Attached files

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EX-23.1 - CONSENT OF HEIN & ASSOCIATES LLP - MAGNUM HUNTER RESOURCES CORPd283615dex231.htm
EX-12.1 - COMPUTATION O F RATIO OF EARNINGS TO FIXED CHARGES - MAGNUM HUNTER RESOURCES CORPd283615dex121.htm
EX-21.1 - LIST OF SUBSIDIARIES. - MAGNUM HUNTER RESOURCES CORPd283615dex211.htm
EX-99.2 - INDEPENDENT ENGINEER RESERVE REPORT PREPARED BY AJM DELOITTE AND TOUCHE, LLP - MAGNUM HUNTER RESOURCES CORPd283615dex992.htm
EX-99.1 - INDEPENDENT ENGINEER RESERVE REPORT PREPARED BY CAWLEY GILLESPIE & ASSOCIATES, I - MAGNUM HUNTER RESOURCES CORPd283615dex991.htm
EX-23.2 - CONSENT OF CAWLEY GILLESPIE & ASSOCIATES, INC. - MAGNUM HUNTER RESOURCES CORPd283615dex232.htm
EX-31.1 - CERTIFICATION OF CHIEF EXECUTIVE OFFICER PURSUANT TO SECTION 302 OF THE SARBANES - MAGNUM HUNTER RESOURCES CORPd283615dex311.htm
EX-31.2 - CERTIFICATION OF CHIEF FINANCIAL OFFICER PURSUANT TO SECTION 302 OF THE SARBANES - MAGNUM HUNTER RESOURCES CORPd283615dex312.htm
EX-23.3 - CONSENT OF AJM DELOITTE AND TOUCHE, LLP - MAGNUM HUNTER RESOURCES CORPd283615dex233.htm
EX-10.4.1 - AMENDMENT TO EMPLOYMENT AGREEMENT - MAGNUM HUNTER RESOURCES CORPd283615dex1041.htm
EX-10.12 - EXECUTIVE CHANGE IN CONTROL RETENTION AGREEMENT - MAGNUM HUNTER RESOURCES CORPd283615dex1012.htm
EX-10.1.1 - AMENDMENT TO EMPLOYMENT AGREEMENT - MAGNUM HUNTER RESOURCES CORPd283615dex1011.htm
EX-10.7.1 - AMENDMENT TO EMPLOYMENT AGREEMENT - MAGNUM HUNTER RESOURCES CORPd283615dex1071.htm
EX-32 - CERTIFICATION OF THE CEO AND CFO PROVIDED PURSUANT TO 18 U.S.C. SECTION 1350 - MAGNUM HUNTER RESOURCES CORPd283615dex32.htm
Table of Contents

 

 

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.

 

 

 


Table of Contents

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  
     Proved
Reserves(a)
            %
Oil/Liquids
    Productive
Wells
 

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  
     Proved
Reserves(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 Working
Interest
    First
Production
    Lateral
Length  (feet)
    # of  Frac
Stages
    IP-24 Hour
Rate (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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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

  MHR
Working
Interest
    First
Production
    Lateral
Length
    # of  Frac
Stages
    IP-24 Hour
Rate (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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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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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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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 Working
Interest
    First
Production
    Lateral
Length  (feet)
    # of Frac
Stages
    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.

 

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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.

 

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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  Ended
December 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

 

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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.

 

     Developed
Acreage(1)
     Undeveloped
Acreage(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.

 

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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.

 

     Producing
Oil Wells
     Producing
Gas Wells
     Total  Producing
Wells
 
     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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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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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 of
December 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 Securities
to be Issued Upon
Exercise of
Outstanding Options,
Warrants and Rights
     Weighted-Average
Exercise Price of
Outstanding Options,
Warrants and
Rights
     Number of Securities
Remaining Available for
Future Issuance Under
Equity Compensation Plans
(Excluding Securities
Reflected 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