MAGNUM HUNTER RESOURCES CORP - FORM 10-K/A

Attached files

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EX-32.2 - CERTIFICATION - MAGNUM HUNTER RESOURCES CORP	magnum_ex3202.htm
EX-31.2 - CERTIFICATION - MAGNUM HUNTER RESOURCES CORP	magnum_ex3102.htm
EX-31.1 - CERTIFICATION - MAGNUM HUNTER RESOURCES CORP	magnum_ex3101.htm
EX-32.1 - CERTIFICATION - MAGNUM HUNTER RESOURCES CORP	magnum_ex3201.htm
EX-23.3 - CONSENT - MAGNUM HUNTER RESOURCES CORP	magnum_ex2303.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K/A

(Amendment No. 1)


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

For the fiscal year ended December 31, 2010

Commission file number: 001-32997

Magnum Hunter Resources Corporation

(Name of registrant as specified in its charter)


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

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

(Address of principal executive offices, including zip code)

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

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


Title of each class:		Name of each exchange on which registered:
$0.01 par value Common Stock 10.25% Series C Cumulative Perpetual Preferred Stock		NYSE NYSE Amex

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

None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes 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):


Large accelerated filer o		Accelerated filer þ		Non-accelerated filer o		Smaller reporting company o

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 March 11, 2011, 76,452,804 shares of the registrant’s common stock were issued and outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

The information required by Part III of the Form 10-K, to the extent no set forth herein, is incorporated herein by reference from the registrant’s definitive proxy statement for the 2011 Annual Meeting of Stockholders, to be filed with the Securities and Exchange Commission pursuant to Regulation 14A not later than 120 days after the close of the registrant’s fiscal year.

Explanatory Note

This Amendment No. 1 to Form 10-K (this “Amendment”) amends Magnum Hunter Resources Corporation’s (the “Company”) Annual Report on Form 10-K for the year ended December 31, 2010 (the “Original 10-K”) which was filed with the Securities and Exchange Commission (the “Commission”) on February 18, 2011. The Company is filing this Amendment for the sole purpose of replacing in its entirety Item 2 – Properties of the Original 10-K and to file or furnish certain updated exhibits.

Item 2 – Properties is being amended to:

·	Add disclosure regarding our delivery commitments;

·	Add disclosure regarding the net quantities of oil and gas produced and sold by the Company for each of the previous three years ended December 31st and the average sales price per unit and average production cost per unit in connection therewith;

·	Add disclosure regarding the number of wells that are in the process of being drilled or completed;

·	Update certain reconciliation information with respect to non-GAAP financial information that was previously reported in a Current Report on Form 8-K; and

·	Provide certain additional information regarding our drilling activities that appears in the second to last paragraph of the section titled “Appalachian Basin/Marcellus Shale.”

Certain exhibits have been updated and are being filed or furnished with this Amendment to:

·	Provide an updated consent of our independent petroleum engineer; and

·	Provide the required certifications by our principal executive officer and principal financial officer.

Except as described above, no other changes have been made to the Original 10-K. The Original 10-K continues to speak as of the date of the original filing, and the Company has not updated the disclosures contained therein to reflect any events which occurred subsequent to the filing of the Original 10-K, or to modify the disclosure contained in the Original 10-K other than to reflect the changes described above.

This Amendment should be read in conjunction with the Company’s filings with the Commission made subsequent to the date of the original filing.

PART I

Item 2. PROPERTIES

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.

On January 25, 2011, NGAS and Triad Hunter entered into a participation agreement and related operating agreement for two horizontal wells required under an existing NGAS drilling commitment under a lease covering approximately 27,000 acres in the Amvest field. The participation agreement provides that the wells are to be drilled by NGAS for the account of Triad Hunter at cost, with NGAS receiving an overhead fee of $50,000 per well and Magnum Hunter receiving a put option on the wells, at cost.

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 Furrh #1-H well in early February 2011. This well is located in Gonzalez County. The Company operates the Furrh #1-H well and owns a 50% working interest.

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. We currently do not have any delivery commitments with regard to our future oil and gas production. 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.

	Net Reserves (SEC Prices at 12/31/10)
Category	Oil		NGL		Gas		PV-10
	(mbbls)		(barrels)		(mmcf)		($mm)

Proved Developed		3,720		—		18,888	$	111.8
Proved Undeveloped		3,104		—		20,564	$	66.0
Total Proved		6,824		—		39,452	$	177.8

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

	Net Reserves (Based on NYMEX Futures Prices at 12/31/10)
Category	Oil		NGL		Gas		PV-10
	(mbbls)		(barrels)		(mmcf)		($mm)

Proved Developed		3,975		—		20,577	$	144.9
Proved Undeveloped		3,632		—		21,167	$	97.7
Total Proved		7,607		—		41,744	$	242.6

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:

	2010		2009		2008

Description
Proved Developed Reserves
Oil (bbls)		3,720,300		1,694,700		1,092,730
NGLs (bbls)		—		361,000		301,577
Natural Gas (mcf)		18,887,700		4,952,500		2,549,496
Proved Undeveloped Reserves
Oil (bbls)		3,104,000		2,126,800		769,309
NGLs (bbls)		—		426,000		245,636
Natural Gas (mcf)		20,564,200		4,411,700		1,703,450
Total Proved Reserves (boe)(1)(2)		13,399,700		6,169,200		3,118,076

PV-10 Value ($mm)(3)	$	177.8	$	65.6	$	21.0
Standardized Measure ($mms)	$	128.0	$	47.4	$	15.6

_________________

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

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

(3)		Represents the present value, discounted at 10% per annum (PV-10), of estimated future cash flows before income tax of our estimated proved reserves. The estimated future cash flows set forth above were determined by using reserve quantities of proved reserves and the periods in which they are expected to be developed and produced based on prevailing economic conditions. The estimated future production is priced based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for the period January through December 2010, using $79.43 per bbl and $4.37 per mmbtu and adjusted by lease for transportation fees and regional price differentials. Management believes that the presentation of the non-GAAP financial measure of PV-10 provides useful information to investors because it is widely used by professional analysts and sophisticated investors in evaluating oil and natural gas companies.

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:

	For the Year Ended
Proved Reserves (mboe)	December 31, 2010

Proved reserves — beginning of year		6,169.2
Revisions of previous estimates		(22.2	)
Improved recovery		0.0
Extensions and discoveries		3,194.1
Production		(588.9	)
Purchases of reserves in place		7,037.1
Sales of reserves in place		(2,389.6	)
Proved reserves — end of year		13,399.7
Proved developed reserves — beginning of year		2,880.7
Proved developed reserves — end of year		5,842.4

Recent SEC Rule-Making Activity

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

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

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

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

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

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

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

Reserve Estimation

CGA 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.

	Developed				Undeveloped
	Acreage(1)				Acreage(2)				Total Acreage
	Gross		Net		Gross		Net		Gross		Net

Appalachia		70,803		62,652		110,449		33,723		181,252		96,375
North Dakota		15,200		6,536		3,411		1,116		18,611		7,652
Texas		6,993		1,916		51,152		24,229		58,145		26,145
Other		714		443		90,000		8,866		90,714		9,309
Total		93,710		71,547		255,012		67,934		348,722		139,481

______________

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

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

	Producing				Producing				Total Producing
	Oil Wells				Gas Wells				Wells
	Gross		Net		Gross		Net		Gross		Net

Appalachia		1,398.0		1,375.6		692.0		638.6		2,090.0		2,014.2
North Dakota		151.0		70.9		0.0		0.0		151.0		70.9
Texas		4.0		2.8		15.0		2.2		19.0		5.0
Other		2.0		1.3		0.0		0.0		2.0		1.3
Total		1,555		1,451		707		641		2,262		2,091

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

Year Ending	Expiring Acreage
December 31,	Gross		Net

2011		12,425		8,848
2012		20,267		12,687
2013		25,865		20,757
2014		31,156		21,864
Total		89,713		64,156

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.

	2010						2009						2008
	Gross			Net			Gross			Net			Gross			Net

Exploratory Wells:
Productive		8			6.67			3			0.70			25			2.45
Unproductive		0			0.00			1			0.10			11			2.20
Total		8			6.67			4			0.80			36			4.65
Developmental Wells:		67			6.70			27			3.80			8			1.41
Total Wells:
Productive		75			13.37			30			4.50			33			3.86
Unproductive		0			0.00			1			0.10			0			0.00
Total		75			13.37			31			4.60			33			3.86
Success Ratio(1)		100.0	%		100.0	%		96.8	%		97.8	%		100.0	%		100.0	%

(1)

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

As of February 15, 2011, we had 1 gross (0.5 net) wells in the process of drilling or completing.

Oil and Gas Production, Prices and Costs

The following table shows the approximate net production attributable to our oil and gas interests, the average sales price and the average lease operating expense attributable to our total oil and gas production and for certain segments of our operations as required by SEC rules. Production and sales information relating to properties acquired is reflected in this table only since the closing date of the acquisition and may affect the comparability of the data between the periods presented. Property disposed of that is treated as discontinued operations has been excluded from such periods.

	Years Ended December 31,
	2010	2009	2008
Sistersville(1)
Oil Production (Bbls)	3,896.0	-	-
Natural Gas Production (Mcf)	256,157.0	-	-
NGL Production (Bbls)	-	-	-
Total Production (Boe)	46,588.8	-	-
Oil Average Sales Price	$71.80	-	-
Natural Gas Average Sales Price	$5.91	-	-
NGL Average Sales Price	-	-	-
Average Lease Operating Expense per Boe	$10.59	-	-

Mohall(2)
Oil Production (Bbls)	38,034.7	29,532.1	22,748.0
Natural Gas Production (Mcf)	-	-	-
NGL Production (Bbls)	-	-	-
Total Production (Boe)	38,034.7	29,532.1	22,748.0
Oil Average Sales Price	$69.70	$55.30	$85.32
Natural Gas Average Sales Price	-	-	-
NGL Average Sales Price	-	-	-
Average Lease Operating Expense per Boe	$22.96	$20.79	$28.26

Total Company
Oil Production (Bbls)	316,119.6	114,590.0	110,718.9
Natural Gas Production (Mcf)	952,174.7	191,151.0	130,370.5
NGL Production (Bbls)	-	-	-
Total Production (Boe)	474,817.3	146,449.0	132,447.4
Oil Average Sales Price	$72.41	$53.56	$86.92
Natural Gas Average Sales Price	$5.07	$2.46	$4.36
NGL Average Sales Price	-	-	-
Average Lease Operating Expense per Boe	$21.90	$26.48	$30.42

(1) These properties were part of the assets acquired from Triad Energy in 2010, which are located in West Virginia.
(2) These properties are part of our non-operated properties in the Williston Basin in North Dakota.

Title to Properties

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

customary royalty interests;

liens incident to operating agreements and for current taxes;

obligations or duties under applicable laws;

development obligations under oil and gas leases;

net profit interests;

overriding royalty interests;

non-surface occupancy leases; and

lessor consents to placement of wells.

Non-GAAP Measures: Reconciliation to Standardized Measure

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

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

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

	(Unaudited) As of December 31,
	2010

Future cash inflows	$	709,788
Future production costs		(253,544	)
Future development costs		(77,216	)
Future income tax expense		(88,233	)
Future net cash flows		290,795
10% annual discount for estimated
timing of cash flows		(162,836	)
Standardized measure of discounted future
net cash flows related to proved reserves	$	127,959

Reconciliation of Non-GAAP Measure
PV-10	$	177,814
Less: Income taxes
Undiscounted future income taxes		(88,233	)
10% discount factor		38,378
Future discounted income taxes		(49,855	)

Standardized measure of discounted future net cash flows	$	127,959

PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES

Exhibits: The exhibits listed below are filed or incorporated by reference as part of this report.

Exhibit Number		Description
3.1(1)		Restated Certificate of Incorporation of the Registrant, filed February 13, 2002
3.1.1(1)		Certificate of Amendment of Certificate of Incorporation of the Registrant, filed May 8, 2003
3.1.2(1)		Certificate of Amendment of Certificate of Incorporation of the Registrant, filed June 6, 2005
3.1.3(4)		Certificate of Amendment of Certificate of Incorporation of the Registrant, filed July 18, 2007
3.1.4(7)		Certificate of Ownership and Merger Merging Magnum Hunter Resources Corporation with and into Petro Resources Corporation, filed July 13, 2009
3.1.5(22)		Certificate of Amendment of Certificate of Incorporation of the Registrant, filed November 3, 2010
3.2(1)		Amended and Restated Bylaws of the Registrant, dated March 15, 2001
3.2.1(2)		Amendment to Bylaws of the Registrant, dated April 14, 2006
3.2.2(5)		Amendment to Bylaws of the Registrant, dated October 12, 2006
4.1		Form of certificate for common stock##
4.2(13)		Certificate of Designation of Rights and Preferences of 10.25% Series C Cumulative Perpetual Preferred Stock, dated December 10, 2009
4.2.1(16)		Certificate of Amendment of Certificate of Designation of Rights and Preferences of 10.25% Series C Cumulative Perpetual Preferred Stock, dated August 2, 2010
4.2.2(20)		Certificate of Amendment of Certificate of Designation of Rights and Preferences of 10.25% Series C Cumulative Perpetual Preferred Stock, dated September 8, 2010
10.1(15)		Employment Agreement between the Registrant and James W. Denny, dated May 27, 2008*
10.2(6)		Employment Agreement between the Registrant and Gary C. Evans, dated May 22, 2009*
10.3(6)		Stock Option Agreement between the Registrant and Gary C. Evans, dated May 22, 2009*
10.4(6)		Restricted Stock Agreement between the Registrant and Gary C. Evans, dated May 22, 2009*
10.5(6)		Employment Agreement between the Registrant and Ronald D. Ormand, dated May 22, 2009*
10.6(6)		Stock Option Agreement between the Registrant and Ronald D. Ormand, dated May 22, 2009*
10.7(6)		Restricted Stock Agreement between the Registrant and Ronald D. Ormand, dated May 22, 2009*
10.8		Employment Agreement between the Registrant and H.C. “Kip” Ferguson, dated October 1, 2009*##
10.9		Resignation and General Release Agreement between the Registrant and Wayne P. Hall, dated December 22, 2010##
10.10(25)		Amended and Restated Stock Incentive Plan of Registrant*
10.11		Form of Stock Option Agreement under the Registrant’s Amended and Restated Stock Incentive Plan*##
10.12(25)		Form of Restricted Stock Award Agreement under the Registrant’s Amended and Restated Stock Incentive Plan*
10.13(25)		Form of Stock Appreciation Right Agreement under the Registrant’s Amended and Restated Stock Incentive Plan*
10.14(1)		Lease Purchase Agreement between the Registrant and The Meridian Resource & Exploration, LLC, dated January 10, 2006
10.15(1)		Form of Registration Rights Agreement for $3.00 warrants sold as part of the Registrant’s February 2006 private placement, dated February 17, 2006
10.16(1)		Form of $3.00 Warrant sold as part of February 2006 private placement
10.17(3)		Purchase and Sale Agreement between the Registrant and Eagle Operating, Inc., dated December 11, 2006
10.18		First Amendment to Purchase and Sale Agreement between the Registrant and Eagle Operating, Inc., dated January 25, 2007##
10.19(8)		Agreement and Plan of Merger between the Registrant, Sharon Hunter, Inc., Sharon Resources, Inc. and Sharon Energy Ltd., dated September 9, 2009
10.20(8)		Purchase and Sale Agreement between the Registrant and Centurion Exploration Company, LLC, dated September 14, 2009
10.21(9)		Asset Purchase Agreement between the Registrant and Triad Energy Corporation, dated October 28, 2009
10.22(10)		Form of Securities Purchase and Registration Rights Agreement with respect to November 5, 2009 offering
10.23(10)		Form of $2.50 Warrant with respect to the Registrant’s November 5, 2009 offering
10.24(11)		Placement Agency Agreement with respect to the Registrant’s November 10, 2009 offering, dated November 10, 2009
10.25(11)		Placement Agency Agreement with respect to the Registrant’s November 11, 2009 offering, dated November 11, 2009
10.26(11)		Form of $2.50 Warrant with respect to the Registrant’s November 10 and 11, 2009 offerings
10.27(12)		Underwriting Agreement between the Registrant and Wunderlich Securities, Inc., dated December 9, 2009
10.28(14)		Amended and Restated Credit Agreement between the Registrant, Bank of Montreal, Capital One, N.A., BMO Capital Markets and Capital One, N.A and the lenders party thereto, dated February 12, 2010+
10.29(17)		First Amendment to Amended and Restated Credit Agreement between the Registrant, Bank of Montreal, Capital One, N.A., and the lenders party thereto, dated May 13, 2010

Exhibit Number		Description
10.30(18)		At the Market Sales Agreement for Series C Preferred Stock between the Registrant and McNicoll, Lewis & Vlak LLC, dated June 22, 2010
10.31(19)		At the Market Sales Agreement for common stock between the Registrant and McNicoll, Lewis & Vlak LLC, dated June 25, 2010
10.32(21)		Limited Waiver of Credit Agreement Provisions, between the Registrant and Bank of Montreal and Capital One, N.A., dated September 24, 2010
10.33(23)		Purchase and Sale Agreement between the Registrant and Approach Oil & Gas Inc., dated October 29, 2010+
10.34(24)		At the Market Sales Agreement for common stock between the Registrant and McNicoll, Lewis and Vlak, LLC, dated November 12, 2010
10.35(24)		At the Market Sales Agreement for Series C Preferred Stock between the Registrant and McNicoll, Lewis and Vlak, LLC, dated November 12, 2010
10.36(26)		Second Amendment to Amended and Restated Credit Agreement and Waiver between the Registrant, Bank of Montreal, Capital One, N.A., and the guarantors and lenders party thereto, dated November 30, 2010+
10.37(27)		Arrangement Agreement between the Registrant and NGAS Resources, Inc., dated December 23, 2010+
10.38(27)		Form of Support Agreement between the Registrant and certain NGAS Resources, Inc. shareholders, dated December 23, 2010
10.39(28)		Purchase and Sale Agreement between the Registrant, Quest Eastern Resource LLC and PostRock MidContinent Production, LLC, dated December 24, 2010+@
10.40(29)		Arrangement Agreement between the Registrant and NuLoch Resources Inc., dated January 19, 2011(including Form of Support Agreement between the Registrant and certain NuLoch Resources Inc. shareholders)+
21.1		List of Subsidiaries##
23.1		Consent of Hein & Associates LLP##
23.2		Consent of MaloneBailey, PC##
23.3		Consent of Cawley Gillespie & Associates, Inc#
31.1		Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002#**
31.2		Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002#**
32.1		Certification of the Chief Executive Officer provided pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002#
32.2		Certification of the Chief Financial Officer provided pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002#
99.1		Independent Engineer Reserve Report for the year ended December 31, 2010 prepared by Cawley Gillespie & Associates, Inc.# #

__________________

*		The referenced exhibit is a management contract, compensatory plan or arrangement.

+		The schedules to this exhibit have been omitted pursuant to Item 601(b)(2) of Regulation S-K and will be provided to the SEC upon request.

@		Portions of this exhibit are subject to a request for confidential treatment and have been redacted and filed separately with the SEC.

#		Filed herewith.

##		Filed or furnished as an Exhibit to our Original Form 10-K filed on February 18, 2011.

**		Our original certifications pursuant to Rule 13a-14(a) and Rule 14d-14(a) are filed with the Original Form 10-K filed on February 18, 2011. The certifications filed with this Amendment are limited to the matters addressed herein.

(1)		Incorporated by reference from the Registrant’s Registration Statement on Form SB-2 filed on March 21, 2006.

(2)		Incorporated by reference from the Registrant’s Amendment No. 1 to Registration Statement on Form SB-2 filed on June 9, 2006.

(3)		Incorporated by reference from the Registrant’s annual report on Form 10-KSB for the year ended December 31, 2006, filed on April 2, 2007.

(4)		Incorporated by reference from the Registrant’s quarterly report on Form 10-QSB filed on August 14, 2007.

(5)		Incorporated by reference from the Registrant’s Amendment No. 1 to Registration Statement on Form SB-2 filed on September 21, 2007.

(6)		Incorporated by reference from the Registrant’s current report on Form 8-K filed on May 28, 2009.

(7)		Incorporated by reference from the Registrant’s current report on Form 8-K filed on July 14, 2009.

(8)		Incorporated by reference from the Registrant’s current report on Form 8-K filed on September 15, 2009.

(9)		Incorporated by reference from the Registrant’s current report on Form 8-K filed on October 29, 2009.

(10)		Incorporated by reference from the Registrant’s current report on Form 8-K filed on November 6, 2009.

(11)		Incorporated by reference from the Registrant’s current report on Form 8-K filed on November 13, 2009.

(12)		Incorporated by reference from the Registrant’s current report on Form 8-K filed on December 11, 2009.

(13)		Incorporated by reference from the Registrant’s Registration Statement on Form 8-A filed on December 10, 2009.

(14)		Incorporated by reference from the Registrant’s current report on Form 8-K filed on February 19, 2010.

(15)		Incorporated by reference from the Registrant’s annual report on Form 10-K filed on March 31, 2009.

(16)		Incorporated by reference from the Registrant’s quarterly report on Form 10-Q filed on August 12, 2010.

(17)		Incorporated by reference from the Registrant’s current report on Form 8-K filed on May 19, 2010.

(18)		Incorporated by reference from the Registrant’s current report on Form 8-K filed on June 24, 2010.

(19)		Incorporated by reference from the Registrant’s current report on Form 8-K filed on June 25, 2010.

(20)		Incorporated by reference from the Registrant’s current report on Form 8-K filed on September 15, 2010.

(21)		Incorporated by reference from the Registrant’s current report on Form 8-K filed on September 30, 2010.

(22)		Incorporated by reference from the Registrant’s current report on Form 8-K filed on November 2, 2010.

(23)		Incorporated by reference from the Registrant’s current report on Form 8-K filed on November 4, 2010.

(24)		Incorporated by reference from the Registrant’s current report on Form 8-K filed on November 15, 2010.

(25)		Incorporated by reference from the Registrant’s current report on Form 8-K filed on December 3, 2010.

(26)		Incorporated by reference from the Registrant’s current report on Form 8-K filed on December 6, 2010.

(27)		Incorporated by reference from the Registrant’s current report on Form 8-K filed on December 30, 2010.

(28)		Incorporated by reference from the Registrant’s current report on Form 8-K/A filed on March 2, 2011.

(29)		Incorporated by reference from the Registrant’s current report on Form 8-K filed on January 25, 2011.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this Amendment No. 1 to its annual report to be signed on its behalf by the undersigned, thereunto duly authorized.


	MAGNUM HUNTER RESOURCES CORPORATION
Date: March 15, 2011	By:	/s/ Gary C. Evans
		Gary C. Evans
		Chairman of the Board and Chief Executive Officer

MAGNUM HUNTER RESOURCES CORP - FORM 10-K/A - March 15, 2011

Attached files

MAGNUM HUNTER RESOURCES CORP Reports