UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

Form 10-K

 

 

Commission file number: 001-32997

 

 

Magnum Hunter Resources Corporation

(Name of registrant as specified in its charter)

 

 

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:

 

 

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 o     No þ

 

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

 

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

 

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

 

Indicate by check mark 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.  o

 

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

 

 

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

 

State the aggregate market value of voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of the registrant’s most recently completed second fiscal quarter: $276,042,143.

 

As of February 16, 2011, 76,462,082 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, 2010 are incorporated by reference into Part III of this Form 10-K.

 

 

Magnum Hunter Resources Corporation

 

2010 Annual Report on Form 10-K

 

Table of Contents

 

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, market conditions in the oil and gas industry and the impact of environmental and other governmental regulation. In addition, with respect to our pending acquisitions of NGAS Resources, Inc., referred to as NGAS, and NuLoch Resources Inc., referred to as NuLoch, 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 either 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:

 

 

With respect to the Company’s pending acquisitions, factors, risks and uncertainties that may cause actual results, performance or achievements to vary materially from those anticipated in forward-looking statements

include, but are not limited to, the risk that either proposed transaction will not be consummated; failure to satisfy any of the conditions to either proposed transaction, such as in the case of the NGAS transaction the inability to obtain the requisite approvals of the NGAS shareholders and the Supreme Court of British Columbia, or in the case of the NuLoch transaction, the inability to obtain the requisite approvals of NuLoch’s shareholders, the Company’s shareholders and the Court of Queen’s Bench of Alberta; adverse effects on the market price of our common stock or on our operating results because of a failure to complete either proposed transaction; failure to realize the expected benefits of either proposed transaction; negative effects of announcement or consummation of either proposed transaction on the market price of our common stock; significant transaction costs and/or unknown liabilities; general economic and business conditions that affect the companies following the proposed transaction; and other factors.

 

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.

 

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

 

 

 

 

 

 

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

 

Overview

 

We are an independent oil and gas company engaged in the acquisition, development and production of oil and natural gas, primarily in West Virginia, North Dakota, Texas and Louisiana. We are presently active in three of the most prolific shale resource plays in the United States, namely the Marcellus Shale, Eagle Ford Shale and Williston Basin/Bakken Shale. The Company is a Delaware corporation and was incorporated in 1997. In 2005, Magnum Hunter began oil and gas operations under the name Petro Resources Corporation. In May 2009, Magnum Hunter (then known as Petro Resources Corporation) restructured its management team and refocused its business strategy, and in July 2009 changed its name to Magnum Hunter Resources Corporation. The restructured management team includes Gary C. Evans, as 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.

 

The Company’s new management implemented a business strategy consisting of exploiting the Company’s inventory of lower risk drilling locations and the acquisition of undeveloped leases and long-lived proved reserves with significant exploitation and development opportunities primarily located in unconventional resource plays. As a result of this strategy, the Company has substantially increased its assets and production base through a combination of acquisitions and ongoing development drilling efforts, the Company’s percentage of operated properties has increased significantly, its inventory of acreage and drilling locations in resource plays has grown and its management team has been expanded. Recently, management has focused on further developing and exploiting unconventional resource plays, the acquisition of additional operated properties and the development of associated midstream opportunities directly related to these regions.

 

At December 31, 2010, our proved reserves were 13.4 mmboe, were approximately 51% oil, had a standardized measure of $128 million and had a PV-10 value of $177.8 million on an SEC basis and $242.6 million on a NYMEX basis. Our proved reserves at year end 2010 increased 216% from the level at year end 2009. Our average daily production volumes for 2010 were 1,301 boepd, which represent a 224% increase from those volumes for 2009 (giving effect to the Company’s sale in October 2010 of its Cinco Terry property as if such sale occurred at the beginning of each period). Our daily production volumes were approximately 2,732 boepd at December 31, 2010.

 

The principal executive offices of Magnum Hunter are located at 777 Post Oak Boulevard, Suite 650, Houston, Texas 77056, its telephone number is (832) 369-6986 and its 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

 

During the past year, the Company expanded, and more recently announced the pending further expansion of, its position in the Marcellus Shale area of West Virginia and Bakken Shale area of North Dakota and Canada through several significant transactions (completed and pending) discussed below.

 

Completed Triad Acquisition.  On February 12, 2010, the Company closed the acquisition of substantially all of the assets of privately-held Triad Energy Corporation and certain of its affiliates, which we refer to collectively as Triad Energy, a 23-year old Appalachian Basin focused oil and gas production company. The Company acquired the

assets of Triad Energy in connection with Triad Energy’s reorganization under Chapter 11 of the United States Bankruptcy Code for consideration totaling approximately $81 million. The acquired assets are located in West Virginia, Ohio and Kentucky, in the Appalachian Basin. The acquired assets included (i) conventional, mature oil fields under primary and secondary development containing approximately 5.1 mmboe of proved reserves at December 31, 2009 (65% oil); (ii) over 2,000 producing wells (99% of which are operated by the Company’s subsidiary, Triad Hunter, LLC); (iii) over 88,417 net acres, including over 47,000 net acres in the Marcellus Shale; (iv) approximately 182 miles of natural gas pipeline and/or rights-of-way; (v) three drilling rigs and service equipment; and (vi) two commercial salt water disposal facilities.

 

Completed PostRock Acquisition.  On December 24, 2010, the Company’s subsidiary, Triad Hunter, LLC, which we refer to as Triad Hunter, entered into a definitive agreement to acquire 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 the acquisition of certain Marcellus Shale assets located in Wetzel County for a total purchase price of $28 million. The purchase price consisted of (i) $14 million in cash and (ii) approximately 2.25 million newly issued restricted common shares of Magnum Hunter. 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 $11.75 million. The purchase price consisted of (i) $5.875 million in cash and (ii) 946,314 newly issued restricted common shares of Magnum Hunter.

 

The third phase of the transaction is contemplated to close in the future for Magnum Hunter to acquire the third and smallest package of assets, subject to the determination by Magnum Hunter that certain events and conditions precedent to the closing have occurred or been satisfied.

 

Triad Hunter operates 100% of the properties acquired in the first two phases of the transaction. These properties include a total of approximately 9,423 gross acres (6,758 net acres), comprised of approximately 4,451 gross acres (2,225 net acres) in Wetzel County and approximately 4,972 gross acres (4,533 net acres) in Lewis County. The acquired acreage is located in the general proximity of Triad Hunter’s existing Marcellus Shale acreage located in Tyler, Pleasants and Doddridge Counties, West Virginia. The majority of future lease expirations across the acquired acreage can be extended through a manageable drilling program which is planned for early 2011. The Company’s proved reserves at December 31, 2010 included approximately 11.64 bcfe associated with the properties acquired in the first phase of the transaction.

 

Pending NGAS Resources Acquisition.  On December 23, 2010, the Company entered into an arrangement agreement with NGAS Resources, Inc., a British Columbia corporation, which we refer to as NGAS, pursuant to which the Company will acquire all of the issued and outstanding equity of NGAS. NGAS is an independent exploration and production company focused on unconventional natural gas plays in the eastern United States, principally in the southern Appalachian Basin (the Huron and Weir Shales in Kentucky).

 

The proposed acquisition will be implemented pursuant to a court-approved plan of arrangement under British Columbia law. Under the plan of arrangement, each common share of NGAS will be transferred to the Company for the right to receive 0.0846 shares of the Company’s common stock. Upon closing of the transaction, Magnum Hunter will issue approximately 6.6 million common shares to the NGAS shareholders, representing (i) approximately 5% of Magnum Hunter’s fully diluted common shares outstanding as of February 14, 2011 (such percentage assuming completion of both the NGAS acquisition and the pending NuLoch Resources Inc. acquisition described below) or (ii) approximately 7% of Magnum Hunter’s fully diluted common shares outstanding as of February 14, 2011 (such percentage assuming completion of the NGAS acquisition but not the pending NuLoch Resources Inc. acquisition ). Certain NGAS liabilities will be refinanced under a new senior credit facility to be provided to the Company by BMO Capital Markets. In connection with the pending NuLoch Resources Inc. acquisition, the Company received a commitment for the new senior credit facility, which will have an initial borrowing base of $145 million, assuming completion of both acquisitions.

 

The NGAS assets to be acquired by the Company include proved reserves of 78.4 bcfe as of December 31, 2009 (74% natural gas and 65% proved developed producing), long-lived reserves with an R/P ratio of 23.4 years,

daily production of approximately 9.2 mmcfe as of September 30, 2010 and approximately 330,000 gross lease acres (68% undeveloped) in Kentucky. (As of February 15, 2011, information with respect to NGAS’s proved reserves as of December 31, 2010 was not yet available.)

 

The NGAS acquisition requires approval of NGAS’s shareholders, and is subject to customary closing conditions. The NGAS acquisition is scheduled to close on or about March 31, 2011, although there is no assurance that the acquisition will ultimately be consummated.

 

NGAS transaction highlights:

 

 

Pending NuLoch Resources Acquisition.  On January 19, 2011, the Company entered into an arrangement agreement among the Company, MHR ExchangeCo Corporation, a newly-formed corporation existing under the laws of the Province of Alberta and an indirect wholly owned subsidiary of the Company, which we refer to as ExchangeCo, and NuLoch Resources Inc., a corporation existing under the laws of the Province of Alberta, which we refer to as NuLoch, pursuant to which the Company through ExchangeCo will acquire all of the issued and outstanding equity of NuLoch. NuLoch is a Canadian public oil and natural gas producer with headquarters in Calgary, Alberta.

 

The proposed acquisition will be implemented pursuant to a court-approved plan of arrangement under Alberta law. The arrangement will involve an exchange of NuLoch’s common shares to the Company for shares of the Company’s common stock and/or exchangeable shares of ExchangeCo, as described below. Pursuant to the plan of arrangement, holders of NuLoch shares who are residents of Canada will receive, at the holder’s election, (i) a number of exchangeable shares equal to the number of NuLoch shares exchanged multiplied by the exchange ratio of 0.3304, (ii) a number of Magnum Hunter common shares equal to the number of NuLoch shares exchanged multiplied by the exchange ratio, or (iii) a combination of exchangeable shares and Magnum Hunter common shares as described in clauses (i) and (ii) above. Holders of NuLoch shares who are non-Canadian residents will receive a number of Magnum Hunter common shares equal to the number of NuLoch shares exchanged multiplied by the exchange ratio. The exchangeable shares will be exchangeable into Magnum Hunter common shares (on a share-for-share basis) and will carry voting and dividend/distribution rights which are designed to put holders of the exchangeable shares in the same functional and economic position as holders of Magnum Hunter common shares. Any exchangeable shares not previously exchanged will be automatically exchanged for Magnum Hunter common shares on the one year anniversary of the closing date of the proposed transaction, unless the Company exchanges them earlier upon the occurrence of certain events.

 

In connection with the proposed transaction, Magnum Hunter will issue approximately 42.8 million common shares (including Magnum Hunter common shares issuable upon exchange of the exchangeable shares of ExchangeCo) to the NuLoch securityholders, representing (i) approximately 32% of Magnum Hunter’s fully diluted common shares outstanding as of February 14, 2011 (such percentage assuming completion of both the NuLoch and NGAS acquisitions) or (ii) approximately 34% of Magnum Hunter’s fully diluted common shares outstanding as of February 14, 2011 (such percentage assuming completion of the NuLoch acquisition but not the NGAS acquisition). As of December 31, 2010, NuLoch had no outstanding long-term debt.

In connection with the proposed transaction, Magnum Hunter has received a commitment for a new $250 million senior credit facility with an initial borrowing base of $145 million (assuming completion of both the NuLoch and NGAS acquisitions) to be provided by BMO Capital Markets, secured by the Company’s existing asset base, including the assets being acquired from NuLoch and NGAS.

 

The NuLoch acquisition requires approval of NuLoch’s shareholders and optionholders, and the issuance of Magnum Hunter common stock in connection with the acquisition requires approval of Magnum Hunter’s stockholders. The NuLoch acquisition is also subject to customary closing conditions. The NuLoch acquisition is scheduled to close no later than May 31, 2011, although there is no assurance that the acquisition will ultimately be consummated.

 

NuLoch is actively developing its existing property portfolio in North Dakota and Saskatchewan, predominately in the evolving Bakken-Three Forks Sanish formations of the mid-continental Williston Basin in the United States and Canada. NuLoch’s assets include various interests in approximately 67 wells in the Williston Basin and six drilling rigs drilling new wells in the United States and Canada at year end 2010.

 

NuLoch’s assets include the following key attributes (although Canadian companies customarily report proved reserves and other oil and natural gas operating information on a gross basis, the following information has been provided to the Company by NuLoch’s management on a net ownership basis):

 

 

NuLoch transaction highlights:

 

 

Magnum Hunter’s Summary of Proved Reserves, Wells and Production

 

SEC Case Reserve Summary

 

 

 

 

NYMEX Futures Strip Case Reserve Summary

 

 

 

 

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 cost effective development of our properties and strategic acquisitions. Key elements of our business strategy include:

 

Focus on Unconventional Resource Plays  — We intend to focus on the development and expansion of our properties in the Marcellus Shale, Eagle Ford Shale and Williston Basin/Bakken Shale. As of February 15, 2011, the Company had over 138,438 gross acres (88,045 net acres) and over 600 identified drilling locations in these three areas. With recent improvements in drilling and completion technologies, the development of unconventional resources can be highly economic. We believe that these areas represent the potential for the best return on invested capital for our stockholders.

 

Strategic Acquisitions — The Company intends to continue to opportunistically acquire additional acreage and reserves in our core areas. In the past year, we have completed acquisitions from Triad Energy and PostRock Energy Corporation and have entered into definitive agreements for pending acquisitions of NGAS Resouces, Inc. and NuLoch Resources Inc., which are anticipated to be completed in the first half of 2011. We believe that our acquisition and operational track record, as well as our extensive industry relationships, will provide for continued growth opportunities in the future.

 

Focus on Acquisition and Development of Oil and Liquids Rich Resources — We plan to focus our development and acquisition efforts primarily on oil reserves in the Williston Basin (Bakken-Three Forks/Sanish) and in the oil window of the Eagle Ford Shale in south Texas. In addition, we are focused on liquids rich gas development (1,250 plus btu) in the Marcellus Shale area of northwest West Virginia. We believe these areas present the potential for the most attractive returns on employed capital.

 

Operating Control — We believe that operatorship provides 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 increase production volumes. During the past year, we have significantly increased the number of wells that we operate and control.

 

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

 

Leveraging the Experience of our Management Team — Management actively utilizes its track record and relationships with industry partners, commercial and investment banks and institutional and private equity investors in an effort to rapidly build and develop the Company’s asset base and finance the Company’s growth on the most cost effective basis.

 

Development of Eureka Hunter Pipeline Assets — We are continuing the construction of a 20 inch steel pipeline to support the development of our Marcellus Shale acreage position. This pipeline will enable the Company to develop our substantial natural gas and ngl resources in the Marcellus Shale, as well as provide the opportunity for substantial cash flow from the gathering of third party volumes of natural gas and ngls. We have allocated $25 million of our 2011 capital budget to grow our midstream business unit. The Company began flowing gas through the initial phase of its pipeline in the fourth quarter of 2010. The Company has contracted to purchase a 200 mmcfpd capacity cryogenic processing plant and anticipates delivery of the plant in October 2011. The plant is expected to be operational by mid-year 2012. We continue to actively pursue joint venture and other financing structures to support the expansion of the pipeline, and anticipate ultimately increasing its throughput capacity to approximately 200 mmcfpd.

 

Competitive Strengths

 

We believe that our key competitive strengths include:

 

Experienced Management Team — 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., unrelated to the Company, founded by Gary C. Evans in 1985, achieved an average annual internal rate of return of 38% to shareholders during the 15 years it was publicly traded. Additionally, our management team has collectively completed over $30 billion in financing transactions and acquisitions in the oil and gas industry, and our personnel have extensive expertise in all key operational disciplines.

 

Balanced Long-Lived Asset Base with Substantial Oil Reserves — As of December 31, 2010, we owned interests in 2,262 gross (2,091 net) productive wells across approximately 348,722 gross (139,481 net) mineral acres, predominately in the Marcellus Shale, Eagle Ford Shale and Williston Basin/Bakken Shale. We believe this geographic mix of properties and drilling opportunities, combined with our continuing business strategy of acquiring and exploiting properties in these areas, present us with multiple opportunities in executing our strategy. Our R/P ratio life is approximately 13.4 years based on year-end 2010 proved reserves of 13.4 mmboe. As of December 31, 2010, approximately 51% of our proved reserves were oil and 55% of our production was oil.

 

Acreage Position and Drilling Inventory in Core Resource Areas — As of February 15, 2011, we had over 88,045 net acres in our core resource areas, including approximately 56,595 net acres in the Marcellus Shale, 25,000 net acres in the Eagle Ford Shale and 6,450 net acres in the Williston Basin/Bakken Shale. We have identified an inventory of over 600 drillable locations in these core areas, with less than 10% currently booked as proved reserves.

 

Operated Assets — The Company operates a substantial majority of its assets. As of December 31, 2010, we operated approximately 87% of our producing wells and 66% of our proved reserves.

 

Marcellus Infrastructure Assets — The Company controls approximately 182 miles of pipeline, gathering systems and/or rights-of-way to provide critical takeaway capacity and third party gathering in the capacity-constrained Marcellus Shale area of West Virginia. Following our planned expansion efforts, we estimate our natural gas pipeline system will have throughput capacity of approximately 200 mmcfpd. In addition, we own and operate a 120,000 barrel per month commercial salt water disposal facility in Ohio, a second commercial salt water disposal facility located in Kentucky, three drilling rigs and various service equipment, which contribute to the efficient operation and development of our assets in the Marcellus Shale area.

 

2011 Operating Capital Budget

 

We estimate our capital budget for fiscal year 2011 to be approximately $150 million (excluding any budgeted amounts for operations that may be acquired pursuant to the pending NGAS and NuLoch acquisitions), including:

 

 

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 employed capital. We also believe in maintaining a strong balance sheet and using commodity price hedging. 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.

 

Marketing and Pricing

 

We derive revenue principally from the sale of oil and natural gas. As a result, our revenues are determined, to a large degree, by prevailing prices for crude oil and natural gas. We sell our oil and natural gas on the open market at

prevailing market prices. The market price for oil and natural gas is dictated by supply and demand, and we cannot accurately predict or control the price we may receive for our oil and natural gas.

 

We use commodity price hedging instruments to reduce our exposure to oil and natural gas price fluctuations and to help ensure that we have adequate cash flow to fund our debt service costs, 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.

 

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:

 

 

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

 

 

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 senior credit facility), we may be adversely affected by volatility in oil and natural gas prices.

As of December 31, 2010, we had the following hedges in place:

 

 

 

Competition

 

The oil and natural gas industry is highly competitive in all phases. We encounter competition from other oil and natural gas companies in all areas of operation, including the acquisition of leases and properties. Our competitors include numerous independent oil and natural gas companies and individuals. Many of our competitors are large, well established companies that have substantially larger operating staffs and greater capital resources than we do.

 

The prices of our products are controlled by the world oil market; 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.”

Operating Hazards and Risks

 

Drilling activities are subject to many risks, including the risk that no commercially productive reservoirs will be encountered. There can be no assurance that the new wells we drill will be productive or that we will recover all or any portion of our investment. Drilling for oil and natural gas may involve unprofitable efforts, not only from dry wells, but also from wells that are productive, but do not produce sufficient net revenues to return a profit after drilling, operating and other costs. The cost and timing of drilling, completing and operating wells is often uncertain. Our drilling operations may be curtailed, delayed or canceled as a result of numerous factors, many of which are beyond our control, including low oil and natural gas prices, title problems, weather conditions, delays by 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 transporting oil and natural gas, such as fires, natural disasters, explosions, encountering formations with abnormal pressures, blowouts, craterings, pipeline ruptures and spills, any of which can result in the loss of hydrocarbons, environmental pollution, personal injury claims and other damage to our properties and those of others. We maintain insurance against some but not all of the risks described above. In particular, the insurance we maintain does not cover claims relating to failure of title to oil and natural gas leases, loss of surface equipment at well locations, business interruption, loss of revenue due to low commodity prices or loss of 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.

 

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 and state legislatures and agencies. Failure to comply with such laws, rules and regulations can result in substantial penalties, including the delay or stopping of our operations. The legislative and regulatory burden on the oil and natural gas industry increases our cost of doing business and affects our profitability.

 

Our exploration and drilling activities, including the operation and construction of pipelines, plants and other facilities for gathering, processing or storing oil, natural gas and other products, are subject to stringent federal, state and local laws and regulations governing environmental quality, including those relating to oil spills and pollution control, that 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 and local 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.”

 

Climate change has become the subject of an important public policy debate. Climate change remains a complex issue, with some scientific research suggesting that an increase in greenhouse gas emissions (GHGs) may pose a risk to society and the environment. The oil and natural gas exploration and production industry is a source of certain GHGs, namely carbon dioxide and methane. 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 NGLs that we produce.”

Formation

 

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

 

Employees

 

At December 31, 2010, we had 165 full-time employees, of which 14 were officers. None of our employees is represented by a union. Management considers our relations with employees to be very good.

 

Facilities

 

As of December 31, 2010, our principal executive offices are located in Houston, Texas, and consist of approximately 16,944 square feet of leased office space. Our lease expires with respect to approximately 9,000, 6,000 and 1,600 square feet of this space in January 2016, May 2012 and December 2013, respectively. We also inherited, through the acquisition of our subsidiary, Sharon Hunter Resources, Inc., approximately 6,031 square feet of office space located in Houston, Texas under a lease that expires in February 2012. We have sub-leased this space. Our Triad Hunter offices consist of approximately 7,608 square feet of leased office space in Marietta, Ohio, as well as field offices in Kentucky and West Virginia.

 

Available Information

 

Our 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.

 

 

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. and global markets may have a material adverse impact on our business and financial condition that we currently cannot predict.

 

The U.S. and other world economies are slowly recovering from a recession which began in 2008 and has extended into 2011. 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 business and consumer confidence levels have not yet fully recovered to pre-recession levels. In addition, more volatility may occur before a sustainable, yet lower, growth rate is achieved. Global economic growth drives demand for energy from all sources, including for oil and natural gas. A lower future economic growth rate will result in decreased demand for our crude oil and natural gas production as well as lower commodity prices, which will reduce our cash flows from operations and our profitability.

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

 

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

 

 

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

 

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 collectibility 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.

 

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

 

Market conditions or the restriction in the availability of satisfactory oil and natural gas transportation arrangements may hinder our access to oil and natural gas markets or delay our production. The availability of a ready market for our oil and natural gas production depends on a number of factors, including the demand for and supply of oil and natural gas and the proximity of reserves to pipelines and terminal facilities. Our ability to market our production depends in substantial part on the availability and capacity of gathering systems, pipelines and processing facilities owned and operated by third parties. Our failure to obtain such services on acceptable terms

could materially harm our business. Our productive properties may be located in areas with limited or no access to pipelines, thereby necessitating delivery by other means, such as trucking, or requiring compression facilities. Such restrictions on our ability to sell our oil or natural gas may have several adverse effects, including higher transportation costs, fewer potential purchasers (thereby potentially resulting in a lower selling price) or, in the event we were unable to market and sustain production from a particular lease for an extended time, possibly causing us to lose a lease due to lack of production.

 

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

 

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

 

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

 

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

 

Shortages of oil field 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 new regions, 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. 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 and production 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 those wells and conduct those operations that we currently have planned and budgeted, causing us to miss our forecasts and projections.

 

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:

 

 

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

 

The oil and natural gas industry is capital intensive. We make and expect to continue to make substantial capital expenditures in our business and operations for the exploration for, and development, production and acquisition of, oil and natural gas reserves. To date, we have financed capital expenditures primarily with proceeds from bank borrowings, cash generated by operations and 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:

 

 

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

 

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

 

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

 

We are not insured against all risks. Losses and liabilities arising from uninsured and underinsured events could materially and adversely affect our business, financial condition, 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:

 

 

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

 

We have a total of approximately 168 employees as of February 14, 2011. Despite this number of employees, we expect that we will continue to require the services of independent consultants and contractors to perform various professional services, including reservoir engineering, land, legal, environmental and tax services. We will also pursue alliances with partners in the areas of geological and geophysical services and prospect generation, evaluation and prospect leasing. Our dependence on third party consultants and service providers creates a number of risks, including but not limited to:

 

 

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 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:

 

 

 

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.

 

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

 

We have limited experience in the drilling and completion of Marcellus Shale, Eagle Ford Shale and Bakken Shale wells, including limited horizontal drilling and completion experience. Other operators in the Marcellus Shale, Eagle Ford Shale and Bakken Shale plays may have significantly more experience in the drilling and completion of these wells, including the drilling and completion of horizontal wells. In addition, we have limited information with respect to the ultimate recoverable reserves and production decline rates in these areas. The wells drilled in Marcellus Shale, Eagle Ford Shale and Bakken Shale are primarily horizontal and require more stimulation, which makes them more expensive to drill and complete. The wells will also be more susceptible

to mechanical problems associated with the drilling and completion of the wells, such as casing collapse and lost equipment in the wellbore due to the length of the lateral portions of these unconventional wells. The fracturing of these shale formations will be more extensive and complicated than fracturing geological formations in conventional areas of operation.

 

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

 

Our prospects are in various stages of evaluation. 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 17, 2011, our outstanding indebtedness was approximately $34 million. 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:

 

 

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, 2010, we have incurred a cumulative net loss from operations of $41.1 million. We also recorded net losses in the first three quarters of 2010 and in the year ended December 31, 2010. If we fail to generate profits from our operations, we will not be able to sustain our business. We may never report profitable operations or generate sufficient revenue to maintain our company as a going concern.

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.

 

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

 

We have included in this report certain estimates of our proved reserves and related PV-10 at December 31, 2010 as prepared consistent with our independent reserve engineer’s interpretations of the new SEC rules relating to disclosures of estimated oil and natural gas reserves. These new rules are effective for fiscal years ending on or after December 31, 2009. These new rules require SEC reporting companies to prepare their reserve estimates using revised reserve definitions and revised pricing based on 12-month unweighted first-day-of-the-month average pricing. The SEC has not specifically reviewed our reserve estimates under the new rules and has released only limited interpretive guidance regarding reporting of reserve estimates under the new rules. Accordingly, while the estimates of our proved reserves and related PV-10 at December 31, 2010 included in this report have been prepared based on what we and our independent reserve engineers believe to be reasonable interpretations of the new SEC rules, those estimates could ultimately differ materially from any estimates we might prepare applying more specific SEC interpretive guidance.

 

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

 

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

 

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

 

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

 

 

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

 

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

 

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

 

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

 

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

 

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

 

To reduce our exposure to fluctuations in the prices of oil and natural gas, we currently and will likely 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:

 

 

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 senior credit 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 volume. Information as to these activities is set forth under “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Market Risk Management,” and in Note 4, “Financial Instruments and Derivatives,” to the consolidated financial statements.

 

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

 

There is a risk that we will be required to write down the carrying value of our oil and gas properties, which would reduce our earnings and stockholders’ equity. We account for our 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.

 

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 and gas leasehold acquisition costs requires judgment to estimate the fair value of these costs with reference to drilling activity in a given area.

 

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

 

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

 

Our senior credit facility with our lenders contains certain negative covenants that, among other things, restrict our ability to, with certain exceptions:

 

 

Our senior credit facility also requires us to satisfy certain affirmative financial covenants, including maintaining:

 

 

We are also required to enter into certain commodity price hedging agreements pursuant to the terms of the credit facility.

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

 

Certain of our subsidiaries, including PRC Williston LLC, Sharon Hunter Resources, Inc., Triad Hunter, LLC and Eureka Hunter Pipeline, LLC, have each guaranteed the performance of our obligations under our senior credit facility, and we have collateralized our obligations under the senior credit facility through our grant of a first priority security interest in our ownership interests in these subsidiaries and substantially all of our oil and gas properties, subject only to certain permitted liens.

 

Our ability to meet our debt obligations under the senior credit facility will depend on the future performance of our properties, which will be affected by financial, business, economic, regulatory and other factors, many of which we are unable to control. Our failure to service this debt could result in a default under the credit facility, which could result in the loss of our ownership interests in the guarantor subsidiaries and our oil and gas assets and otherwise materially adversely affect our business, financial condition and results of operations.

 

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

 

Exploration for and development, exploitation, production and sale of oil and natural gas in the United States are subject to extensive federal, state and local 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.

 

It is possible that new taxes (including those referenced under the heading “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”) 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 discharges of hazardous materials, fines and sanctions, and other environmental damages.

 

Enactment of legislative or regulatory proposals under consideration could negatively affect our business.

 

Numerous legislative and regulatory proposals affecting the oil and gas industry have been proposed or are under consideration by the current federal administration, Congress and various federal agencies. Among these proposals are: (1) climate change legislation introduced in Congress, Environmental Protection Agency regulations, carbon emission “cap-and-trade” regimens, and related proposals, none of which has been adopted in final form; (2) proposals contained in the President’s 2012 budget to repeal various tax deductions available to oil and gas producers, such as the current tax deduction for intangible drilling and development costs, which if eliminated could raise the cost of energy production, reduce energy investment and affect the economics of oil and gas exploration and production activities; and (3) legislation being considered by Congress that would subject the process of hydraulic fracturing to federal regulation under the Safe Drinking Water Act. Generally, any such future laws and regulations could result in increased costs or additional operating restrictions, and could have an effect on future

demand for oil and gas or on oil and gas prices. Until any such legislation or regulations are enacted or adopted, it is not possible to gauge their impact on our future operations or our results of operations and financial condition.

 

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

 

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

 

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

 

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

 

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

 

Although it is not possible at this time to predict whether proposed legislation or regulations will be adopted as initially written, if at all, or how legislation or new regulations that may be adopted to address greenhouse gas emissions would impact our business, any such future laws and regulations could result in increased compliance

costs or additional operating restrictions. Any additional costs or operating restrictions associated with legislation or regulations regarding greenhouse gas emissions could have a material adverse effect on our business, financial condition and results of operation. In addition, these developments could curtail the demand for fossil fuels such as oil and gas in areas of the world where our customers operate and thus adversely affect demand for our products and services, which may in turn adversely affect our future results of operations.

 

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 or local 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 and local laws and regulations governing the release of materials into the environment or otherwise relating to environmental protection. These laws and regulations may require the acquisition of a permit before drilling 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.

 

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.

 

On July 21, 2010, President Obama signed into law the Dodd-Frank Wall Street Reform and Consumer Protection Act, or the Act. The Act provides for new statutory and regulatory requirements for derivative transactions, including certain oil and gas hedging transactions. In particular, the Act includes a requirement that certain hedging transactions be cleared on exchanges and a requirement to post cash collateral for such transactions, although it is unclear whether the Act will apply to contracts for the sale of oil and gas for future delivery. The Act also provides for a potential exception from these clearing and cash collateral requirements for commercial end-users. However, many of the key concepts and defined terms under the Act must be delineated by rules and regulations to be adopted by the Commodities Futures Trading Commission, or the CFTC, and other applicable regulatory agencies. As a consequence, it is difficult to predict the effect the Act may have on our hedging activities. Depending on the rules and definitions adopted by the CFTC, we might be required to provide cash collateral for our commodities hedging transactions. Such a requirement could result in significant liquidity issues by reducing our ability to use cash for investment or other corporate purposes. Moreover, our senior credit facility, which requires us to enter into swap agreements covering at least 60% of our anticipated production from proved developed producing reserves, expressly prohibits our ability to provide cash collateral in connection with such agreements. In addition, a

requirement to post cash collateral for hedging transactions could limit our ability to execute strategic hedges, which would result in increased commodity price uncertainty and volatility in our future cash flows.

 

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

 

Among the changes contained in President Obama’s 2012 budget proposal released by the White House on February 14, 2011, is the elimination of certain key U.S. federal income tax preferences currently available to oil and gas exploration and production companies. Such changes include, but are not limited to:

 

 

The Close Big Oil Tax Loophole Act, which was introduced in the Senate in February 2011, includes many of the same proposals but is limited to taxpayers with annual gross revenues in excess of $100 million. It is unclear whether any of the foregoing changes will actually be enacted or how soon any such changes could become effective. The passage of any legislation as a result of the budget proposal, the Senate bill, or any other similar change in U.S. federal income tax law could eliminate certain tax deductions that are currently available with respect to oil and gas exploration and development, and any such change could negatively affect our financial condition and results of operations.

 

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.

 

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:

 

 

If acquisitions are unsuccessful or result in unanticipated events or if we are unable to successfully integrate acquisitions into our existing operations, such acquisitions could adversely affect our 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:

 

 

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.

 

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 focused in the south Texas, Ohio/West Virginia and North Dakota regions, we are pursuing and expect to continue to pursue acquisitions of properties located in other geographic areas.

 

Our current Eureka Hunter midstream operations and the expected future expansion of these operations, which include or will include natural gas gathering operations and a natural gas processing plant, subject us to additional governmental regulations.

 

The Company is currently constructing its Eureka Hunter pipeline, which will provide intrastate gas gathering services in support of the Company’s and other upstream producers’ operations in West Virginia and possibly Ohio. The Company has completed the first phase of the initial section of the pipeline and anticipates further expansion of the pipeline in 2011, 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 Company has also contracted for the construction of a gas processing facility which the Company anticipates will receive gas from the Eureka Hunter pipeline. Such facility is in the early stages of design and construction and is anticipated to be delivered to a site in West Virginia in the latter part of 2011.

The construction and operation of the Eureka Hunter pipeline and gas processing facility 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 these projects will be completed on schedule or at the budgeted cost, or at all. The operations of our gathering system, including the Eureka Hunter pipeline, in addition to the gas processing facility, 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 or our gas processing facility under construction 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.

 

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 15, 2011, 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 $8.34 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:

 

 

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 15, 2011, the last reported sale price of our common stock on the NYSE was $6.86 per share. The present volume of trading in our common stock may not provide investors sufficient liquidity in the event they wish to sell their shares of common stock. There can be no assurance that an active market for our common stock will be available for trading in large volumes. In addition, the stock market in general, and early stage public companies in particular, have experienced extreme price and volume fluctuations that have often been unrelated or disproportionate to the operating performance of such companies. If we are unable to further develop an active market for our common stock, our stockholders may not be able to sell our common stock at prices they consider to be fair or at times that are convenient for them, or at all.

 

We will likely issue additional common stock in the future, which would dilute 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 150,000,000 shares of common stock and 10,000,000 shares of preferred stock with such designations, preferences and rights as may be determined by our board of directors. As of February 15, 2011, there were 76,462,082 shares of our common stock issued and outstanding and 4,000,000 shares of our Series C Preferred Stock issued and outstanding.

 

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

 

Additionally, we are engaged in the issuance and sale of our common stock from time to time through a sales agent pursuant to an “at the market” (ATM) sales agreement between us and the sales agent. Sales of shares of our common stock, if any, by the sales agent 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 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 7.5% of the outstanding shares of our common stock as of February 15, 2011.

 

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:

 

 

 

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 15, 2011, our board of directors and executive officers collectively beneficially owned approximately 7.5% of the outstanding shares of our common stock. Although this is not a majority of our outstanding common stock, these stockholders, acting together, will have the ability to exert substantial influence over all matters requiring stockholder approval, including the election and removal of directors, any proposed merger, consolidation, or sale of all or substantially all of our assets and other corporate transactions.

 

The provisions in our amended and restated certificate of incorporation and amended and restated bylaws and under Delaware law, and the concentrated ownership of our common stock by our 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 dividends on our common stock in the foreseeable future. We currently intend to retain future earnings, if any, to finance the expansion of our business. Our future dividend policy is within the discretion of our board of directors and will depend upon various factors, including our business, financial condition, results of operations, capital requirements and investment opportunities. In addition, our senior credit facility limits the payment of dividends without the prior written consent of the lenders. Accordingly, stockholders must look solely to appreciation of our common stock to realize a gain on their investment, which may not occur.

 

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

 

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

 

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

 

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, 2010, we had outstanding warrants that have a final maturity of 2012 exercisable for an aggregate of 963,034 shares of our common stock. Any such exercise will be dilutive to our existing stockholders.

The market price of our common stock could be adversely affected by sales of substantial amounts of our common stock and securities convertible into, or exchangeable 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.

 

 

Appalachian Basin/Marcellus Shale

 

The Appalachian Basin is considered one of the most mature oil and natural gas producing regions in the United States. The Company made its entry into the Appalachian Basin through the acquisition of the assets of Triad Energy in February 2010. We recently expanded our acreage position and reserves with the acquisition of assets from affiliates of PostRock Energy Corporation in December 2010 and January 2011, which we refer to as the PostRock properties. In addition, on December 27, 2010, we announced the pending acquisition of NGAS which, if and when such acquisition is completed, will further expand our presence in the Appalachian Basin. As of February 15, 2011, the Company held approximately 91,870 net acres in the Appalachian Basin, including approximately 56,595 net acres overlying the Marcellus Shale area.

 

At December 31, 2010, proved reserves attributable to our Appalachian Basin area of operations on an SEC basis were 9.2 mmboe, of which 35% were oil and 43% were classified as proved developed producing. Using NYMEX strip prices, proved reserves were 9.6 mmboe at December 31, 2010. We operate 2,090 gross productive wells and exited 2010 with a production rate of approximately 1,575 boepd in the Appalachian Basin.

 

Our Appalachian Basin acreage is located in West Virginia, Ohio and Kentucky. The liquids rich gas and high btu content of the natural gas produced in the Company’s core Marcellus Shale area in northwest West Virginia and southeastern Ohio, coupled with a location near the energy-consuming regions of the mid-Atlantic and northeastern United States, typically allow the Company to sell its natural gas at a premium to the benchmark price for natural gas on the NYMEX. Historically, producers in the Appalachian Basin developed oil and natural gas from 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 6,000 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. These horizontal laterals exceed 2,000 feet in length, and typically involve multistage fracturing completions.

 

As of February 14, 2011, we had approximately 56,595 net acres in the core Marcellus Shale area. Our Marcellus Shale acreage is principally located in Tyler, Pleasants, Dodddridge,Wetzel and Lewis Counties, West Virginia. The Company operates 32 vertical Marcellus Shale wells and three horizontal Marcellus Shale wells defining the potential within our existing acreage. We also own conventional acreage in Pleasants County, West Virginia and in Nobel and Washington Counties, Ohio. As of February 14, 2011, approximately 75% of our

leases in the Marcellus Shale area are held by production. Our shallow production comes from the Big Ingun, Berea, Devonian Shale and the Clinton/Medina Sands. We also believe that our acreage may have the possibility of producing from the Trenton-Black River and Huron formations. The Huron formation has also benefited from lateral well drilling technology. In addition to our Marcellus Shale acreage, we have significant enhanced waterflood oil recovery operations in Calhoun, Clay and Roane Counties, West Virginia, including our Granny’s Creek Field, Richardson Unit and Tariff unit.

 

The PostRock properties acquired by us in December 2010 and January 2011 are 100% operated by Triad Hunter. The PostRock properties include a total of approximately 9,423 gross acres (6,758 net acres), comprising approximately 4,451 gross acres (2,225 net acres) in Wetzel County, West Virginia and approximately 4,972 gross acres (4,533 net acres) in Lewis County, West Virginia. The acquired acreage is located in the general proximity of Triad Hunter’s existing Marcellus Shale acreage in Tyler, Pleasants and Doddridge Counties, West Virginia. The majority of future lease expirations across the acquired acreage can be extended through a manageable drilling program which is planned for early 2011. Our proved reserves at December 31, 2010 included approximately 1.94 mmboe associated with the PostRock properties acquired in December 2010.

 

The Company’s first horizontal well in the natural gas liquids rich leg of the Marcellus Shale of northwestern West Virginia was the Weese Hunter #1001, located in Tyler County. The Company spud the Weese Hunter #1001 in late July 2010 and reached total vertical depth of approximately 6,510 feet in mid August 2010. A third party drilling rig commenced the horizontal leg in mid September 2010 and reached a horizontal length of approximately 4,028 feet. Total measured depth for the Weese Hunter #1001 is approximately 10,388 feet. A twelve stage frac job was successfully completed in December 2010. The Weese Hunter #1001 well initially tested at a production rate (IP) of 7.0 mmcfe per day with flowing tubing pressures of 2350 psi on a 22/64 inch choke. The btu content of the well was measured at approximately 1,225. The Weese Hunter #1001 began producing into our Eureka Hunter pipeline system on December 22, 2010. The current EUR for the Weese Hunter #1001 is approximately 4 bcfe. The Company operates this well and owns a 100% working interest with a 84.3% net revenue interest.

 

The Company’s second horizontal well in this area of the Marcellus Shale was the Weese Hunter #1003, located in Tyler County. The Company spud the Weese Hunter #1003 in October 2010 and reached total vertical depth of approximately 6,360 feet in November 2010. The well’s horizontal leg extends approximately 2,984 feet. Total measured depth for the Weese Hunter #1003 is approximately 10,151 feet. A twelve stage frac job was successfully completed in January 2011. The Weese Hunter #1003 well initially tested at a production rate (IP) of 5.45 mmcfe per day. The Weese Hunter #1003 began producing into our Eureka Hunter pipeline system on January 24, 2011.

 

The Company’s third horizontal well in this area of the Marcellus Shale was the Ormet #1-9H, located in Tyler County. The Company spud the Ormet #1-9H in October 2010 and reached total vertical depth of approximately 5,871 feet in October 2010. The drilling rig commenced the horizontal leg in mid November 2010 and reached a horizontal length of approximately 3,628 feet. Total measured depth for the Ormet #1-9H is approximately 9,944 feet. A twelve stage frac job was successfully completed in February 2011. The Ormet #1-9H well is expected to achieve first flow in late February 2011.

 

We plan to significantly expand our Marcellus Shale program in 2011, drilling a minimum of 15 gross horizontal wells (12.5 net) from our inventory of over 439 identified drilling locations at a cost of approximately $60 million.

 

South Texas/Eagle Ford Shale

 

Our Eagle Ford Shale acreage is located in the oil window of the trend in Gonzales, Atascosa and Fayette Counties, Texas with estimated original oil in place of 20-40 mmbbls per section. Effective development of our Eagle Ford Shale assets depends on optimization of horizontal drilling and multi-stage reservoir stimulation. Increased lateral length, increased frac stages and proper frac fluid selection are also important factors in increasing EURs and production rates. Initial production rates in the oil window are also dependent on gas oil ratios (GORs). Rock properties and fluid characteristics also can enhance deliverability and EURs.

The Eagle Ford Shale is a Cretaceous aged shale ranging in thickness of 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 or dolomitic shale sections. The Eagle Ford Shale produces from depths that range from approximately 7,500 to 14,000 feet. The Eagle Ford Shale has become one of the newest emerging successful shale reserves in the country.

 

As of December 31, 2010, Magnum Hunter had 890.5 mbbls of oil and 463.9 mmcf of natural gas of net estimated ultimate recoverable reserves on an SEC basis associated with our Eagle Ford Shale properties.

 

As of February 1, 2011, we had approximately 23,075 net acres (47,664 gross) primarily targeting the Eagle Ford Shale oil window. We have currently identified approximately 100 horizontal Eagle Ford Shale drilling locations, of which less than 10% are currently classified as proved reserves. Our working interests vary from 50% in Gonzales, Lee and Fayette Counties, Texas to 96.75% in Atascosa County, Texas. We have budgeted an estimated $65 million in capital expenditures for 2011 for the drilling of 14 gross (7 net) horizontal wells targeting the Eagle Ford Shale oil window. The Company has focused in the up-dip oil trend of the Eagle Ford Shale (8,000 to 11,500 feet) to provide better economic metrics.

 

We entered into a joint venture with Hunt Oil Company covering an area of mutual interest (AMI) consisting of 28,187 gross acres and 26,822 net acres in Gonzales and Lavaca Counties, Texas, under which each company has a 50% ownership interest. Both parties agreed to work together within the AMI on an equal and joint basis through December 2014. Both companies have cross-assigned existing ownership interests in their respective lease acreage positions for both Lavaca and Gonzales Counties. Additionally, the parties will share all future 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. Both companies intend that all new wells to be drilled under the joint venture will be horizontal Eagle Ford Shale wells.

 

We also have a second joint venture with a private independent oil and gas company in the Eagle Ford Shale area. The joint venture covers an AMI consisting of approximately 4,000 gross acres and 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 agreed to work together within the AMI on an equal basis for all future leasing, exploration, drilling, completion and development costs and other expenses. We are the operator under the joint venture. All wells under the joint venture will be horizontal Eagle Ford Shale wells. The Company and the other party will jointly drill a minimum of two wells in the AMI.

 

We have an active drilling program in the Peach Creek Field, located in southeastern Gonzales County 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 Field.

 

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.

 

The Company’s first well drilled in the Eagle Ford Shale oil window was the Gonzo Hunter #1-H in Gonzales County, Texas. The well was spud on June 10, 2010 and was drilled to a true vertical depth of 9,750 feet plus 4,365 horizontal feet. After a successful frac job, the well had an initial production rate of 605 boepd and 412 bbls per day of water. At year end 2010, the Gonzo Hunter #1-H was flowing to production without artificial lift at approximately 186 bopd, 123 mcfpd and 54 bbls per day of water. The well had produced approximately 24,000 bbls of oil as of December 31, 2010. Magnum Hunter currently estimates the gross economic ultimate recovery for the Gonzo Hunter #1-H to be 362,000 boe. Magnum Hunter operates the well and owns a 50% working interest.

 

The Gonzo Hunter North #1-H was spud on December 31, 2010, and is located approximately one mile northeast of the Gonzo Hunter #1-H. The well was drilling ahead at a vertical depth of approximately 9,245 feet at December 31, 2010. Magnum Hunter operates the well and owns a 50% working interest. We anticipate that the Gonzo Hunter North #1-H will be fracture stimulated in February 2011.

The Company’s Southern Hunter #1-H is located approximately seven miles southwest of the Gonzo Hunter #1-H. The well was spud on October 14, 2010 and was drilled to a true vertical depth of 11,779 feet plus 4,460 horizontal feet. After a 14 stage frac job, flowback commenced on January 7, 2011. In early January 2011, the Southern Hunter #1-H was flowing to production at approximately 1,335 boe per day and 212 bbls per day of water on a 13/64 inch choke with flow tubing pressure of 4,300 psi. Based on current production characteristics, the Company estimates the Southern Hunter #1-H’s gross economic ultimate recovery to be in the 500,000 boe range. Magnum Hunter operates the well and owns a 50% working interest.

 

On November 2, 2010, the Cinco Ranch #2-H well was spud. The well, located in Gonzales County, has been drilled to a true vertical depth of 10,025 feet and an additional 5,541 feet horizontally. The well is scheduled for a March 2011 frac job. Magnum Hunter is a 50% working interest owner in the Cinco Ranch #2-H well. Hunt Oil Company is the operator and owns the remaining 50% working interest.

 

The Cinco Ranch #1-H was spud on December 13, 2010. The well, located in Gonzales County, was drilling ahead at December 31, 2010. The drilling rig was released in January 2011 after drilling to a true vertical depth of 9,667 feet plus 4,683 horizontal feet. Magnum Hunter is a 50% working interest owner in the Cinco Ranch #1-H well. Hunt Oil Company is the operator and owns the remaining 50% working interest.

 

The Company spud the Furh #1-H well in early February 2011. This well is located in Gonzales County.

 

The Company’s first well in Atascosa County within the Eagle Ford Shale is the Lagunillas Camp #1-H. The well was spud on August 12, 2010 and was drilled to a true vertical depth of 8,350 feet plus 5,050 horizontal feet. After a 15 stage frac job, the well had an initial production rate of 340 boepd and 750 bbls per day of water. At December 31, 2010, the Lagunillas Camp #1-H was flowing to production with no artificial lift at approximately 216 bbls of oil and 742 bbls of water per day. Magnum Hunter operates the Lagunillas Camp #1-H well and owns a 96.875% working interest.

 

Magnum Hunter’s second well in Atascosa County within the Eagle Ford Shale is the Lagunillas Camp #2-H. The well was spud on September 15, 2010 and was drilled to a true vertical depth of 8,350 feet plus 4,650 horizontal feet. At December 31, 2010, the Lagunillas Camp #2 well was producing approximately 147 bopd, 66 mcfpd and 275 bbls of water per day. The well had produced approximately 8,600 bbls of oil as of December 31, 2010. The Company operates the Lagunillas Camp #2-H well and owns a 96.875% working interest.

 

Williston Basin/Bakken Shale

 

At December 31, 2010, 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 (6,540 net) acres. Approximately 90% of these leases, which are located in Burke, Renville, Ward, Bottineau and McHenry Counties in North Dakota, are held by production. As of December 31, 2010, our proved reserves on an SEC basis were an estimated 2.5 mmboe with approximately 96% and 90% of our reserves and production, respectively, consisting of oil. As of December 31, 2010, on a NYMEX strip basis, our proved reserves were 2.7 mmboe. At December 31, 2010, we had a production exit rate of approximately 392 boepd from our North Dakota properties.

 

Re-pressurization efforts with respect to our North Dakota properties commenced in November 2002, which have resulted in the ability to begin secondary recovery efforts through conventional and horizontal drilling activities in seven of the 15 producing fields. We have identified approximately 66 horizontal drilling locations.

 

On January 19, 2011, the Company entered into a definitive agreement to acquire NuLoch, which, if and when such acquisition is completed, will significantly expand our presence in the Williston Basin with 71,600 net acres and 267 net identified drilling locations. The Company has positioned itself to explore this liquids rich region in North America and plans to use NuLoch as an initial platform to acquire and develop reserves and production in the Williston Basin in 2011.

 

The Williston Basin is spread across North Dakota, Montana and parts of southern Canada with the United States portion of the basin encompassing approximately 143,000 square miles. The basin produces oil and 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 is generally found at vertical depths of 9,000 to 10,500 feet. Below the Lower Bakken Shale lies the Three Forks/Sanish formation, and the Three Forks Shale has also proven to contain reservoir rock. The Three Forks/Sanish typically consists of interbedded dolomites and shale with local development of a discontinuous sandy member at the top, known as the Sanish sand. Crude oil production from the Bakken Shale and Three Forks/Sanish reservoirs is made possible through the combination of advanced horizontal drilling and fracture stimulation technology. Combining these two technologies to produce crude oil from the Bakken formation began to evolve around the year 2000. Horizontal wells in these formations are typically drilled on 320 acre, 640 acre or 1,280 acre spacing with horizontal laterals extending 4,500 to 9,500 feet into the reservoir. Fracture stimulation techniques vary but most commonly utilize multi-stage mechanically diverted stimulations using un-cemented liners and packers.

 

Other Properties

 

South Louisiana / East Chalkley — Our East Chalkley field is located in Cameron Parish, Louisiana. The unit consists of approximately 714 gross acres. This developmental project is an exploitation of bypassed oil reserves remaining in a natural gas field located at depths between 9,300 and 9,400 feet. At December 31, 2010, proved reserves on an SEC basis were 274 mboe, consisting of 88% oil and 47% proved developed. At December 31, 2010, proved reserves on a NYMEX strip basis were 277 mboe. The Company operates East Chalkley and owns an approximate 62% working interest and approximate 42.7% net revenue interest. We have not allocated any capital to this project for 2011 and are actively seeking to divest this non-core asset.

 

Other — The Company has an interest in the Surprise Project which is located in Nacogdoches County, Texas with natural gas potential from multiple horizons including James Lime, Pettit, Travis Peak, Expanded Bossier, Cotton Valley, and Haynesville Shale formations. The prospect is operated by Goodrich Petroleum Corporation. The prospect area consists of approximately 4,796 gross (479 net) acres, and we have a 10% working interest and a 7.4% net revenue interest in the prospect. In addition, we have approximately 157,758 gross (13,371 net) undeveloped acres in New Mexico, Kentucky and Utah. We currently do not plan to allocate any capital to these prospects or areas for 2011.

 

Midstream Assets

 

The acquisition of assets from Triad Energy included important infrastructure assets for the effective development of the Company’s Marcellus Shale unconventional resources. With increased drilling activity in the region, relying on third party oilfield service providers and pipeline operators can be costly. Access to a pipeline system is vital to flow natural gas to sales and often is a deciding factor in drilling and production decisions. The summary below provides a brief overview of the midstream services we operate and control. We anticipate these assets will generate an attractive revenue stream as we actively market them to third party producers in the Appalachian Basin.

 

The Eureka Hunter pipeline consists of approximately 182 miles of pipeline, gathering systems and/or rights-of-way located in northern West Virginia, in the Marcellus Shale. The rights-of-way run through Pleasants, Tyler, Ritchie, Wetzel, Marion, Harrison, Doddridge, Lewis and Monongalia Counties. We are currently constructing a new 20 inch high-pressure pipeline with up to 200 mmcfpd of throughput capacity. The first pipeline section of six miles was turned to sales on December 22, 2010. The next section of the pipeline of approximately 10 miles, which together with the initial six mile section comprising the first phase, is expected to be completed by June 30, 2011. We expect to have sufficient capacity to gather significant quantities of Company-produced natural gas from our Marcellus Shale development program, as well as third-party gas. We have budgeted $25 million to this project for 2011 which will be used for the construction of approximately six miles of main line and 12 miles of laterals.

In December 2010, the Company entered into an agreement for the construction of a new 200 mmcf per day capacity cryogenic natural gas processing plant. The processing plant will process natural gas and natural gas liquids gathered on the Eureka Hunter pipeline. Installation and hookup of the plant will begin upon delivery of the plant, scheduled for October 2011. The plant is expected to be operational by mid-year 2012. With the Company’s first section of the Eureka Hunter pipeline system operational, the purchase of the plant furthers the Company’s goal of becoming a fully integrated producer, gas gatherer and processor in this region. The plant will allow us to not only gather and process our equity natural gas, but also to provide a conduit for other producers in the area. We anticipate funding capital requirements for the plant through a combination of a partnership with an industry participant and/or project financing. Our pending acquisition of NGAS contemplates the restructuring of an existing out-of-market gas gathering and transportation agreement between NGAS and a third party, and as part of the restructuring such third party would be granted a limited option to acquire a 50% ownership interest in the processing plant. We are also discussing funding arrangements for the plant with other potential industry partners.

 

Equipment and Services

 

Alpha Hunter Drilling — As part of the acquisition of the Triad Energy assets, we acquired oilfield service equipment which is operated by our subsidiary, Alpha Hunter Drilling, LLC. This equipment consists primarily of three drilling rigs, a workover rig and heavy machinery, which are used in our operations and also those of third parties. We anticipate using our rigs to drill the vertical portions of our Marcellus Shale wells and then switching to larger rigs for the horizontal sections. This flexibility is expected to reduce the overall drilling costs, as well as improve the timing of drilling activity. As of February 14, 2011, two of our drilling rigs were under multi-well drilling contracts to large producers in the area. The third drilling rig will be utilized for drilling the top hole for our 2011 Marcellus Shale drilling program and will be leased to third party operators on the spot market.

 

Hunter Disposal — Typically, Marcellus Shale wells produce significant amounts of water that, in most cases, require disposal. Producers often remove the water in trucks for proper disposal in approved facilities. While this method has been the only option to many producers in the Appalachian Basin, it adds a significant operating burden and increases costs. Our subsidiary, Hunter Disposal LLC, owns and operates a salt water disposal facility located in Ohio, with current capacity of approximately 120,000 barrels of water per month. Additionally, Hunter Disposal owns and operates a second commercial salt water disposal facility located in the Primrose Field in Lee County, Kentucky. This disposal facility averages 45,000 barrels of water per month. This facility has a capacity for increased disposal up to 60,000 barrels of water per month with minimal capital requirements. In addition to utilizing our disposal facilities to reduce our operating costs and more importantly provide a cost-efficient option to dispose of water generated from our Marcellus Shale drilling program, we market our disposal capabilities to third party operators.

 

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) Texas, including substantial acreage in the Eagle Ford Shale area; (iii) the Williston Basin in North Dakota; and (iv) southern Louisiana. Cawley, Gillespie & Associates, Inc., independent petroleum consultants, which we refer to as CGA, has estimated our oil and natural gas reserves and the present value of future net revenues therefrom as of December 31, 2010. Those estimates were determined based on prices and costs as of or for the twelve month period ended December 31, 2010. Since January 1, 2010, 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.

 

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.

 

 

The table below summarizes our proved reserves, based on NYMEX futures strip pricing as of December 31, 2010.

 

 

All of our reserves are located within the continental United States. Reserve estimates are inherently imprecise and remain subject to revisions based on production history, results of additional exploration and development, prices of oil and natural gas and other factors. Please read “Item 1A. Risk Factors — Our estimated reserves are based on many assumptions that may turn out to be inaccurate. Any significant inaccuracies in these reserve estimates or underlying assumptions may materially affect the quantities and present value of our reserves”. You should also read the notes following the table below and our consolidated financial statements for the year ended December 31, 2010 in conjunction with the following reserve estimates.

 

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

 

 

 

 

As of December 31, 2010, our proved undeveloped reserves on an SEC basis totaled 3.1 mmbo of crude oil and 20.6 bcf of natural gas for a total of 6.5 mmboe. Changes in PUDs that occurred during the year were due to increased drilling activity in our Eagle Ford Shale and Marcellus Shale areas of operation.

 

The following table summarizes the changes in our proved reserves for the year ended December 31, 2010:

 

 

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:

 

 

 

Reserve Estimation

 

CGA evaluated our oil and gas reserves on a consolidated basis as of December 31, 2010. 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 does 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 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 periodically throughout the year to discuss the assumptions and methods used in the proved reserve estimation process. We provide historical information to CGA 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, 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 35 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 28 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, 2010.

 

 

 

 

 

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

 

 

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

 

 

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.

 

 

 

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 production expense attributable to our oil and gas production for the periods indicated. 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 both periods.

 

 

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:

 

 

 

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.

 

PART II

 

 

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 NSYE Amex for each quarterly period for the last two fiscal years. On February 15, 2011, the last reported sale price of our common stock, as reported on the NYSE, was $6.86 per share.

 

 

Holders

 

On February 16, 2011, based on information from our transfer agent, Nevada Agency and Transfer Company, the number of holders of record of our common stock was 154. Effective February 21, 2011, American Stock Transfer & Trust Company, LLC will become the transfer agent for both our common stock and Series C Preferred Stock.

 

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 senior credit facility. It is anticipated that earnings, if any, will be retained for the future operation of our business.

Securities Authorized for Issuance Under Equity Compensation Plans

 

The following table provides information with respect to our common shares issuable under our equity compensation plans as of December 31, 2010:

 

 

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 9 to our consolidated financial statements.

 

Recent Sales of Unregistered Securities

 

During the year ended December 31, 2010, the Company sold from time to time an aggregate of 7,536,654 shares of its common stock pursuant to the exercise of certain warrants, as follows:

 

(a) The Company sold an aggregate of 5,722,650 shares of common stock pursuant to the exercise of certain warrants issued by the Company in 2005, at an exercise price of $2.00 per share, for total gross proceeds of approximately $11.4 million. 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 251,500 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 $754,500. 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.

 

(c) The Company sold an aggregate of 1,562,504 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 $3.9 million. 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:

 

(a) On May 12, 2010, the Company issued 7,500 shares of common stock to a former employee of the Company pursuant to his exercise of a stock option granted to him under the Company’s stock incentive plan. The Company received proceeds from the exercise of $8,775.

 

(b) On February 3, 2010 and May 26, 2010, the Company issued an aggregate of 30,869 and 15,193 shares, respectively, of common stock to its non-management directors as payment of meeting fees owed to the directors for attendance at board and committee meetings. These shares were issued under the Company’s stock incentive plan.

(c) On June 7, 2010, the Company issued 1,000,000 shares of common stock pursuant to the conversion by a shareholder of 1,000,000 shares of the Company’s Series B Convertible Preferred Stock, in accordance with the terms of the preferred stock.

 

All 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.

 

Repurchases of Common Stock

 

During September 2010, the Company purchased an aggregate of 153,300 shares of its common stock in the open market at an average purchase price of $3.94 per share to be used to fund potential future common stock contributions to employees of the Company and its subsidiaries pursuant to the Company’s 401(k) Employee Stock Ownership Plan.

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, 2010 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, 2005, and that dividends were reinvested.

 

COMPARISON OF 5 YEAR CUMULATIVE TOTAL RETURN