 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. The minimum annual NOL utilization limitation amount is determined by multiplying Companys market capitalization value on the ownership change date by the applicable federal interest rate. The amount of the limitation may, under
certain circumstances, be increased to reflect both recognized and deemed recognized built-in gains that occur, or are deemed to occur, during the five-year period immediately following the ownership change. An ownership change occurred in 2007 that
subjected approximately $13 million of NOL carryforwards to the annual NOL utilization limitations provided for in Section 382 in addition to the limitation on the NOL related to the acquisitions discussed above. However, the annual NOL
utilization limitations applicable to these ownership changes are not expected to have a material impact on our ability to utilize the NOL carryforwards generated in those prior years.

The following is a reconciliation of the reported amount of income tax expense (benefit) for the years ended December 31, 2011, 2010, and 2009 to the amount of income tax expense that would result
from applying domestic federal statutory tax rates to pretax income:



|                                |  |                |         |   |      |   |        |      |  |   |        |  
|------------------------------- |  | -------------- | ------- | - | ---- | - | ------ | ---- |  | - | ------ | -
|                                |  | 2011           |         |   | 2010 |   |        | 2009 | 
|                                |  | (in thousands) |        
|Statutory tax expense (benefit) |  | $              | (26,301 | ) |      | $ | (5,520 | )    |  | $ | (5,741 | )
|State income tax                |  |                | (4,641  | ) |      |   | 63     |      |  |   |       |  
|Effect of foreign tax rates     |  |                | 315     |   |      |   |       |      |  |   |       |  
|Effect of permanent differences |  |                | 419     |   |      |   | 386    |      |  |   | 7      |  
|Change in valuation allowance   |  |                | 29,512  |   |      |   | 5,134  |      |  |   | 5,734  |  
|                                |  |                |         |   |      |   |        |      |  |   |        |  
|Total tax expense (benefit)     |  | $              | (696    | ) |      | $ | 63     |      |  | $ |       |  
|                                |  |                |         |   |      |   |        |      |  |   |        |  



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##### Table of Contents

The components of our deferred income taxes were as follows for the years ended December 31, 2011, 2010
and 2009:



|                                 |  |                |          |   |      |   |         |      |  |   |         |  
|-------------------------------- |  | -------------- | -------- | - | ---- | - | ------- | ---- |  | - | ------- | -
|                                 |  | 2011           |          |   | 2010 |   |         | 2009 | 
|                                 |  | (in thousands) |         
|Deferred tax assets:             |  |                |          |   |      |   |         |      |  |   |         |  
|Net operating loss carryforwards |  | $              | 62,923   |   |      | $ | 21,520  |      |  | $ | 17,084  |  
|Asset retirement obligations     |  |                | 7,475    |   |      |   | 1,691   |      |  |   | 771     |  
|Share based compensation         |  |                | 10,247   |   |      |   | 3,091   |      |  |   | 2,693   |  
|Depletion carry forwards         |  |                | 972      |   |      |   | 972     |      |  |   | 508     |  
|Other foreign tax credits        |  |                | 834      |   |      |   |        |      |  |   |        |  
|Foreign tax credits              |  |                | 25,506   |   |      |   |        |      |  |   |        |  
|Deferred tax liabilities:        |  |                |          |   |      |   |         |      |  |   |         |  
|Property and equipment           |  |                | (111,015 | ) |      |   | (3,685  | )    |  |   | (2,895  | )
|Valuation allowances             |  |                |          |   |      |   |         |      |  |   |         |  
|Foreign tax credits              |  |                | (25,506  | ) |      |   |        |      |  |   |        |  
|Related to acquisitions          |  |                | (15,212  | ) |      |   |        |      |  |   |        |  
|Valuation allowance              |  |                | (51,523  | ) |      |   | (23,589 | )    |  |   | (18,161 | )
|                                 |  |                |          |   |      |   |         |      |  |   |         |  
|Net deferred tax                 |  | $              | (95,299  | ) |      | $ |        |      |  | $ |        |  
|                                 |  |                |          |   |      |   |         |      |  |   |         |  

The tax years 2008-2011 remain open to examination for federal income tax purposes and by the other major taxing
jurisdictions to which we are subject. The tax years 2007-2011 remain open for the Texas Franchise tax.

NOTE 13OTHER INFORMATION

Quarterly Data (Unaudited)

The following tables set forth unaudited summary financial results on a quarterly basis for the two most recent years.



|                                             |  |                |        |   |           |   |         |              |  |   |             |   |  |   |         |   |  |   |         |  
|-------------------------------------------- |  | -------------- | ------ | - | --------- | - | ------- | ------------ |  | - | ----------- | - |  | - | ------- | - |  | - | ------- | -
|                                             |  | (in
thousands) |       
|                                             |  | Quarter Ended  |        |   | TotalYear |  
|                                             |  | March 31       |        |   | June 30   |   |         | September 30 |  |   | December 31 |   | 
|2011                                         |  |                |        |   |           |   |         |              |  |   |             |   |  |   |         |   |  |   |         |  
|Total revenue                                |  | $              | 15,321 |   |           | $ | 33,437  |              |  | $ | 32,439      |   |  | $ | 47,981  |   |  | $ | 129,178 |  
|Loss from operations                         |  |                | (2,529 | ) |           |   | (13,988 | )            |  |   | (13,320     | ) |  |   | (29,553 | ) |  |   | (59,390 | )
|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       | ) |  | $ | (0.46   | ) |  | $ | (0.80   | )
|2010                                         |  |                |        |   |           |   |         |              |  |   |             |   |  |   |         |   |  |   |         |  
|Total revenue                                |  | $              | 6,655  |   |           | $ | 8,402   |              |  | $ | 7,920       |   |  | $ | 9,046   |   |  | $ | 32,724  |  
|Loss from operations                         |  |                | (4,493 | ) |           |   | (6,451  | )            |  |   | (3,394      | ) |  |   | (5,071  | ) |  |   | (19,409 | )
|Net loss attributable to common shareholders |  |                | (4,049 | ) |           |   | (5,994  | )            |  |   | (4,324      | ) |  |   | (1,900  | ) |  |   | (16,267 | )
|Basic and diluted loss per common share      |  | $              | (0.07  | ) |           | $ | (0.10   | )            |  | $ | (0.06       | ) |  | $ | (0.02   | ) |  | $ | (0.25   | )



F-40



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##### Table of Contents

Segment Reporting (Unaudited)

The following tables set forth operating activities by segment for the years ended December 31, 2011, 2010, and 2009 respectively.



|                                                                |  |                                 |         |   |              |   |         |                  |  |   |           |   |  |                  |        |   |                          |   |        |       |  |   |        |   |  |   |         |  
|--------------------------------------------------------------- |  | ------------------------------- | ------- | - | ------------ | - | ------- | ---------------- |  | - | --------- | - |  | ---------------- | ------ | - | ------------------------ | - | ------ | ----- |  | - | ------ | - |  | - | ------- | -
|                                                                |  | December 31, 2011(in thousands) |        
|                                                                |  | CorporateUnallocated            |         |   | U.S.Upstream |   |         | CanadianUpstream |  |   | Midstream |   |  | OilfieldServices |        |   | IntersegmentEliminations |   |        | Total | 
|Oil and gas Sales                                               |  | $                               |        |   |              | $ | 95,535  |                  |  | $ | 10,731    |   |  | $                |       |   |                          | $ |       |       |  | $ |       |   |  | $ | 106,266 |  
|Field operations and other                                      |  |                                 |        |   |              |   | 1,665   |                  |  |   | 36        |   |  |                  | 2,491  |   |                          |   | 22,472 |       |  |   | (3,752 | ) |  |   | 22,912  |  
|                                                                |  |                                 |         |   |              |   |         |                  |  |   |           |   |  |                  |        |   |                          |   |        |       |  |   |        |   |  |   |         |  
|Total revenue                                                   |  |                                 |        |   |              |   | 97,200  |                  |  |   | 10,767    |   |  |                  | 2,491  |   |                          |   | 22,472 |       |  |   | (3,752 | ) |  |   | 129,178 |  
|Lease operating expenses                                        |  |                                 |        |   |              |   | 26,689  |                  |  |   | 1,813     |   |  |                  |       |   |                          |   |       |       |  |   | (1,434 | ) |  |   | 27,068  |  
|Severance taxes and marketing                                   |  |                                 |        |   |              |   | 6,886   |                  |  |   | 588       |   |  |                  |       |   |                          |   |       |       |  |   |       |   |  |   | 7,474   |  
|Exploration                                                     |  |                                 |        |   |              |   | 1,497   |                  |  |   | 40        |   |  |                  |       |   |                          |   |       |       |  |   |       |   |  |   | 1,537   |  
|Field Operations                                                |  |                                 |        |   |              |   | 1,508   |                  |  |   |          |   |  |                  | 373    |   |                          |   | 17,375 |       |  |   | (2,318 | ) |  |   | 16,938  |  
|Impairment of unproved oil & gas properties                     |  |                                 |        |   |              |   |        |                  |  |   |          |   |  |                  |       |   |                          |   |       |       |  |   |       |   |  |   |        |  
|Impairment of proved oil & gas properties                       |  |                                 |        |   |              |   | 22,900  |                  |  |   |          |   |  |                  |       |   |                          |   |       |       |  |   |       |   |  |   | 22,900  |  
|Depreciation, depletion and accretion                           |  |                                 |        |   |              |   | 40,374  |                  |  |   | 6,055     |   |  |                  | 1,789  |   |                          |   | 872    |       |  |   |       |   |  |   | 49,090  |  
|General and administrative                                      |  |                                 | 50,794  |   |              |   | 8,822   |                  |  |   | 1,914     |   |  |                  | 850    |   |                          |   | 1,181  |       |  |   |       |   |  |   | 63,561  |  
|                                                                |  |                                 |         |   |              |   |         |                  |  |   |           |   |  |                  |        |   |                          |   |        |       |  |   |        |   |  |   |         |  
|Total expenses                                                  |  |                                 | 50,794  |   |              |   | 108,676 |                  |  |   | 10,410    |   |  |                  | 3,012  |   |                          |   | 19,428 |       |  |   | (3,752 | ) |  |   | 188,568 |  
|Interest income                                                 |  |                                 | 4       |   |              |   | 15      |                  |  |   | 2,062     |   |  |                  |       |   |                          |   |       |       |  |   | (2,054 | ) |  |   | 27      |  
|Interest expense                                                |  |                                 | (9,879  | ) |              |   | (2,315  | )                |  |   | 13        |   |  |                  | (1,674 | ) |                          |   | (204   | )     |  |   | 2,054  |   |  |   | (12,005 | )
|Gain (loss) on derivative contracts                             |  |                                 | (6,346  | ) |              |   |        |                  |  |   |          |   |  |                  |       |   |                          |   |       |       |  |   |       |   |  |   | (6,346  | )
|Other income and (expense)                                      |  |                                 |        |   |              |   | 611     |                  |  |   | (5        | ) |  |                  |       |   |                          |   |       |       |  |   |       |   |  |   | 606     |  
|                                                                |  |                                 |         |   |              |   |         |                  |  |   |           |   |  |                  |        |   |                          |   |        |       |  |   |        |   |  |   |         |  
|Total other income and expense                                  |  |                                 | (16,221 | ) |              |   | (1,689  | )                |  |   | 2,070     |   |  |                  | (1,674 | ) |                          |   | (204   | )     |  |   |       |   |  |   | (17,718 | )
|Loss from continuing operations before non-controlling interest |  |                                 | (67,015 | ) |              |   | (13,165 | )                |  |   | 2,427     |   |  |                  | (2,195 | ) |                          |   | 2,840  |       |  |   |       |   |  |   | (77,108 | )
|Income tax expense (benefit)                                    |  |                                 |        |   |              |   | (571    | )                |  |   | (125      | ) |  |                  |       |   |                          |   |       |       |  |   |       |   |  |   | (696    | )
|Net (income) loss attributable to non-controlling interest      |  |                                 |        |   |              |   | (249    | )                |  |   |          |   |  |                  |       |   |                          |   |       |       |  |   |       |   |  |   | (249    | )
|                                                                |  |                                 |         |   |              |   |         |                  |  |   |           |   |  |                  |        |   |                          |   |        |       |  |   |        |   |  |   |         |  
|Net loss                                                        |  | $                               | (67,015 | ) |              | $ | (12,843 | )                |  | $ | 2,552     |   |  | $                | (2,195 | ) |                          | $ | 2,840  |       |  | $ |       |   |  | $ | (76,661 | )
|                                                                |  |                                 |         |   |              |   |         |                  |  |   |           |   |  |                  |        |   |                          |   |        |       |  |   |        |   |  |   |         |  



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##### Table of Contents



|                                                                |  |                                 |         |   |              |   |        |                  |  |   |           |  |  |                  |     |  |                          |   |       |       |  |   |        |   |  |   |         |  
|--------------------------------------------------------------- |  | ------------------------------- | ------- | - | ------------ | - | ------ | ---------------- |  | - | --------- |  |  | ---------------- | --- |  | ------------------------ | - | ----- | ----- |  | - | ------ | - |  | - | ------- | -
|                                                                |  | December 31, 2010(in thousands) |        
|                                                                |  | CorporateUnallocated            |         |   | U.S.Upstream |   |        | CanadianUpstream |  |   | Midstream |  |  | OilfieldServices |     |  | IntersegmentEliminations |   |       | Total | 
|Oil and gas Sales                                               |  | $                               |        |   |              | $ | 27,715 |                  |  | $ |          |  |  | $                |    |  |                          | $ |      |       |  | $ |       |   |  | $ | 27,715  |  
|Field operations and other                                      |  |                                 |        |   |              |   | 1,905  |                  |  |   |          |  |  |                  | 414 |  |                          |   | 5,027 |       |  |   | (2,337 | ) |  |   | 5,009   |  
|                                                                |  |                                 |         |   |              |   |        |                  |  |   |           |  |  |                  |     |  |                          |   |       |       |  |   |        |   |  |   |         |  
|Total revenue                                                   |  |                                 |        |   |              |   | 29,620 |                  |  |   |          |  |  |                  | 414 |  |                          |   | 5,027 |       |  |   | (2,337 | ) |  |   | 32,724  |  
|Lease operating expenses                                        |  |                                 |        |   |              |   | 10,399 |                  |  |   |          |  |  |                  |    |  |                          |   |      |       |  |   |       |   |  |   | 10,399  |  
|Severance taxes and marketing                                   |  |                                 |        |   |              |   | 2,305  |                  |  |   |          |  |  |                  |    |  |                          |   |      |       |  |   |       |   |  |   | 2,305   |  
|Exploration                                                     |  |                                 |        |   |              |   | 936    |                  |  |   |          |  |  |                  |    |  |                          |   |      |       |  |   |       |   |  |   | 936     |  
|Field Operations                                                |  |                                 |        |   |              |   | 2,213  |                  |  |   |          |  |  |                  | 214 |  |                          |   | 4,273 |       |  |   | (2,337 | ) |  |   | 4,363   |  
|Impairment of proved oil & gas properties                       |  |                                 |        |   |              |   | 306    |                  |  |   |          |  |  |                  |    |  |                          |   |      |       |  |   |       |   |  |   | 306     |  
|Depreciation, depletion and accretion                           |  |                                 |        |   |              |   | 8,347  |                  |  |   |          |  |  |                  | 45  |  |                          |   | 531   |       |  |   |       |   |  |   | 8,923   |  
|General and administrative                                      |  |                                 | 22,835  |   |              |   | 1,798  |                  |  |   |          |  |  |                  | 71  |  |                          |   | 197   |       |  |   |       |   |  |   | 24,901  |  
|                                                                |  |                                 |         |   |              |   |        |                  |  |   |           |  |  |                  |     |  |                          |   |       |       |  |   |        |   |  |   |         |  
|Total expenses                                                  |  |                                 | 22,835  |   |              |   | 26,304 |                  |  |   |          |  |  |                  | 330 |  |                          |   | 5,001 |       |  |   | (2,337 | ) |  |   | 52,133  |  
|Interest income                                                 |  |                                 | 41      |   |              |   | 20     |                  |  |   |          |  |  |                  |    |  |                          |   |      |       |  |   |       |   |  |   | 61      |  
|Interest expense                                                |  |                                 | (3,412  | ) |              |   | (23    | )                |  |   |          |  |  |                  |    |  |                          |   | (159  | )     |  |   |       |   |  |   | (3,594  | )
|Gain (loss) on derivative contracts                             |  |                                 | 820     |   |              |   | (6     | )                |  |   |          |  |  |                  |    |  |                          |   |      |       |  |   |       |   |  |   | 814     |  
|                                                                |  |                                 |         |   |              |   |        |                  |  |   |           |  |  |                  |     |  |                          |   |       |       |  |   |        |   |  |   |         |  
|Total other income and expense                                  |  |                                 | (2,551  | ) |              |   | (9     | )                |  |   |          |  |  |                  |    |  |                          |   | (159  | )     |  |   |       |   |  |   | (2,719  | )
|Loss from continuing operations before non-controlling interest |  |                                 | (25,386 | ) |              |   | 3,307  |                  |  |   |          |  |  |                  | 84  |  |                          |   | (133  | )     |  |   |       |   |  |   | (22,128 | )
|Net (income) loss attributable to non-controlling interest      |  |                                 |        |   |              |   | (129   | )                |  |   |          |  |  |                  |    |  |                          |   |      |       |  |   |       |   |  |   | (129    | )
|                                                                |  |                                 |         |   |              |   |        |                  |  |   |           |  |  |                  |     |  |                          |   |       |       |  |   |        |   |  |   |         |  
|Net income (loss) from continuing operations                    |  |                                 | (25,386 | ) |              |   | 3,178  |                  |  |   |          |  |  |                  | 84  |  |                          |   | (133  | )     |  |   |       |   |  |   | (22,257 | )
|Income from discontinued operations                             |  |                                 |        |   |              |   | 8,457  |                  |  |   |          |  |  |                  |    |  |                          |   |      |       |  |   |       |   |  |   | 8,457   |  
|                                                                |  |                                 |         |   |              |   |        |                  |  |   |           |  |  |                  |     |  |                          |   |       |       |  |   |        |   |  |   |         |  
|Net loss                                                        |  | $                               | (25,386 | ) |              | $ | 11,635 |                  |  | $ |          |  |  | $                | 84  |  |                          | $ | (133  | )     |  | $ |       |   |  | $ | (13,800 | )
|                                                                |  |                                 |         |   |              |   |        |                  |  |   |           |  |  |                  |     |  |                          |   |       |       |  |   |        |   |  |   |         |  



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|                                                                |  |                                 |         |   |              |   |        |                  |  |   |           |  |  |                  |   |  |                          |   |   |       |  |   |   |  |  |   |         |  
|--------------------------------------------------------------- |  | ------------------------------- | ------- | - | ------------ | - | ------ | ---------------- |  | - | --------- |  |  | ---------------- | - |  | ------------------------ | - | - | ----- |  | - | - |  |  | - | ------- | -
|                                                                |  | December 31, 2009(in thousands) |        
|                                                                |  | CorporateUnallocated            |         |   | U.S.Upstream |   |        | CanadianUpstream |  |   | Midstream |  |  | OilfieldServices |   |  | IntersegmentEliminations |   |   | Total | 
|Oil and gas Sales                                               |  | $                               |        |   |              | $ | 6,607  |                  |  | $ |          |  |  | $                |  |  |                          | $ |  |       |  | $ |  |  |  | $ | 6,607   |  
|Field operations and other                                      |  |                                 |        |   |              |   | 237    |                  |  |   |          |  |  |                  |  |  |                          |   |  |       |  |   |  |  |  |   | 237     |  
|                                                                |  |                                 |         |   |              |   |        |                  |  |   |           |  |  |                  |   |  |                          |   |   |       |  |   |   |  |  |   |         |  
|Total revenue                                                   |  |                                 |        |   |              |   | 6,844  |                  |  |   |          |  |  |                  |  |  |                          |   |  |       |  |   |  |  |  |   | 6,844   |  
|Lease operating expenses                                        |  |                                 |        |   |              |   | 3,879  |                  |  |   |          |  |  |                  |  |  |                          |   |  |       |  |   |  |  |  |   | 3,879   |  
|Severance taxes and marketing                                   |  |                                 |        |   |              |   | 500    |                  |  |   |          |  |  |                  |  |  |                          |   |  |       |  |   |  |  |  |   | 500     |  
|Exploration                                                     |  |                                 |        |   |              |   | 790    |                  |  |   |          |  |  |                  |  |  |                          |   |  |       |  |   |  |  |  |   | 790     |  
|Impairment of proved oil & gas properties                       |  |                                 |        |   |              |   | 634    |                  |  |   |          |  |  |                  |  |  |                          |   |  |       |  |   |  |  |  |   | 634     |  
|Depreciation, depletion and accretion                           |  |                                 |        |   |              |   | 3,168  |                  |  |   |          |  |  |                  |  |  |                          |   |  |       |  |   |  |  |  |   | 3,168   |  
|General and administrative                                      |  |                                 | 8,485   |   |              |   | 5      |                  |  |   |          |  |  |                  |  |  |                          |   |  |       |  |   |  |  |  |   | 8,490   |  
|                                                                |  |                                 |         |   |              |   |        |                  |  |   |           |  |  |                  |   |  |                          |   |   |       |  |   |   |  |  |   |         |  
|Total expenses                                                  |  |                                 | 8,485   |   |              |   | 8,976  |                  |  |   |          |  |  |                  |  |  |                          |   |  |       |  |   |  |  |  |   | 17,461  |  
|Interest income                                                 |  |                                 | 1       |   |              |   |       |                  |  |   |          |  |  |                  |  |  |                          |   |  |       |  |   |  |  |  |   | 1       |  
|Interest expense                                                |  |                                 | (3,336  | ) |              |   | 645    |                  |  |   |          |  |  |                  |  |  |                          |   |  |       |  |   |  |  |  |   | (2,691  | )
|Gain (loss) on derivative contracts                             |  |                                 | (2,061  | ) |              |   | (264   | )                |  |   |          |  |  |                  |  |  |                          |   |  |       |  |   |  |  |  |   | (2,325  | )
|                                                                |  |                                 |         |   |              |   |        |                  |  |   |           |  |  |                  |   |  |                          |   |   |       |  |   |   |  |  |   |         |  
|Total other income and expense                                  |  |                                 | (5,396  | ) |              |   | 381    |                  |  |   |          |  |  |                  |  |  |                          |   |  |       |  |   |  |  |  |   | (5,015  | )
|Loss from continuing operations before non-controlling interest |  |                                 | (13,881 | ) |              |   | (1,751 | )                |  |   |          |  |  |                  |  |  |                          |   |  |       |  |   |  |  |  |   | (15,632 | )
|Net (income) loss attributable to non-controlling interest      |  |                                 |        |   |              |   | 63     |                  |  |   |          |  |  |                  |  |  |                          |   |  |       |  |   |  |  |  |   | 63      |  
|                                                                |  |                                 |         |   |              |   |        |                  |  |   |           |  |  |                  |   |  |                          |   |   |       |  |   |   |  |  |   |         |  
|Net income (loss) from continuing operations                    |  |                                 | (13,881 | ) |              |   | (1,688 | )                |  |   |          |  |  |                  |  |  |                          |   |  |       |  |   |  |  |  |   | (15,569 | )
|Income from discontinued operations                             |  |                                 |        |   |              |   | 445    |                  |  |   |          |  |  |                  |  |  |                          |   |  |       |  |   |  |  |  |   | 445     |  
|                                                                |  |                                 |         |   |              |   |        |                  |  |   |           |  |  |                  |   |  |                          |   |   |       |  |   |   |  |  |   |         |  
|Net loss                                                        |  | $                               | (13,881 | ) |              | $ | (1,243 | )                |  | $ |          |  |  | $                |  |  |                          | $ |  |       |  | $ |  |  |  | $ | (15,124 | )
|                                                                |  |                                 |         |   |              |   |        |                  |  |   |           |  |  |                  |   |  |                          |   |   |       |  |   |   |  |  |   |         |  

The Oilfield Services, Midstream, and Upstream functions best define the operating segments of 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 and natural gas.
The Company has significant operations both in the United States and in Canada in the Upstream segment. The Oilfield Services segment is organized and operates to sell services to third party producers of crude oil and natural gas. The Midstream
segment operates a network of pipelines that gathers natural gas. These segments are broadly understood across the petroleum and petrochemical industries.

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 operating decision maker to make decisions about resources to be allocated to the segment and assess its performance; and (3) for which discrete
financial information is available.



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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) |        
|                                 |  | 2011           |         |  | 2010 |   |         | 2009 | 
|Purchase of non-producing leases |  | $              | 412,099 |  |      | $ | 46,683  |      |  | $ | 2,603  | 
|Purchase of producing properties |  |                | 204,511 |  |      |   | 53,116  |      |  |   | 3,288  | 
|Exploration costs                |  |                | 189,535 |  |      |   | 43,466  |      |  |   | 3,794  | 
|Development costs                |  |                | 24,740  |  |      |   | 13,641  |      |  |   | 6,798  | 
|Asset retirement obligation      |  |                | 12,843  |  |      |   | 2,171   |      |  |   | 278    | 
|                                 |  |                |         |  |      |   |         |      |  |   |        | 
|                                 |  | $              | 843,728 |  |      | $ | 159,077 |      |  | $ | 16,760 | 
|                                 |  |                |         |  |      |   |         |      |  |   |        | 

Oil and Gas Reserve Information

Proved oil and gas reserve quantities are based on estimates prepared by Cawley, Gillespie & Associates, Inc. and AJM, Magnum Hunters third party reservoir engineering firms. There are
numerous uncertainties inherent in estimating quantities of proved reserves and projecting future rates of production and timing of development expenditures. The following reserve data only represent estimates and should not be construed as being
exact.

Total Proved Reserves



|                                             |  |                          |        |   |             |  |         |  
|-------------------------------------------- |  | ------------------------ | ------ | - | ----------- |  | ------- | -
|                                             |  | Crude oil and Condensate |        |   | Natural Gas | 
|                                             |  | (mbbl)                   |        |   | (mcf)       | 
|Balance December 31, 2008                    |  |                          | 2,410  |   |             |  | 4,253   |  
|Extensions, discoveries and other additions  |  |                          | 982    |   |             |  | 2,087   |  
|Revisions of previous estimates              |  |                          | 1,330  |   |             |  | 34      |  
|Purchases of reserves in place               |  |                          | 84     |   |             |  | 3,468   |  
|Sales of reserves in place                   |  |                          | (16    | ) |             |  | (20     | )
|Production                                   |  |                          | (180   | ) |             |  | (458    | )
|                                             |  |                          |        |   |             |  |         |  
|Balance December 31, 2009                    |  |                          | 4,609  |   |             |  | 9,364   |  
|Revisions of previous estimates              |  |                          | (112   | ) |             |  | 541     |  
|Purchase of reserves                         |  |                          | 3,328  |   |             |  | 22,250  |  
|Extensions, discoveries, and other additions |  |                          | 890    |   |             |  | 13,822  |  
|Sale of reserves                             |  |                          | (1,507 | ) |             |  | (5,298  | )
|Production                                   |  |                          | (384   | ) |             |  | (1,227  | )
|                                             |  |                          |        |   |             |  |         |  
|Balance December 31, 2010                    |  |                          | 6,824  |   |             |  | 39,452  |  
|Revisions of previous estimates              |  |                          | 6,937  |   |             |  | 40,495  |  
|Purchase of reserves                         |  |                          | 6,345  |   |             |  | 43,757  |  
|Extensions, discoveries, and other additions |  |                          | 2,687  |   |             |  | 22,399  |  
|Sale of reserves                             |  |                          | (215   | ) |             |  | (11     | )
|Production                                   |  |                          | (869   | ) |             |  | (6,855  | )
|                                             |  |                          |        |   |             |  |         |  
|Balance December 31, 2011                    |  |                          | 21,709 |   |             |  | 139,237 |  
|                                             |  |                          |        |   |             |  |         |  
|Developed reserves, included above           |  |                          |        |   |             |  |         |  
|December 31, 2009                            |  |                          | 2,055  |   |             |  | 4,953   |  
|December 31, 2010                            |  |                          | 3,720  |   |             |  | 18,888  |  
|December 31, 2011                            |  |                          | 9,179  |   |             |  | 90,198  |  



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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 then current provisions of ASC 932 and SFAS 69. Future cash inflows at December 31, 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, 2011, 2010, and 2009 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 carryforwards 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.

The standardized measure of discounted
future net cash flows relating to proved oil and natural gas reserves are as follows:



|                                                         |  |                          |           |   |      |   |          |      |  |   |         |  
|-------------------------------------------------------- |  | ------------------------ | --------- | - | ---- | - | -------- | ---- |  | - | ------- | -
|                                                         |  | (in thousands)           |          
|                                                         |  | Years Ended December 31, |          
|                                                         |  | 2011                     |           |   | 2010 |   |          | 2009 | 
|Future cash inflows                                      |  | $                        | 2,409,249 |   |      | $ | 709,788  |      |  | $ | 262,758 |  
|Future production costs                                  |  |                          | (765,048  | ) |      |   | (253,544 | )    |  |   | (93,078 | )
|Future development costs                                 |  |                          | (330,007  | ) |      |   | (77,216  | )    |  |   | (33,245 | )
|Future income tax expense                                |  |                          | (253,721  | ) |      |   | (88,233  | )    |  |   | (30,858 | )
|Future net cash flows                                    |  |                          | 1,060,473 |   |      |   | 290,795  |      |  |   | 105,577 |  
|10% annual discount for estimated timing of cash flows   |  |                          | (586,077  | ) |      |   | (162,836 | )    |  |   | (58,189 | )
|                                                         |  |                          |           |   |      |   |          |      |  |   |         |  
|Standardized measure of discounted future net cash flows |  | $                        | 474,396   |   |      | $ | 127,959  |      |  | $ | 47,388  |  
|                                                         |  |                          |           |   |      |   |          |      |  |   |         |  

Future cash flows as shown above were reported without consideration for the effects of commodity derivative transactions
outstanding at each period end.



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Changes in Standardized Measure of Discounted Future Net Cash Flows

The changes in the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves are as follows:



|                                                                                                       |  |                         |          |   |      |  |         |      |  |  |         |  
|------------------------------------------------------------------------------------------------------ |  | ----------------------- | -------- | - | ---- |  | ------- | ---- |  |  | ------- | -
|                                                                                                       |  | (in thousands)          |         
|                                                                                                       |  | Year Ended December 31, |         
|                                                                                                       |  | 2011                    |          |   | 2010 |  |         | 2009 | 
|Balance, beginning of period                                                                           |  |                         | 127,959  |   |      |  | 47,388  |      |  |  | 15,621  |  
|Net change in sales and transfer prices and in production (lifting) costs related to future production |  |                         | 49,498   |   |      |  | 17,133  |      |  |  | 12,387  |  
|Changes in estimated future development costs                                                          |  |                         | (167,399 | ) |      |  | (50,950 | )    |  |  | (18,755 | )
|Sales and transfers of oil and gas produced during the period                                          |  |                         | (71,724  | ) |      |  | (19,054 | )    |  |  | (4,757  | )
|Net change due to extensions, discoveries and improved recovery                                        |  |                         | 110,316  |   |      |  | 51,022  |      |  |  | 17,578  |  
|Net change due to revisions in quantity estimates                                                      |  |                         | 235,163  |   |      |  | (355    | )    |  |  | 17,654  |  
|Previously estimated development costs incurred during the period                                      |  |                         | 24,740   |   |      |  | 25,020  |      |  |  | 6,798   |  
|Accretion of discount                                                                                  |  |                         | 27,029   |   |      |  | 2,740   |      |  |  | 2,614   |  
|Purchase of minerals in place                                                                          |  |                         | 234,336  |   |      |  | 112,406 |      |  |  | 8,739   |  
|Sale of minerals in place                                                                              |  |                         | (3,726   | ) |      |  | (23,837 | )    |  |  | (262    | )
|Other                                                                                                  |  |                         | 823      |   |      |  | (1,863  | )    |  |  | (3,606  | )
|Net change in income taxes                                                                             |  |                         | (92,620  | ) |      |  | (31,691 | )    |  |  | (6,623  | )
|                                                                                                       |  |                         |          |   |      |  |         |      |  |  |         |  
|Standardized measure of discounted future net cash flows                                               |  |                         | 474,396  |   |      |  | 127,959 |      |  |  | 47,388  |  
|                                                                                                       |  |                         |          |   |      |  |         |      |  |  |         |  

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.



|                              |  |      |       |  |      |   |       |      |  |   |       | 
|----------------------------- |  | ---- | ----- |  | ---- | - | ----- | ---- |  | - | ----- | 
|                              |  | 2011 |       |  | 2010 |   |       | 2009 | 
|Oil (per bbl)                 |  | $    | 96.19 |  |      | $ | 79.43 |      |  | $ | 54.96 | 
|Natural gas liquids (per bbl) |  | $    | 44.25 |  |      | $ |      |      |  | $ | 27.20 | 
|Gas (per mcf)                 |  | $    | 4.11  |  |      | $ | 4.37  |      |  | $ | 3.35  | 

NOTE 14  RELATED PARTY TRANSACTIONS

During 2011, 2010, and 2009, 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 $463,000, $450,000, and $161,000, for the year ended December 31, 2011, 2010, and 2009, respectively.

During 2011, 2010, and 2009, we obtained accounting services and use of office space from GreenHunter Energy, Inc., an entity for which Mr. Evans is an officer and major shareholder and for which
Ronald Ormand, our Chief Financial Officer and a director, is also a director. Professional services expenses totaled $162,000, $212,000, and $30,000 for the year ended December 31, 2011, 2010, and 2009, respectively. All accounting services
are now managed entirely by Magnum Hunter employees.

We entered into a one year 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 year ended December 31, 2011, the Company paid rent of $36,000 pertaining to the lease.

During the year ended December 31, 2011, Eagle Ford Hunter, Triad Hunter and Hunter Disposal, LLC, wholly owned subsidiaries of the Company, rented storage tanks for disposal water and equipment from
GreenHunter Energy, Inc. Rental costs totaled $1.3 million, $0 and $0 for the years ended December 31, 2011, 2010 and 2009, respectively. Terms for the storage rental are comparable to those that could be obtained from third parties in the
marketplace.



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As of December 31, 2011, our net accounts payable to GreenHunter Energy, Inc. was $70,000.

On October 13, 2011, the Company purchased an office building for $1.7 million from GreenHunter Energy, 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, a portion of which note 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 described above.

On February 17, 2012, the Company divested its
wholly-owned subsidiary, Hunter Disposal, LLC, to GreenHunter Water, LLC, a wholly-owned subsidiary of GreenHunter Energy, Inc. See Note 17  Subsequent Events, for more information.

NOTE 15  COMMITMENTS AND CONTINGENCIES

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 $1,353,000 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 $1,353,000. 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, 2011 and 2010 was $640,695.

Operational Contingencies

The exploration, development and production of oil and gas assets are subject to various, federal and state laws and regulations designed
to protect the environment. Compliance with these regulations is part of our day-to-day operating procedures. Infrequently, accidental discharge of such materials as oil, natural gas or drilling fluids can occur and such accidents can require
material expenditures to correct. We maintain levels of insurance we believe to be customary in the industry to limit its financial exposure. We are unaware of any material capital expenditures required for environmental control during this fiscal
year.

Leases

As of
December 31, 2011, we rent various office spaces in Houston, Texas, that total approximately 22,966 square feet at a cost of $37,925 per month for the remaining terms ranging from two to fifty-two months. Triad Hunter had various lease
commitments for periods ranging from three to seventy-four months at December 31, 2011, and with monthly payments of approximately $29,518 as of that date. Williston Hunter has office spaces in Calgary, Alberta and Denver, Colorado that have a
combined monthly payment of $31,517.

Drilling Contract

On June 24, 2011, the Company entered into a forty month drilling contract from July 1, 2011, through October 31, 2014. Our remaining maximum liability under the drilling contract, which
would apply if we terminated the contract before the end of its term, was approximately $16.6 million as of December 31, 2011.

Employment Agreements

We have
outstanding employment agreements with three of our senior and executive officers for terms ranging from four to nine months. Our maximum commitment under the employment agreements, which would apply if the employees covered by these agreements were
all terminated without cause, was approximately $963,000 at December 31, 2011.



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NOTE 16  CONDENSED CONSOLIDATING GUARANTOR FINANCIAL STATEMENTS

The Company and its wholly-owned subsidiaries, except Alpha Hunter Drilling, LLC, Eureka Hunter, LLC, and Hunter Real Estate, LLC, and
its majority owned subsidiary, PRC Williston, LLC referred to collectively as Non Guarantor Subsidiaries, may fully and unconditionally guarantee the obligations of the Company under any debt securities that it may issue pursuant to a universal
shelf registration statement, on a joint and several basis, on Form S-3. Condensed consolidating financial information for Magnum Hunter Resources Corporation and subsidiaries as of December 31, 2011 and December 31, 2010, and
for the years ended December 31, 2011, 2010, and 2009 was as follows:

Magnum Hunter Resources Corporation and
Subsidiaries Condensed Consolidating Balance Sheets

(in thousands)



|                                                             |  |                                   |         |  |                       |   |         |                           |  |   |              |   |  |                                               |          |   |  |   |           | 
|------------------------------------------------------------ |  | --------------------------------- | ------- |  | --------------------- | - | ------- | ------------------------- |  | - | ------------ | - |  | --------------------------------------------- | -------- | - |  | - | --------- | 
|                                                             |  | As of December 31, 2011           |        
|                                                             |  | Magnum HunterResourcesCorporation |         |  | GuarantorSubsidiaries |   |         | Non GuarantorSubsidiaries |  |   | Eliminations |   |  | Magnum HunterResourcesCorporationConsolidated |         
|ASSETS                                                       |  |                                   |         |  |                       |   |         |                           |  |   |              |   |  |                                               |          |   |  |   |           | 
|Current assets                                               |  | $                                 | 25,402  |  |                       | $ | 39,570  |                           |  | $ | 12,341       |   |  | $                                             |         |   |  | $ | 77,313    | 
|Intercompany accounts receivable                             |  |                                   | 602,773 |  |                       |   |        |                           |  |   |             |   |  |                                               | (602,773 | ) |  |   |          | 
|Property and equipment (using successful efforts accounting) |  |                                   | 13,287  |  |                       |   | 727,661 |                           |  |   | 337,558      |   |  |                                               |         |   |  |   | 1,078,506 | 
|Investment in subsidiaries                                   |  |                                   | 244,500 |  |                       |   |        |                           |  |   | 126,655      |   |  |                                               | (371,155 | ) |  |   |          | 
|Other assets                                                 |  |                                   | 9,151   |  |                       |   | 467     |                           |  |   | 2,967        |   |  |                                               |         |   |  |   | 12,585    | 
|                                                             |  |                                   |         |  |                       |   |         |                           |  |   |              |   |  |                                               |          |   |  |   |           | 
|Total Assets                                                 |  | $                                 | 895,113 |  |                       | $ | 767,698 |                           |  | $ | 479,521      |   |  | $                                             | (973,928 | ) |  | $ | 1,168,404 | 
|                                                             |  |                                   |         |  |                       |   |         |                           |  |   |              |   |  |                                               |          |   |  |   |           | 
|LIABILITIES AND STOCKHOLDERS EQUITY                         |  |                                   |         |  |                       |   |         |                           |  |   |              |   |  |                                               |          |   |  |   |           | 
|Current liabilities                                          |  | $                                 | 21,112  |  |                       | $ | 114,105 |                           |  | $ | 32,102       |   |  | $                                             |         |   |  | $ | 167,319   | 
|Intercompany accounts payable                                |  |                                   |        |  |                       |   | 241,339 |                           |  |   | 361,434      |   |  |                                               | (602,773 | ) |  |   |          | 
|Long-term liabilities                                        |  |                                   | 253,319 |  |                       |   | 93,925  |                           |  |   | 63,189       |   |  |                                               |         |   |  |   | 410,433   | 
|Redeemable preferred stock                                   |  |                                   | 100,000 |  |                       |   |        |                           |  |   |             |   |  |                                               |         |   |  |   | 100,000   | 
|Shareholders equity                                         |  |                                   | 520,682 |  |                       |   | 318,329 |                           |  |   | 22,796       |   |  |                                               | (371,155 | ) |  |   | 490,652   | 
|                                                             |  |                                   |         |  |                       |   |         |                           |  |   |              |   |  |                                               |          |   |  |   |           | 
|Total Liabilities and Stockholders Equity                   |  | $                                 | 895,113 |  |                       | $ | 767,698 |                           |  | $ | 479,521      |   |  | $                                             | (973,928 | ) |  | $ | 1,168,404 | 
|                                                             |  |                                   |         |  |                       |   |         |                           |  |   |              |   |  |                                               |          |   |  |   |           | 
|                                                             | 
|                                                             |  | As of December 31, 2010           |        
|                                                             |  | Magnum HunterResourcesCorporation |         |  | GuarantorSubsidiaries |   |         | Non GuarantorSubsidiaries |  |   | Eliminations |   |  | Magnum HunterResourcesCorporationConsolidated |         
|ASSETS                                                       |  |                                   |         |  |                       |   |         |                           |  |   |              |   |  |                                               |          |   |  |   |           | 
|Current assets                                               |  | $                                 | 4,809   |  |                       | $ | 6,436   |                           |  | $ | 1,881        |   |  | $                                             |         |   |  | $ | 13,126    | 
|Intercompany accounts receivable                             |  |                                   | 131,691 |  |                       |   |        |                           |  |   |             |   |  |                                               | (131,691 | ) |  |   |          | 
|Property and equipment (using successful efforts accounting) |  |                                   | 12,049  |  |                       |   | 149,647 |                           |  |   | 70,904       |   |  |                                               |         |   |  |   | 232,601   | 
|Investment in subsidiaries                                   |  |                                   | 80,877  |  |                       |   |        |                           |  |   |             |   |  |                                               | (80,877  | ) |  |   |          | 
|Other assets                                                 |  |                                   | 2,724   |  |                       |   | 512     |                           |  |   | 5            |   |  |                                               |         |   |  |   | 3,240     | 
|                                                             |  |                                   |         |  |                       |   |         |                           |  |   |              |   |  |                                               |          |   |  |   |           | 
|Total Assets                                                 |  | $                                 | 232,150 |  |                       | $ | 156,595 |                           |  | $ | 72,790       |   |  | $                                             | (212,568 | ) |  | $ | 248,967   | 
|                                                             |  |                                   |         |  |                       |   |         |                           |  |   |              |   |  |                                               |          |   |  |   |           | 
|LIABILITIES AND STOCKHOLDERS EQUITY                         |  |                                   |         |  |                       |   |         |                           |  |   |              |   |  |                                               |          |   |  |   |           | 
|Current liabilities                                          |  | $                                 | 24,853  |  |                       | $ | 13,480  |                           |  | $ | 5,902        |   |  | $                                             |         |   |  | $ | 44,235    | 
|Intercompany accounts payable                                |  |                                   |        |  |                       |   | 56,326  |                           |  |   | 75,365       |   |  |                                               | (131,691 | ) |  |   |          | 
|Long-term liabilities                                        |  |                                   | 24,386  |  |                       |   | 3,023   |                           |  |   | 3,765        |   |  |                                               |         |   |  |   | 31,174    | 
|Redeemable preferred stock                                   |  |                                   | 70,236  |  |                       |   |        |                           |  |   |             |   |  |                                               |         |   |  |   | 70,236    | 
|Shareholders equity                                         |  |                                   | 112,675 |  |                       |   | 83,766  |                           |  |   | (12,242      | ) |  |                                               | (80,877  | ) |  |   | 103,322   | 
|                                                             |  |                                   |         |  |                       |   |         |                           |  |   |              |   |  |                                               |          |   |  |   |           | 
|Total Liabilities and Stockholders Equity                   |  | $                                 | 232,150 |  |                       | $ | 156,595 |                           |  | $ | 72,790       |   |  | $                                             | (212,568 | ) |  | $ | 248,967   | 
|                                                             |  |                                   |         |  |                       |   |         |                           |  |   |              |   |  |                                               |          |   |  |   |           | 



F-48



---

##### Table of Contents

Magnum Hunter Resources Corporation and Subsidiaries Condensed Consolidating Statements of
Operations

(in thousands)



|                                                                                                 |  |                                      |         |   |                       |   |         |                           |  |   |              |   |  |                                               |        |   |  |   |         |  
|------------------------------------------------------------------------------------------------ |  | ------------------------------------ | ------- | - | --------------------- | - | ------- | ------------------------- |  | - | ------------ | - |  | --------------------------------------------- | ------ | - |  | - | ------- | -
|                                                                                                 |  | For the Year Ended December 31, 2011 |        
|                                                                                                 |  | Magnum HunterResourcesCorporation    |         |   | GuarantorSubsidiaries |   |         | Non GuarantorSubsidiaries |  |   | Eliminations |   |  | Magnum HunterResourcesCorporationConsolidated |       
|Revenues                                                                                         |  | $                                    | 1,056   |   |                       | $ | 100,504 |                           |  | $ | 31,370       |   |  | $                                             | (3,752 | ) |  | $ | 129,178 |  
|Expenses                                                                                         |  |                                      | 68,757  |   |                       |   | 111,994 |                           |  |   | 29,287       |   |  |                                               | (3,752 | ) |  |   | 206,286 |  
|                                                                                                 |  |                                      |         |   |                       |   |         |                           |  |   |              |   |  |                                               |        |   |  |   |         |  
|Loss from continuing operations before equity in net income of subsidiary                        |  |                                      | (67,701 | ) |                       |   | (11,490 | )                         |  |   | 2,083        |   |  |                                               |       |   |  |   | (77,108 | )
|Equity in net income of subsidiary                                                               |  |                                      | (8,960  | ) |                       |   |        |                           |  |   |             |   |  |                                               | 8,960  |   |  |   |        |  
|                                                                                                 |  |                                      |         |   |                       |   |         |                           |  |   |              |   |  |                                               |        |   |  |   |         |  
|Net income (loss)                                                                                |  |                                      | (76,661 | ) |                       |   | (11,490 | )                         |  |   | 2,083        |   |  |                                               | 8,960  |   |  |   | (77,108 | )
|Less: Net income attributable to non-controlling interest                                        |  |                                      |        |   |                       |   |        |                           |  |   | (249         | ) |  |                                               |       |   |  |   | (249    | )
|                                                                                                 |  |                                      |         |   |                       |   |         |                           |  |   |              |   |  |                                               |        |   |  |   |         |  
|Net loss                                                                                         |  |                                      | (76,661 | ) |                       |   | (11,490 | )                         |  |   | 1,834        |   |  |                                               | 8,960  |   |  |   | (77,357 | )
|Income tax benefit                                                                               |  |                                      |        |   |                       |   | 571     |                           |  |   | 125          |   |  |                                               |       |   |  |   | 696     |  
|Dividends on preferred stock                                                                     |  |                                      | (14,007 | ) |                       |   |        |                           |  |   |             |   |  |                                               |       |   |  |   | (14,007 | )
|                                                                                                 |  |                                      |         |   |                       |   |         |                           |  |   |              |   |  |                                               |        |   |  |   |         |  
|Net income (loss) attributable to common shareholders                                            |  | $                                    | (90,668 | ) |                       | $ | (10,918 | )                         |  | $ | 1,959        |   |  | $                                             | 8,960  |   |  | $ | (90,668 | )
|                                                                                                 |  |                                      |         |   |                       |   |         |                           |  |   |              |   |  |                                               |        |   |  |   |         |  
|                                                                                                 | 
|                                                                                                 |  | For the Year Ended December 31, 2010 |        
|                                                                                                 |  | Magnum HunterResourcesCorporation    |         |   | GuarantorSubsidiaries |   |         | Non GuarantorSubsidiaries |  |   | Eliminations |   |  | Magnum HunterResourcesCorporationConsolidated |       
|Revenues                                                                                         |  | $                                    | 1,312   |   |                       | $ | 21,765  |                           |  | $ | 11,984       |   |  | $                                             | (2,337 | ) |  | $ | 32,724  |  
|Expenses                                                                                         |  |                                      | 27,339  |   |                       |   | 18,293  |                           |  |   | 11,557       |   |  |                                               | (2,337 | ) |  |   | 54,852  |  
|                                                                                                 |  |                                      |         |   |                       |   |         |                           |  |   |              |   |  |                                               |        |   |  |   |         |  
|Loss from continuing operations before equity in net income of subsidiary                        |  |                                      | (26,027 | ) |                       |   | 3,472   |                           |  |   | 427          |   |  |                                               |       |   |  |   | (22,128 | )
|Equity in net income of subsidiary                                                               |  |                                      | 3,770   |   |                       |   |        |                           |  |   |             |   |  |                                               | (3,770 | ) |  |   |        |  
|                                                                                                 |  |                                      |         |   |                       |   |         |                           |  |   |              |   |  |                                               |        |   |  |   |         |  
|Gain (loss) from continuing operations before income taxes and non-controlling interest          |  |                                      | (22,257 | ) |                       |   | 3,472   |                           |  |   | 427          |   |  |                                               | (3,770 | ) |  |   | (22,128 | )
|Less: Net income attributable to non-conrolling interest                                         |  |                                      |        |   |                       |   |        |                           |  |   | (129         | ) |  |                                               |       |   |  |   | (129    | )
|                                                                                                 |  |                                      |         |   |                       |   |         |                           |  |   |              |   |  |                                               |        |   |  |   |         |  
|Net income (loss) from continuing operations attributable to Magnum Hunter Resources Corporation |  |                                      | (22,257 | ) |                       |   | 3,472   |                           |  |   | 298          |   |  |                                               | (3,770 | ) |  |   | (22,257 | )
|Income from discontinued operations                                                              |  |                                      | 8,457   |   |                       |   |        |                           |  |   |             |   |  |                                               |       |   |  |   | 8,457   |  
|                                                                                                 |  |                                      |         |   |                       |   |         |                           |  |   |              |   |  |                                               |        |   |  |   |         |  
|Net loss                                                                                         |  |                                      | (13,800 | ) |                       |   | 3,472   |                           |  |   | 298          |   |  |                                               | (3,770 | ) |  |   | (13,800 | )
|Dividends on preferred stock                                                                     |  |                                      | (2,467  | ) |                       |   |        |                           |  |   |             |   |  |                                               |       |   |  |   | (2,467  | )
|                                                                                                 |  |                                      |         |   |                       |   |         |                           |  |   |              |   |  |                                               |        |   |  |   |         |  
|Net income (loss) attributable to common shareholders                                            |  | $                                    | (16,267 | ) |                       | $ | 3,472   |                           |  | $ | 298          |   |  | $                                             | (3,770 | ) |  | $ | (16,267 | )
|                                                                                                 |  |                                      |         |   |                       |   |         |                           |  |   |              |   |  |                                               |        |   |  |   |         |  



F-49



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##### Table of Contents



|                                                                                                 |  |                                      |         |   |                       |   |     |                           |  |   |              |   |  |                                               |     |   |  |   |         |  
|------------------------------------------------------------------------------------------------ |  | ------------------------------------ | ------- | - | --------------------- | - | --- | ------------------------- |  | - | ------------ | - |  | --------------------------------------------- | --- | - |  | - | ------- | -
|                                                                                                 |  | For the Year Ended December 31, 2009 |        
|                                                                                                 |  | Magnum HunterResourcesCorporation    |         |   | GuarantorSubsidiaries |   |     | Non GuarantorSubsidiaries |  |   | Eliminations |   |  | Magnum HunterResourcesCorporationConsolidated |    
|Revenues                                                                                         |  | $                                    | 981     |   |                       | $ | 104 |                           |  | $ | 5,777        |   |  | $                                             | (18 | ) |  | $ | 6,844   |  
|Expenses                                                                                         |  |                                      | 16,054  |   |                       |   | 152 |                           |  |   | 6,282        |   |  |                                               | (12 | ) |  |   | 22,476  |  
|                                                                                                 |  |                                      |         |   |                       |   |     |                           |  |   |              |   |  |                                               |     |   |  |   |         |  
|Loss from continuing operations before equity in net income of subsidiary                        |  |                                      | (15,073 | ) |                       |   | (48 | )                         |  |   | (505         | ) |  |                                               | (6  | ) |  |   | (15,632 | )
|Equity in net income of subsidiary                                                               |  |                                      | (491    | ) |                       |   |    |                           |  |   |             |   |  |                                               | 491 |   |  |   |        |  
|                                                                                                 |  |                                      |         |   |                       |   |     |                           |  |   |              |   |  |                                               |     |   |  |   |         |  
|Gain (loss) from continuing operations before income taxes and non-controlling interest          |  |                                      | (15,564 | ) |                       |   | (48 | )                         |  |   | (505         | ) |  |                                               | 485 |   |  |   | (15,632 | )
|Less: Net income attributable to non-controlling interest                                        |  |                                      |        |   |                       |   |    |                           |  |   | 63           |   |  |                                               |    |   |  |   | 63      |  
|                                                                                                 |  |                                      |         |   |                       |   |     |                           |  |   |              |   |  |                                               |     |   |  |   |         |  
|Net income (loss) from continuing operations attributable to Magnum Hunter Resources Corporation |  |                                      | (15,564 | ) |                       |   | (48 | )                         |  |   | (442         | ) |  |                                               | 485 |   |  |   | (15,569 | )
|Income from discontinued operations                                                              |  |                                      | 445     |   |                       |   |    |                           |  |   |             |   |  |                                               |    |   |  |   | 445     |  
|                                                                                                 |  |                                      |         |   |                       |   |     |                           |  |   |              |   |  |                                               |     |   |  |   |         |  
|Net loss                                                                                         |  |                                      | (15,119 | ) |                       |   | (48 | )                         |  |   | (442         | ) |  |                                               | 485 |   |  |   | (15,124 | )
|Dividends on preferred stock                                                                     |  |                                      | (26     | ) |                       |   |    |                           |  |   |             |   |  |                                               |    |   |  |   | (26     | )
|                                                                                                 |  |                                      |         |   |                       |   |     |                           |  |   |              |   |  |                                               |     |   |  |   |         |  
|Net income (loss) attributable to common shareholders                                            |  | $                                    | (15,145 | ) |                       | $ | (48 | )                         |  | $ | (442         | ) |  | $                                             | 485 |   |  | $ | (15,150 | )
|                                                                                                 |  |                                      |         |   |                       |   |     |                           |  |   |              |   |  |                                               |     |   |  |   |         |  



F-50



---

##### Table of Contents

Magnum Hunter Resources Corporation

and Subsidiaries Condensed Consolidating Statements of Cash Flows

(in thousands)



|                                        |  |                                      |          |   |                       |   |          |                           |  |   |              |   |  |                                               |   |  |  |   |          |  
|--------------------------------------- |  | ------------------------------------ | -------- | - | --------------------- | - | -------- | ------------------------- |  | - | ------------ | - |  | --------------------------------------------- | - |  |  | - | -------- | -
|                                        |  | For the Year Ended December 31, 2011 |         
|                                        |  | Magnum HunterResourcesCorporation    |          |   | GuarantorSubsidiaries |   |          | Non GuarantorSubsidiaries |  |   | Eliminations |   |  | Magnum HunterResourcesCorporationConsolidated |  
|Cash flow from operating activities     |  | $                                    | (203,251 | ) |                       | $ | 192,027  |                           |  | $ | 45,062       |   |  | $                                             |  |  |  | $ | 33,838   |  
|Cash flow from investing activities     |  |                                      | (90,464  | ) |                       |   | (196,692 | )                         |  |   | (74,559      | ) |  |                                               |  |  |  |   | (361,715 | )
|Cash flow from financing activities     |  |                                      | 310,917  |   |                       |   | (369     | )                         |  |   | 31,645       |   |  |                                               |  |  |  |   | 342,193  |  
|                                        |  |                                      |          |   |                       |   |          |                           |  |   |              |   |  |                                               |   |  |  |   |          |  
|Effect of exchange rate changes on cash |  |                                      |         |   |                       |   |         |                           |  |   | (19          | ) |  |                                               |  |  |  |   | (19      | )
|                                        |  |                                      |          |   |                       |   |          |                           |  |   |              |   |  |                                               |   |  |  |   |          |  
|Net increase (decrease) in cash         |  |                                      | 17,202   |   |                       |   | (5,034   | )                         |  |   | 2,129        |   |  |                                               |  |  |  |   | 14,297   |  
|Cash at beginning of period             |  |                                      | 1,556    |   |                       |   | (1,094   | )                         |  |   | 92           |   |  |                                               |  |  |  |   | 554      |  
|                                        |  |                                      |          |   |                       |   |          |                           |  |   |              |   |  |                                               |   |  |  |   |          |  
|Cash at end of period                   |  | $                                    | 18,758   |   |                       | $ | (6,128   | )                         |  | $ | 2,221        |   |  | $                                             |  |  |  | $ | 14,851   |  
|                                        |  |                                      |          |   |                       |   |          |                           |  |   |              |   |  |                                               |   |  |  |   |          |  



|                                    |  |                                      |         |   |                       |   |         |                           |  |   |              |   |  |                                               |   |  |  |   |          |  
|----------------------------------- |  | ------------------------------------ | ------- | - | --------------------- | - | ------- | ------------------------- |  | - | ------------ | - |  | --------------------------------------------- | - |  |  | - | -------- | -
|                                    |  | For the Year Ended December 31, 2010 |        
|                                    |  | Magnum HunterResourcesCorporation    |         |   | GuarantorSubsidiaries |   |         | Non GuarantorSubsidiaries |  |   | Eliminations |   |  | Magnum HunterResourcesCorporationConsolidated |  
|Cash flow from operating activities |  | $                                    | (92,809 | ) |                       | $ | 72,453  |                           |  | $ | 19,189       |   |  | $                                             |  |  |  | $ | (1,167   | )
|Cash flow from investing activities |  |                                      | (21,926 | ) |                       |   | (77,194 | )                         |  |   | (19,161      | ) |  |                                               |  |  |  |   | (118,281 | )
|Cash flow from financing activities |  |                                      | 117,998 |   |                       |   | (80     | )                         |  |   | (198         | ) |  |                                               |  |  |  |   | 117,720  |  
|                                    |  |                                      |         |   |                       |   |         |                           |  |   |              |   |  |                                               |   |  |  |   |          |  
|Net increase (decrease) in cash     |  |                                      | 3,263   |   |                       |   | (4,821  | )                         |  |   | (170         | ) |  |                                               |  |  |  |   | (1,728   | )
|Cash at beginning of period         |  |                                      | (1,707  | ) |                       |   | 3,727   |                           |  |   | 262          |   |  |                                               |  |  |  |   | 2,282    |  
|                                    |  |                                      |         |   |                       |   |         |                           |  |   |              |   |  |                                               |   |  |  |   |          |  
|Cash at end of period               |  | $                                    | 1,556   |   |                       | $ | (1,094  | )                         |  | $ | 92           |   |  | $                                             |  |  |  | $ | 554      |  
|                                    |  |                                      |         |   |                       |   |         |                           |  |   |              |   |  |                                               |   |  |  |   |          |  



|                                    |  |                                      |         |   |                       |   |      |                           |  |   |              |   |  |                                               |   |  |  |   |         |  
|----------------------------------- |  | ------------------------------------ | ------- | - | --------------------- | - | ---- | ------------------------- |  | - | ------------ | - |  | --------------------------------------------- | - |  |  | - | ------- | -
|                                    |  | For the Year Ended December 31, 2009 |        
|                                    |  | Magnum HunterResourcesCorporation    |         |   | GuarantorSubsidiaries |   |      | Non GuarantorSubsidiaries |  |   | Eliminations |   |  | Magnum HunterResourcesCorporationConsolidated |  
|Cash flow from operating activities |  | $                                    | 719     |   |                       | $ | 440  |                           |  | $ | 2,214        |   |  | $                                             |  |  |  | $ | 3,373   |  
|Cash flow from investing activities |  |                                      | (12,549 | ) |                       |   | (529 | )                         |  |   | (3,546       | ) |  |                                               |  |  |  |   | (16,624 | )
|Cash flow from financing activities |  |                                      | 9,414   |   |                       |   | (1   | )                         |  |   |             |   |  |                                               |  |  |  |   | 9,413   |  
|                                    |  |                                      |         |   |                       |   |      |                           |  |   |              |   |  |                                               |   |  |  |   |         |  
|Net decrease in cash                |  |                                      | (2,416  | ) |                       |   | (90  | )                         |  |   | (1,332       | ) |  |                                               |  |  |  |   | (3,838  | )
|Cash at beginning of period         |  |                                      | 4,420   |   |                       |   | 235  |                           |  |   | 1,465        |   |  |                                               |  |  |  |   | 6,120   |  
|                                    |  |                                      |         |   |                       |   |      |                           |  |   |              |   |  |                                               |   |  |  |   |         |  
|Cash at end of period               |  | $                                    | 2,004   |   |                       | $ | 145  |                           |  | $ | 133          |   |  | $                                             |  |  |  | $ | 2,282   |  
|                                    |  |                                      |         |   |                       |   |      |                           |  |   |              |   |  |                                               |   |  |  |   |         |  

NOTE 17  SUBSEQUENT EVENTS

We sold an additional 638,998 shares of out Series D Cumulative Perpetual Preferred Stock at an average price of $47.33 per share for
net proceeds of approximately $29.6 million, pursuant to our ATM sales agreement subsequent to December 31, 2011, through the date of this report. There are a total of 2,076,556 shares of Series D Preferred Stock outstanding as of the date
of this report.

On February 14, 2012, the Company entered into the Fifth Amendment to the Second Amended and Restated Credit Agreement, as
amended. Pursuant to the Fifth Amendment, the Companys borrowing base was increased to $235 million from $200 million.



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##### Table of Contents

On February 17, 2012, Triad Hunter, a wholly-owned subsidiary of the Company, closed on an acquisition
of leasehold mineral interests located predominantly in Noble County, Ohio referred to as the Utica Acreage, for a total purchase price of $24.8 million. The Utica Acreage consists of approximately 15,558 gross (12,186 net) acres predominantly
located in Noble County, Ohio. The net price paid per acre for this acquisition was $2,037.

The Utica Acreage is in close proximity to Triad
Hunters existing acreage position in Washington and Noble Counties, Ohio, and now provides Triad Hunter approximately 18,187 gross (14,815 net) acres in in these two counties, and a total of 61,151 net acres that are presently prospective for
the Utica Shale.

On February 17, 2012, the Company, through its wholly owned subsidiary, Triad Hunter, LLC, closed on the sale of 100%
of the equity ownership interest of Hunter Disposal, LLC. The sale was made with GreenHunter Water, LLC, a wholly-owned subsidiary of GreenHunter Energy, Inc., an entity for which Mr. Evans is an officer and major shareholder and for which
Ronald Ormand, our Chief Financial Officer and a director, is also a director. The terms and conditions of the equity purchase agreement between the parties were approved by the audit committee or an independent special committee for each party. The
total sales price for this acquisition was approximately $8.8 million. The consideration received included a combination of cash, GreenHunter Energy restricted common stock, GreenHunter Energy 10% cumulative preferred stock, and a promissory note
due to the Seller. 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.



F-52



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##### Table of Contents

|Item 9. | CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
|------- | ------------------------------------------------------------------------------------

None.



|Item 9A. | CONTROLS AND PROCEDURES
|-------- | -----------------------

Evaluation of Disclosure Controls and Procedures

As of the end of the period covered by this report, an evaluation of the effectiveness of the design and operation of the Companys disclosure controls and procedures (as defined in
Rule 13a-15(e) under the Exchange Act) was performed under the supervision and with the participation of the Companys management, including our Chief Executive Officer and Chief Financial Officer. Based on that evaluation, the
Companys Chief Executive Officer and Chief Financial Officer concluded that the Companys disclosure controls and procedures were effective as of December 31, 2011 to ensure: that information required to be disclosed in the reports
it files and submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SECs rules and forms; and that information that is required to be disclosed under the Exchange Act is
accumulated and communicated to the Companys management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.

Evaluation of Changes in Internal Control over Financial Reporting

Under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, we have determined that, during the fourth quarter of fiscal 2011,
there were no changes in our internal controls over financial reporting that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

Managements Annual Report on Internal Controls Over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act. Under the
supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, we assessed the effectiveness of our internal controls over financial reporting as of the end of the period covered by this
report based on the framework in Internal ControlIntegrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on that assessment, our Chief Executive Officer and Chief Financial Officer
concluded that our internal controls over financial reporting were effective as of December 31, 2011 to provide reasonable assurance regarding the reliability of our financial reporting and the preparation of our financial statements for
external purposes in accordance with U.S. generally accepted accounting principles.

The Company acquired Williston Hunter Canada, Inc.,
Williston Hunter, Inc., and Magnum Hunter Production, Inc. during fiscal 2011. As permitted by SEC guidance, management excluded the acquired companies from its assessment of the effectiveness of the Companys internal control over financial
reporting as of December 31, 2011. Williston Hunter Canada, Inc., Williston Hunter Inc., and Magnum Hunter Production, Inc. are wholly owned subsidiaries whose total assets and net income represent approximately 34% and 35%, respectively, of
the related consolidated financial statement amounts as of and for the year ended December 31, 2011.

The effectiveness of the
Companys internal controls over financial reporting as of December 31, 2011, has been audited by Hein & Associates, LLP, an independent registered public accounting firm, as stated in their attestation report which is included in
Item 8, Financial Statements and Supplementary Data.



F-53



---

##### Table of Contents

Important Considerations

The effectiveness of our disclosure controls and procedures and our internal controls over financial reporting is subject to various inherent limitations, including cost limitations, judgments used in
decision making, assumptions about the likelihood of future events, the soundness of our systems, the possibility of human error, and the risk of fraud. Moreover, projections of any evaluation of effectiveness to future periods are subject to the
risk that controls may become inadequate because of changes in conditions and the risk that the degree of compliance with policies or procedures may deteriorate over time. Because of these limitations, there can be no assurance that any system of
disclosure controls and procedures or internal controls over financial reporting will be successful in preventing all errors or fraud or in making all material information known in a timely manner to the appropriate levels of management.



F-54



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##### Table of Contents

|Item 9B. | OTHER INFORMATION
|-------- | -----------------

None

PART III



|Item 10. | DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
|-------- | ------------------------------------------------------

Information as to Item 10 will be set forth in the 2012 Proxy Statement, or the Proxy Statement, for the Companys Annual Meeting of Stockholders anticipated to be held in June 2012, or the
Annual Meeting, and is incorporated herein by reference.



|Item 11. | EXECUTIVE COMPENSATION
|-------- | ----------------------

Information as to Item 11 will be set forth in the Proxy Statement for the Annual Meeting and is incorporated herein by reference.



|Item 12. | SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
|-------- | ----------------------------------------------------------------------------------------------

Information as to Item 12 will be set forth in the Proxy Statement for the Annual Meeting and is incorporated herein by reference.



|Item 13. | CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE
|-------- | ------------------------------------------------------------------------

Information as to Item 13 will be set forth in the Proxy Statement for the Annual Meeting and is incorporated herein by reference.



|Item 14. | PRINCIPAL ACCOUNTANT FEES AND SERVICES
|-------- | --------------------------------------

Information as to Item 14 will be set forth in the Proxy Statement for the Annual Meeting and is incorporated herein by reference.



F-55



---

##### Table of Contents

PART IV



|Item 15. | EXHIBITS, FINANCIAL STATEMENT SCHEDULES.
|-------- | ----------------------------------------



| | (a) | 1.     Consolidated Financial Statements: See Index to Financial Statements on page F-1.
| | --- | ----------------------------------------------------------------------------------------



| | 2. | Financial Statement Schedule:We have included on page F-57 of this annual report on Form 10-K, Financial Statement Schedule II, Valuation and
Qualifying Accounts
| | -- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------



| | 3. | Exhibits: See the list of exhibits in the Index to Exhibits to this annual report on Form 10-K, which is incorporated by reference herein.
| | -- | ------------------------------------------------------------------------------------------------------------------------------------------



F-56



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##### Table of Contents

PART IIOTHER INFORMATION

MAGNUM HUNTER RESOURCES CORPORATION

SCHEDULE IIVALUATION AND QUALIFYING ACCOUNTS

FOR THE YEAR ENDED
DECEMBER 31, 2011

(in thousands)



|                                                             |  |                            |     |  |                             |   |     |                         |  |   |            |  |  |                      |   |  |  |   |     | 
|------------------------------------------------------------ |  | -------------------------- | --- |  | --------------------------- | - | --- | ----------------------- |  | - | ---------- |  |  | -------------------- | - |  |  | - | --- | 
|                                                             |  |                            |     |  | Additions                   |   |     |                         |  |   |            | 
|Classification                                               |  | Balance atBeginningof Year |     |  | Charged toCosts andExpenses |   |     | Charged toOtherAccounts |  |   | Deductions |  |  | Balance atEndof Year |  
|Year Ended December 31, 2011                                 |  |                            |     |  |                             |   |     |                         |  |   |            |  |  |                      |   |  |  |   |     | 
|Allowance for doubtful accounts on Trade Accounts Receivable |  | $                          | 213 |  |                             | $ | 104 |                         |  | $ |           |  |  | $                    |  |  |  | $ | 317 | 



F-57



---

##### Table of Contents

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly
authorized.



MAGNUM HUNTER RESOURCES CORPORATIONBy:

/S/    GARY C.
EVANSGary C. EvansChairman of the Board and Chief Executive Officer


Date: February 29, 2012

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates
indicated.



|                                                     |  |                                                                                              |  |                  
|---------------------------------------------------- |  | -------------------------------------------------------------------------------------------- |  | -----------------
|Signature                                            |  | Title                                                                                        |  | Date             
|                                                     |  |                                                                                             
|/s/    GARY C.
EVANS Gary C. Evans                   |  | Chairman of the Board and
Chief Executive Officer (Principal Executive Officer)              |  | February 29, 2012
|                                                     |  |                                                                                             
|/s/    RONALD D.
ORMAND Ronald D. Ormand             |  | Executive Vice President, Chief Financial Officer and
Director (Principal Financial Officer) |  | February 29, 2012
|                                                     |  |                                                                                             
|/s/    DAVID S.
KRUEGER David S. Krueger             |  | Senior Vice President and Chief Accounting Officer
(Principal Accounting Officer)            |  | February 29, 2012
|                                                     |  |                                                                                             
|/s/    J. RALEIGH BAILES,
SR. J. Raleigh Bailes, Sr. |  | Director                                                                                     |  | February 29, 2012
|                                                     |  |                                                                                             
|/s/    BRAD
BYNUM Brad Bynum                         |  | Director                                                                                     |  | February 29, 2012
|                                                     |  |                                                                                             
|/s/    VICTOR G.
CARRILLO Victor G.Carrillo          |  | Director                                                                                     |  | February 29, 2012
|                                                     |  |                                                                                             
|/s/    STEPHEN C.
HURLEY Stephen C. Hurley           |  | Director                                                                                     |  | February 29, 2012
|                                                     |  |                                                                                             
|/s/    JOE L.
MCCLAUGHERTY Joe L.
McClaugherty       |  | Director                                                                                     |  | February 29, 2012
|                                                     |  |                                                                                             
|/s/    STEVEN A.
PFEIFER Steven A. Pfeifer           |  | Director                                                                                     |  | February 29, 2012
|                                                     |  |                                                                                             
|/s/    JEFF
SWANSON Jeff Swanson                     |  | Director                                                                                     |  | February 29, 2012



F-58



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##### Table of Contents

INDEX TO EXHIBITS



|               |  |                                                                                                                                                                                                                                                                                    
|-------------- |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|Exhibit
Number |  | Description                                                                                                                                                                                                                                                                        
|2.1            |  | Arrangement Agreement between the Registrant and NGAS Resources, Inc., dated December 23, 2010 (incorporated by reference from the Registrants current report on Form 8-K
filed on December 30, 2010).+                                                                           
|               | 
|2.2            |  | Purchase and Sale Agreement between the Registrant, Quest Eastern Resource LLC and PostRock MidContinent Production, LLC, dated December 24, 2010 (incorporated by reference from the
Registrants current report on Form 8-K/A filed on March 2, 2011).+@                         
|               | 
|2.3            |  | Arrangement Agreement between the Registrant and NuLoch Resources Inc., dated January 19, 2011 (incorporated by reference from the Registrants current report on Form 8-K
filed on January 25, 2011).+                                                                            
|               | 
|2.4            |  | Plan of Arrangement under Section 193 of the Business Corporations Act (Alberta) with respect to the Acquisition of NuLoch Resources Inc. by the Registrant (incorporated by
reference from Registrants registration statement on Form S-4 filed on April 8, 2011).+              
|               | 
|2.5            |  | Purchase and Sale Agreement by and among Triad Hunter, LLC and Windsor Marcellus, LLC (incorporated by reference from the Registrants current report on Form 8-K filed on April
12, 2011.)+                                                                                       
|               | 
|2.6            |  | Purchase and Sale Agreement by and among Triad Hunter, LLC, Quest Eastern Resource LLC and PostRock Energy Corporation, dated June 16, 2011 (incorporated by reference from the
Registrants current report on Form 8-K filed on June 21, 2011).+                                  
|               | 
|2.7            |  | Purchase and Sale Agreement by and among Eagle Operating Inc., Williston Hunter ND, LLC and for the limited purposes set forth therein, the Registrant, dated August 4, 2011
(incorporated by reference from the Registrants current report on Form 8-K filed on August 5, 2011).+
|               | 
|3.1(1)         |  | Restated Certificate of Incorporation of the Registrant, filed February 13, 2002.                                                                                                                                                                                                  
|               | 
|3.1.1(1)       |  | Certificate of Amendment of Certificate of Incorporation of the Registrant, filed May 8, 2003.                                                                                                                                                                                     
|               | 
|3.1.2(1)       |  | Certificate of Amendment of Certificate of Incorporation of the Registrant, filed June 6, 2005.                                                                                                                                                                                    
|               | 
|3.1.3          |  | Certificate of Amendment of Certificate of Incorporation of the Registrant, filed July 18, 2007 (incorporated by reference from the Registrants quarterly report on
Form 10-QSB filed on August 14, 2007).                                                                        
|               | 
|3.1.4          |  | Certificate of Ownership and Merger Merging Magnum Hunter Resources Corporation with and into Petro Resources Corporation, filed July 13, 2009 (incorporated by reference from the
Registrants current report on Form 8-K filed on July 14, 2009).                                
|               | 
|3.1.5          |  | Certificate of Amendment of Certificate of Incorporation of the Registrant, filed November 3, 2010 (incorporated by reference from the Registrants current report on
Form 8-K filed on November 2, 2010).                                                                         
|               | 
|3.1.6          |  | Certificate of Amendment of Certificate of Incorporation of the Registrant, filed May 9, 2011 (incorporated by reference from the Registrants quarterly report on Form 10-Q
filed on March 31, 2011).                                                                             
|               | 
|3.2            |  | Amended and Restated Bylaws of the Registrant, dated March 15, 2001 as amended on April 14, 2006, October 12, 2006, and May 26, 2011 (incorporated by reference from the
Registrants Quarterly Report on Form 10-Q filed on August 9, 2011).                                      
|               | 
|4.1(2)         |  | Form of certificate for common stock.                                                                                                                                                                                                                                              
|               | 
|4.2            |  | Certificate of Designation of Rights and Preferences of 10.25% Series C Cumulative Perpetual Preferred Stock, dated December 10, 2009 (incorporated by reference from the
Registrants Registration Statement on Form 8-A filed on December 10, 2009).                             



---

##### Table of Contents

|               |  |                                                                                                                                                                                                                                                                            
|-------------- |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|Exhibit
Number |  | Description                                                                                                                                                                                                                                                                
|4.2.1          |  | Certificate of Amendment of Certificate of Designation of Rights and Preferences of 10.25% Series C Cumulative Perpetual Preferred Stock, dated August 2, 2010 (incorporated by
reference from the Registrants quarterly report on Form 10-Q filed on August 12, 2010).   
|               | 
|4.2.2          |  | Certificate of Amendment of Certificate of Designation of Rights and Preferences of 10.25% Series C Cumulative Perpetual Preferred Stock, dated September 8, 2010 (incorporated by
reference from the Registrants current report on Form 8-K filed on September 15, 2010).
|               | 
|4.3            |  | Certificate of Designation of Rights and Preferences of 8.0% Series D Cumulative Preferred Stock, dated March 16, 2011 (incorporated by reference from the Registrants current
report on Form 8-K filed on March 17, 2011).                                               
|               | 
|4.4            |  | Certificate of Designations, Preferences and Rights of the Special Voting Preferred Stock (incorporated by reference from the Registrants current report on Form 8-K filed on
May 5, 2011).                                                                               
|               | 
|10.1(3)        |  | Employment Agreement between the Registrant and Gary C. Evans, dated May 22, 2009.*                                                                                                                                                                                        
|               | 
|10.1.1         |  | Amendment to Employment Agreement between the Registrant and Gary C. Evans, dated of November 14, 2011.*#                                                                                                                                                                  
|               | 
|10.2(3)        |  | Stock Option Agreement between the Registrant and Gary C. Evans, dated May 22, 2009.*                                                                                                                                                                                      
|               | 
|10.3(3)        |  | Restricted Stock Agreement between the Registrant and Gary C. Evans, dated May 22, 2009.*                                                                                                                                                                                  
|               | 
|10.4(3)        |  | Employment Agreement between the Registrant and Ronald D. Ormand, dated May 22, 2009.*                                                                                                                                                                                     
|               | 
|10.4.1         |  | Amendment to Employment Agreement between the Registrant and Ronald O. Ormand, dated of November 14, 2011.*#                                                                                                                                                               
|               | 
|10.5(3)        |  | Stock Option Agreement between the Registrant and Ronald D. Ormand, dated May 22, 2009.*                                                                                                                                                                                   
|               | 
|10.6(3)        |  | Restricted Stock Agreement between the Registrant and Ronald D. Ormand, dated May 22, 2009.*                                                                                                                                                                               
|               | 
|10.7(2)        |  | Employment Agreement between the Registrant and H.C. Kip Ferguson, dated October 1, 2009.*                                                                                                                                                                               
|               | 
|10.7.1         |  | Amendment to Employment Agreement between Registrant and H.C. Kip Ferguson, dated November 14, 2011.*#                                                                                                                                                                   
|               | 
|10.8(4)        |  | Amended and Restated Stock Incentive Plan of Registrant.*                                                                                                                                                                                                                  
|               | 
|10.8.1         |  | Amendment to Amended and Restated Stock Incentive Plan (incorporated by reference from the Registrants proxy statement on Annex C of Schedule 14A filed on April 1,
2011).*                                                                                               
|               | 
|10.9(2)        |  | Form of Stock Option Agreement under the Registrants Amended and Restated Stock Incentive Plan.*                                                                                                                                                                          
|               | 
|10.10(4)       |  | Form of Restricted Stock Award Agreement under the Registrants Amended and Restated Stock Incentive Plan.*                                                                                                                                                                
|               | 
|10.11(4)       |  | Form of Stock Appreciation Right Agreement under the Registrants Amended and Restated Stock Incentive Plan.*                                                                                                                                                              
|               | 
|10.12          |  | Form of Executive Change of Control Retention Agreements.*#                                                                                                                                                                                                                
|               | 
|10.12.1        |  | Amendment to Form of Executive Change of Control Retention Agreements.*#                                                                                                                                                                                                   
|               | 
|10.13(1)       |  | Lease Purchase Agreement between the Registrant and The Meridian Resource & Exploration, LLC, dated January 10, 2006.                                                                                                                                                      
|               | 
|10.14(1)       |  | Form of Registration Rights Agreement for $3.00 warrants sold as part of the Registrants February 2006 private placement, dated February 17, 2006.                                                                                                                        
|               | 
|10.15(1)       |  | Form of $3.00 Warrant sold as part of February 2006 private placement.                                                                                                                                                                                                     
|               | 
|10.16          |  | Purchase and Sale Agreement between the Registrant and Eagle Operating, Inc., dated December 11, 2006 (incorporated by reference from the Registrants annual report on
Form 10-KSB for the year ended December 31, 2006, filed on April 2, 2007).                         
|               | 
|10.16.1(2)     |  | First Amendment to Purchase and Sale Agreement between the Registrant and Eagle Operating, Inc., dated January 25, 2007.                                                                                                                                                   
|               | 
|10.17          |  | Agreement and Plan of Merger between the Registrant, Sharon Hunter, Inc., Sharon Resources, Inc. and Sharon Energy Ltd., dated September 9, 2009 (incorporated by reference from the
Registrants current report on Form 8-K filed on September 15, 2009).                 



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##### Table of Contents

|               |  |                                                                                                                                                                                                                                                                                                                                                                            
|-------------- |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|Exhibit
Number |  | Description                                                                                                                                                                                                                                                                                                                                                                
|10.18          |  | Purchase and Sale Agreement between the Registrant and Centurion Exploration Company, LLC, dated September 14, 2009 (incorporated by reference from the Registrants current
report on Form 8-K filed on September 15, 2009).                                                                                                                                              
|               | 
|10.19          |  | Asset Purchase Agreement between the Registrant and Triad Energy Corporation, dated October 28, 2009 (incorporated by reference from the Registrants current report on
Form 8-K filed on October 29, 2009).                                                                                                                                                               
|               | 
|10.20          |  | Form of Securities Purchase and Registration Rights Agreement with respect to November 5, 2009 offering (incorporated by reference from the Registrants current report on
Form 8-K filed on November 6, 2009).                                                                                                                                                            
|               | 
|10.21          |  | Form of $2.50 Warrant with respect to the Registrants November 5, 2009 offering (incorporated by reference from the Registrants current report on Form 8-K filed on
November 6, 2009).                                                                                                                                                                                   
|               | 
|10.22(5)       |  | Placement Agency Agreement with respect to the Registrants November 10, 2009 offering, dated November 10, 2009                                                                                                                                                                                                                                                            
|               | 
|10.23(5)       |  | Placement Agency Agreement with respect to the Registrants November 11, 2009 offering, dated November 11, 2009.                                                                                                                                                                                                                                                           
|               | 
|10.24(5)       |  | Form of $2.50 Warrant with respect to the Registrants November 10 and 11, 2009 offerings.                                                                                                                                                                                                                                                                                 
|               | 
|10.25          |  | At the Market Sales Agreement for Series C Preferred Stock between the Registrant and McNicoll, Lewis &Vlak LLC, dated June 22, 2010 (incorporated by reference from the
Registrants current report on Form 8-K filed on June 24, 2010).                                                                                                                                  
|               | 
|10.26          |  | At the Market Sales Agreement for common stock between the Registrant and McNicoll, Lewis & Vlak LLC, dated June 25, 2010 (incorporated by reference from the Registrants
current report on Form 8-K filed on June 25, 2010).                                                                                                                                             
|               | 
|10.27          |  | Purchase and Sale Agreement between the Registrant and Approach Oil & Gas Inc., dated October 29, 2010 (incorporated by reference from the Registrants current report on
Form 8-K filed on November 4, 2010).+                                                                                                                                                            
|               | 
|10.28          |  | Form of Support Agreement between the Registrant and certain NGAS Resources, Inc. shareholders, dated December 23, 2010 (incorporated by reference from the Registrants current
report on Form 8-K filed on December 30, 2010).                                                                                                                                           
|               | 
|10.29          |  | Omnibus Agreement between the Registrant, NGAS Resources, Inc., NGAS Production Co., NGAS Gathering, LLC, Seminole Energy Services, L.L.C., Seminole Gas Company, L.L.C. and NGAS
Gathering II, LLC, dated March 10, 2011 (incorporated by reference from the Registrants current report on Form 8-K filed on March 16, 2011).@                                           
|               | 
|10.30          |  | Second Amended and Restated Credit Agreement between the Registrant, Bank of Montreal, Capital One, N.A., Amegy Bank National Association, KeyBank National Association, UBS
Securities LLC, BMO Capital Markets, and the lenders party thereto, dated April 13, 2011 (incorporated by reference from the Registrants current report on Form 8-K filed on April 14, 2011).
|               | 
|10.30.1        |  | First Amendment to Second Amended and Restated Credit Agreement (incorporated by reference from the Registrants Current Report on Form 8-K filed on July 19,
2011).                                                                                                                                                                                                       
|               | 
|10.30.2        |  | Second Amendment to Second Amended and Restated Credit Agreement (incorporated by reference from the Registrants current report on Form 8-K filed on August 18,
2011).                                                                                                                                                                                                    
|               | 
|10.30.3        |  | Third Amendment to Second Amended and Restated Credit Agreement (incorporated by reference from the Registrants current report on Form 8-K filed on October 4,
2011).                                                                                                                                                                                                     
|               | 
|10.30.4        |  | Fourth Amendment to Second Amended and Restated Credit Agreement (incorporated by reference from the Registrants current report on Form 8-K filed on December 12,
2011).+                                                                                                                                                                                                 



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##### Table of Contents

|               |  |                                                                                                                                                                                                                                                              
|-------------- |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|Exhibit
Number |  | Description                                                                                                                                                                                                                                                  
|10.30.5        |  | Fifth Amendment to Second Amended and Restated Credit Agreement (incorporated by reference from the Registrants current report on Form 8-K filed on February 14,
2012).+                                                                                    
|               | 
|10.31          |  | Warrants Agreement (including Form of Warrant Certificate) between the Registrant and American Stock Transfer & Trust Company, dated October 13, 2011 (incorporated by
reference from the Registrants current report on Form 8-K filed on October 18, 2011).
|               | 
|10.32          |  | First Lien Credit Agreement by and among Eureka Hunter Pipeline, LLC, the lenders party thereto and SunTrust Bank (incorporated by reference from the Registrants current
report on Form 8-K filed on August 22, 2011).                                     
|               | 
|10.33          |  | Second Lien Term Loan Agreement by and among Eureka Hunter Pipeline, LLC, the lenders party thereto and PennantPark Investment Corporation (incorporated by reference from the
Registrants current report on Form 8-K filed on August 22, 2011).+           
|               | 
|10.34          |  | Second Lien Credit Agreement by and among the Registrant, Capital One, N.A., and the lenders and guarantors party thereto, dated September 28, 2011 (incorporated by reference from
the Registrants Current Report on Form 8-K filed on October 4, 2011).   
|               | 
|10.34.1        |  | First Amendment to Second Lien Credit Agreement, dated December 6, 2011 (incorporated by reference from the Registrants current report on Form 8-K filed on December 12,
2011).                                                                             
|               | 
|10.34.2        |  | Second Amendment to Second Lien Credit Agreement, dated February 14, 2012 (incorporated by reference to the Registrants current report on Form 8-K filed on February 14,
2012).+                                                                            
|               | 
|10.35(6)       |  | At the Market Sales Agreement (Series D Preferred Stock) between the Registrant and MLV & Co., LLC, dated January 18, 2012                                                                                                                                   
|               | 
|10.36(6)       |  | At the Market Sales Agreement (Series D Preferred Stock) between the Registrant and Wunderlich Securities, Inc., dated January 18, 2012.                                                                                                                     
|               | 
|10.37(6)       |  | At the Market Sales Agreement (Common Stock) between the Registrant and MLV & Co., LLC, dated January 18, 2012.                                                                                                                                              
|               | 
|12.1           |  | Computation of Ratio of Earnings to Fixed Charges.#                                                                                                                                                                                                          
|               | 
|21.1           |  | List of Subsidiaries.#                                                                                                                                                                                                                                       
|               | 
|23.1           |  | Consent of Hein & Associates LLP.#                                                                                                                                                                                                                           
|               | 
|23.2           |  | Consent of Cawley Gillespie & Associates, Inc.#                                                                                                                                                                                                              
|               | 
|23.3           |  | Consent of AJM Deloitte and Touche, LLP.#                                                                                                                                                                                                                    
|               | 
|31.1           |  | Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.#                                                                                                                                                         
|               | 
|31.2           |  | Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.#                                                                                                                                                         
|               | 
|32.1           |  | Certification of the Chief Executive Officer and Chief Financial Officer provided pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley
Act of 2002.#                                                                  
|               | 
|99.1           |  | Independent Engineer Reserve Report for the year ended December 31, 2011 prepared by Cawley Gillespie & Associates, Inc.#                                                                                                                                    
|               | 
|99.2           |  | Independent Engineer Reserve Report for the year ended December 31, 2011 prepared by AJM Deloitte and Touche, LLP.#                                                                                                                                          



|* | The referenced exhibit is a management contract, compensatory plan or arrangement.
|- | ----------------------------------------------------------------------------------



|+ | The schedules to this exhibit have been omitted pursuant to Item 601(b)(2) of Regulation S-K and will be provided to the SEC upon request.
|- | ------------------------------------------------------------------------------------------------------------------------------------------



|@ | Portions of this exhibit are subject to a request for confidential treatment and have been redacted and filed separately with the SEC.
|- | --------------------------------------------------------------------------------------------------------------------------------------



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##### Table of Contents

|# | Filed Herewith
|- | --------------



|(1) | Incorporated by reference from the Registrants registration statement on Form SB-2 filed on March 21, 2006.
|--- | ------------------------------------------------------------------------------------------------------------



|(2) | Incorporated by reference from the Registrants annual report on Form 10-K filed on February 18, 2011.
|--- | ------------------------------------------------------------------------------------------------------



|(3) | Incorporated by reference from the Registrants current report on Form 8-K filed on May 28, 2009.
|--- | -------------------------------------------------------------------------------------------------



|(4) | Incorporated by reference from the Registrants current report on Form 8-K filed on December 3, 2010.
|--- | -----------------------------------------------------------------------------------------------------



|(5) | Incorporated by reference from the Registrants current report on Form 8-K filed on November 13, 2009.
|--- | ------------------------------------------------------------------------------------------------------



|(6) | Incorporated by reference from the Registrants current report on Form 8-K filed on January 19, 2012.
|--- | -----------------------------------------------------------------------------------------------------