Magnum Hunter Resources 10K/A 2013 Annual report (amended)

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

____________________________________

Form 10-K/A


x	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 2013

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 incorporation or organization)	(I.R.S. Employer Identification No.)

777 Post Oak Boulevard, Suite 650, Houston, Texas 77056
(Address of principal executive offices, including zip code)

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

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



Title of Each Class	Name of Each Exchange on Which Registered

Common Stock, par value $.01 per share 10.25% Series C Cumulative Perpetual Preferred Stock 8.0% Series D Cumulative Preferred Stock Depositary Shares, each representing a 1/1,000 interest in a share of 8.0% Series E Cumulative Convertible Preferred Stock	NYSE NYSE MKT NYSE MKT NYSE MKT

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 ¨ No x

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

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 x No ¨

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

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

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



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

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

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: $585,926,716

As of February 18, 2014, 171,910,067 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, 2013 are incorporated by reference into Part III of this Form 10-K.

EXPLANATORY NOTE

This Form 10-K/A (this “Amendment”) amends Magnum Hunter Resources Corporation’s (the “Company”) annual report on Form 10-K for the year ended December 31, 2013, as amended (the “Original 10-K”), which was filed with the Securities and Exchange Commission (the “Commission”) on February 25, 2014 and amended on March 18, 2014 and March 31, 2014. The Company is filing this Amendment solely in response to comments received from the staff of the Commission in connection with the staff’s review of certain resale registration statements filed by the Company with the Commission under the Securities Act of 1933 for the resale by certain stockholders of common stock issued to them by the Company in private placements. In response to those comments, the Company is amending the Original 10-K to:

•

provide additional disclosures regarding (a) initial production rates from the Company’s wells, as of the dates set forth in the Original 10-K, (b) changes in the Company’s proved undeveloped reserves, as of the dates or for the periods set forth in the Original 10-K and (c) the technical qualifications of the person primarily responsible for preparing the Company’s reserve report referenced in the Original 10-K, under the headings “Our Company, ” “Our Operations” and “Reserves”, respectively, in Part I, Item 1. Business;


•	provide additional disclosures regarding the Company’s proved reserves, as of the dates set forth in the Original 10-K, in the “Supplemental Oil and Gas Disclosures (Unaudited)” in the notes to the Company’s financial statements in Part II, Item 8. Financial Statements and Supplementary Data;


•	provide additional disclosures regarding the determination of certain elements of the Company’s 2013 executive compensation under the heading “Our Compensation Philosophy” in Part III, Item 11. Executive Compensation; and


•	file a revised exhibit 99.1 (Independent Engineer Reserve Report for the year ended December 31, 2013 prepared by Cawley Gillespie & Associates, Inc.) to include additional disclosures regarding the technical qualifications of the person primarily responsible for preparing the reserve report.

In accordance with Rule 12b-15 under the Securities Exchange Act of 1934, this Amendment sets forth the complete text of Part I, Item 1. Business, Part II, Item 8. Financial Statements and Supplementary Data, and Part III, Item 11. Executive Compensation as amended by this Amendment.

This Amendment speaks as of the original filing date of the Original 10-K and reflects only the changes to the Original 10-K described above. No other information included in the Original 10-K has been modified or updated in any way, and the Company has not updated the disclosures contained herein 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.

The Company also has included as exhibits to this Amendment the certifications required under Sections 302 and 906 of the Sarbanes-Oxley Act of 2002.

This Amendment should be read in conjunction with the Company’s filings with the Commission made subsequent to February 25, 2014, the date of the original filing of the Original 10-K.


Item 1.	BUSINESS

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, a Delaware corporation, and its consolidated subsidiaries. We have provided definitions for some of the oil and natural gas industry terms used in this annual report under “Glossary of Oil and Natural Gas Terms” at the end of this “Business” section of this annual report.

Our Company

We are an independent oil and natural gas company engaged in the exploration for and the exploitation, acquisition, development and production of crude oil, natural gas and natural gas liquids resources in the United States. We are active in what we believe to be three of the most prolific unconventional shale resource plays in the United States, specifically, the Marcellus Shale in West Virginia and Ohio; the Utica Shale in southeastern Ohio and western West Virginia; and the Williston Basin/Bakken Shale in North Dakota. Our core oil and natural gas reserves and operations are primarily concentrated in West Virginia, Ohio and North Dakota. We are also engaged in midstream and oil field services operations, primarily in West Virginia and Ohio.

Since our current management team assumed leadership of our Company in May 2009 and refocused our business strategy, we have substantially increased our assets and production base through a combination of acquisitions, joint ventures and ongoing development drilling efforts on acquired acreage. We believe the increased scale in our core resource plays allows for ongoing cost recovery and production efficiencies as we exploit and monetize our asset base.

Our business strategy is to create significant value for our stockholders by growing reserves, production volumes and cash flow at an attractive rate of return through a combination of efficient development of our properties and strategic acquisitions and joint ventures, and to selectively monetize properties at opportune times and attractive prices. As part of our strategy:

•

We have approved a $400 million capital expenditure budget for fiscal year 2014, excluding acquisitions. We have allocated approximately $260 million in the Utica Shale and Marcellus Shale plays, approximately $50 million in the Williston Basin and approximately $90 million (net to our majority interest) for midstream operations. We expect this Appalachian-focused capital program to further drive our future production volumes and reserve additions and enable us to achieve our 2014 projected exit production rate of 35,000 Boe/d;


•	We have recently completed in excess of $500 million in divestitures, including sales of our Eagle Ford Shale properties in south Texas and certain non-core North Dakota properties (see “—Our Significant Recent Developments”);


•	We are actively marketing our southern Appalachian Basin properties located in Kentucky and Tennessee and our Canadian properties located in Saskatchewan and Alberta pursuant to a plan to divest those assets adopted in September 2013 (see “Management's Discussion and Analysis of Financial Condition and Results of Operations—Business Overview”); and


•	We have identified a number of other non-core U.S. upstream properties for possible divestiture in 2014 that we believe represent (together with the planned southern Appalachian Basin and Canada divestitures described above) in excess of $400 million in value.

As a result of our recent and planned divestitures, we are now strategically focused on our Marcellus Shale and Utica Shale plays in the Appalachian Basin in West Virginia and Ohio and our Bakken Shale play in the Williston Basin in North Dakota.

Appalachian Basin / Marcellus Shale and Utica Shale / West Virginia and Ohio

Appalachian Basin. Our Appalachian Basin drilling operations are focused on development in the liquids rich Marcellus Shale and Utica Shale underlying West Virginia and Ohio. We initially entered the Appalachian Basin through an asset acquisition in February 2010 and have subsequently expanded our operations through various acquisitions and joint ventures and development drilling efforts.

Marcellus Shale. As of January 31, 2014, we had a total of approximately 78,709 net leasehold acres in the Marcellus Shale. Our Marcellus Shale acreage is located principally in Tyler, Pleasants, Ritchie, Wetzel and Lewis Counties, West Virginia and in Washington and Monroe Counties, Ohio. As of January 31, 2014, we had (a) 35 horizontal wells (27.5 net) producing in the Marcellus Shale (including non-operated wells) and (b) 14 horizontal wells (7.9 net) awaiting completion, one horizontal well (one net) drilling, and one drilling rig operating on our Company-operated Marcellus Shale properties. As of January 31, 2014, approximately 76% of our mineral leases in the Marcellus Shale area were held by production. As of January 31, 2014, our five most recently completed Company-operated horizontal wells targeting the Marcellus Shale generated approximately 12,158 Mcfe/d (8,794 Mcfe/d wet gas and 3,364 Mcfe/d condensate) and 7,005 Mcfe/d (5,618 Mcfe/d wet gas and 1,387 Mcfe/d condensate) average IP-24 hour and IP-30 day rates, respectively.

Utica Shale. As of January 31, 2014, we had a total of approximately 99,078 net leasehold acres prospective for the Utica Shale. Approximately 63,877 of the net acres are located in Ohio (a portion of which acreage overlaps our Marcellus Shale acreage), and approximately 35,201 of the net acres are located in West Virginia (a portion of which acreage overlaps our Marcellus Shale acreage).

Our Utica Shale acreage is located principally in Tyler, Pleasants and Wood Counties, West Virginia and in Washington, Monroe, Morgan and Noble Counties, Ohio. We believe approximately 36,500 of our Utica Shale net acres are located in the wet gas window of the play. As of January 31, 2014, we had two horizontal wells (1.5 net) awaiting completion, one horizontal well (one net) drilling, and one drilling rig operating on our Company-operated Utica Shale properties. Approximately 65% of our acreage in the Utica Shale is held by shallow production. Our first dry gas Utica Shale well located on the Stalder Pad in Monroe County, Ohio, was placed on production on February 9, 2014 and tested at a peak rate of 32.5 MMcf of natural gas per day. The Stalder #3UH well was drilled and cased to a true vertical depth of 10,653 feet with a 5,050 foot horizontal lateral and successfully fraced with 20 stages.

Our 2014 capital expenditure budget includes approximately $260 million of capital expenditures in the Appalachian Basin, essentially all in the Marcellus Shale and Utica Shale regions. We intend to drill a total of approximately 25 gross horizontal wells in the Marcellus Shale and Utica Shale in 2014.

Williston Basin / Bakken Shale / North Dakota

As of January 31, 2014, our Williston Basin properties in the United States, or Williston Basin U.S., included approximately 102,869 net acres in the Bakken/Three Forks Sanish formations in North Dakota. Our Williston Basin U.S. acreage is located in Divide County, North Dakota. As of January 31, 2014, we had 255 wells (61 net) producing, 4 wells (1.4 net) awaiting completion, 5 wells (1.4 net) drilling, and 2 drilling rigs operating on our Bakken/Three Forks Sanish properties in North Dakota. As of January 31, 2014, our five most recently completed Company-operated one-mile horizontal wells in Divide County, North Dakota generated an average IP-24 hour rate of approximately 475 Boe/d, and our five most recently completed third-party operated two-mile horizontal wells in Divide County, North Dakota generated an average IP-24 hour rate of approximately 408 Boe/d.

Our 2014 capital expenditure budget includes approximately $50 million of capital expenditures in the Williston Basin/Bakken Shale in North Dakota. We expect these capital expenditures to relate primarily to the drilling of wells in which we participate as a non-operated working interest owner. We anticipate these wells will include approximately 20 gross wells located primarily in the Ambrose Field in Divide County, North Dakota.

Midstream Operations

Our midstream operations are conducted through our majority-owned subsidiary, Eureka Hunter Holdings, LLC, or Eureka Hunter Holdings. Eureka Hunter Pipeline, LLC, or Eureka Hunter Pipeline, a subsidiary of Eureka Hunter Holdings, owns and operates a gas gathering system in West Virginia and Ohio, referred to as our Eureka Hunter Gas Gathering System. We are also engaged in the business of leasing natural gas treating plants to third-party producers in Texas and other states through a separate subsidiary, TransTex Hunter, LLC. We have obtained financing for our midstream operations through an equity purchase commitment from an unaffiliated third party, which also gives us the right to make capital contributions in conjunction with or alongside the capital contributions from the third party, and two separate credit facilities on a non-recourse basis to Magnum Hunter Resources Corporation.

Our midstream pipeline is a strategic asset to the development and delineation of our acreage position in the both the Utica Shale and Marcellus Shale plays. We believe that we have a competitive advantage by being vertically integrated and maintaining control of our natural gas gathering activities. From time to time, we have discussions with strategic companies in our core area of operations and may pursue joint ventures or other strategic transactions with respect to this asset.

We are continuing the commercial development of the Eureka Hunter Gas Gathering System to support the development of our existing and anticipated future Marcellus Shale and Utica Shale acreage positions, as well as the expanding gas gathering needs of third party producers in these regions. The system is being constructed primarily out of 20-inch and 16-inch high-pressure steel pipe with an estimated 350 MMcf/d of initial throughput capacity. As of January 31, 2014, we had completed the construction of a total of over 100 miles of pipeline as part of the system. See “—Our Significant Recent Developments—Expansion of Eureka Hunter Gas Gathering System.”

As of February 16, 2014, we were flowing approximately 171,000 MMbtus of natural gas per day through the Eureka Hunter Gas Gathering System. We gathered 3.2 Bcf of natural gas during January 2014 with a peak day of approximately 170,000 MMBtu of natural gas delivered to a processing plant located near the town of Mobley in Wetzel County, West Virginia, or the Mobley Processing Plant, owned by MarkWest Liberty Midstream & Resources, L.L.C., or MarkWest, on January 5, 2014. During the first six months of 2014, we expect to gather significant additional natural gas volumes from us and third party producers with production connected to the gathering system. We expect that the Eureka Hunter Gas Gathering System will enable us to continue to develop our substantial natural gas and natural gas liquids resources in the Marcellus Shale and Utica Shale, as well as provide the opportunity for substantial cash flow from the gathering of third party volumes of natural gas.

Our 2014 capital expenditure budget includes approximately $90 million (net to our majority interest) of capital expenditures relating to the Eureka Hunter Gas Gathering System.

Oil Field Services Operations

Our oil field services operations consist of the ownership and operation of six drilling rigs that are used primarily for vertical section (top-hole) air drilling in the Appalachian Basin for us and third parties. Our fleet of rigs includes a robotic walking drilling rig that can also drill the horizontal sections of wells in the shale plays where we are active. This drilling rig was designed especially for pad drilling with its unique footprint and capability to walk and rotate without being dismantled.

Summary of Proved Reserves, Production and Acreage

The oil and natural gas reserves and production information provided below includes reserves and production associated with our southern Appalachian Basin and Canadian properties that we intend to divest, which we have presented as assets held for sale in our December 31, 2013 consolidated balance sheet, as well as reserves and production associated with our Eagle Ford Shale and Pearsall Shale assets that were sold in January 2014.

•

As of December 31, 2013, we had approximately 75.9 MMBoe of estimated proved reserves, of which approximately 45.8% was oil and natural gas liquids and approximately 52.2% was classified as proved developed producing reserves. By comparison, as of December 31, 2012, our estimated proved reserves were approximately 73.1 MMBoe, of which approximately 62.9% was oil and natural gas liquids and approximately 52.0% was classified as proved developed producing reserves. Our estimated proved reserves, on a Boe basis, at year-end 2013 increased 3.9% from year-end 2012.

•

As of December 31, 2013, we had proved reserves with a PV-10 value of $922.1 million. This compares with proved reserves with a PV-10 value of $981.2 million as of December 31, 2012. The PV-10 value of our estimated proved reserves at year-end 2013 decreased 6% from year-end 2012. PV-10 values are different from the standardized measure of proved reserves due to the inclusion in the standardized measure of estimated future income taxes. The standardized measure of our proved reserves at December 31, 2013 was $844.5 million.


•	Our daily production volumes at December 31, 2013 were approximately 12,210 Boe/d. Our average daily production volumes for the year ended December 31, 2013, were approximately 9,844 Boe/d, which represented a 27.2% increase from the year ended December 31, 2012. Our average daily production volumes for the quarter ended December 31, 2013 were approximately 11,298 Boe/d.


•	Our daily production volumes at February 20, 2014 were approximately 16,142 Boe/d.


•	As of January 31, 2014, we had approximately 280,657 net leasehold acres in our core operating areas, including approximately 78,709 net acres in the Marcellus Shale, approximately 99,078 net acres prospective for the Utica Shale (a portion of which acreage overlaps our Marcellus Shale acreage) and approximately 102,869 net acres in the Williston Basin/Bakken Shale in North Dakota.

Reserve Summary



	At December 31, 2013
	Proved Reserves(a)	PV-10 (b)(c)		% Proved Developed	% Oil/Liquids
	Proved Reserves(a)	PV-10 (b)(c)				Productive Wells
Area	(MMBoe)	(in millions)				Gross	Net

Appalachian Basin	53.4	$	507.3	73%	26%	3,866.0	2,745.6
Williston Basin
United States	18.5	322.7		39%	93%	255.0	61.0
Canada	2.2	67.1		90%	99%	43.0	37.1
Texas and Louisiana (d)	1.6	14.8		25%	76%	10.0	5.0
Other Canada (e)	0.2	10.2		100%	93%	44.0	40.7
Total at December 31, 2013	75.9	$	922.1	64%	46%	4,218.0	2,889.4


(a)	MMBoe is defined as one million barrels of oil equivalent determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.

(b)

The prices used to calculate this measure were $96.78 per barrel of oil and $3.67 per MMBtu of natural gas. The prices represent the average prices per barrel of oil and per MMBtu of natural gas at the beginning of each month in the 12-month period prior to the end of the reporting period. These prices were adjusted to reflect applicable transportation and quality differentials on a well-by-well basis to arrive at realized sales prices used to estimate our reserves at this date.


(c)	The standardized measure of our proved reserves at December 31, 2013 was $844.5 million. See “—Non-GAAP Measures; Reconciliations” for a definition of pre-tax PV-10 and a reconciliation of our pre-tax PV-10 value to our standardized measure.

(d)

We sold certain Eagle Ford Shale and Pearsall Shale assets in January 2014 (the reserves attributable to which assets are reflected in the table above). See "—Our Significant Recent Developments—Sale of Remaining Eagle Ford Shale and Pearsall Shale Assets" below and "Note 19 - Subsequent Events" in the notes to our consolidated financial statements included in this report. We continue to own certain miscellaneous assets in Texas and Louisiana.


(e)	Pertains to our Alberta, Canada properties.

Our Business Strategy

Key elements of our business strategy include:

Focus on Core Unconventional Resource Plays

As a result of our recent and planned divestitures, we are now strategically focused on the development and expansion of our core areas of operation in the Marcellus Shale in West Virginia and Ohio, in the Utica Shale in southeastern Ohio and western West Virginia and, to a lesser extent, in the Williston Basin/Bakken Shale in North Dakota. As of January 31, 2014, we had a total of approximately 513,628 gross acres (280,657 net acres) in these core areas.

Focus on Development and Acquisition of Liquids Rich Marcellus and Dry Gas and Liquids Rich Utica Resources

We intend to focus our development and acquisition efforts primarily on high return projects, including liquids rich gas (greater than 1,250 Btu) in the Marcellus Shale in West Virginia and Ohio, the dry gas and liquids rich area of the Utica Shale in southeastern Ohio and western West Virginia and oil reserves in the Williston Basin/Bakken Shale in North Dakota. We have allocated a significant portion of our 2014 upstream capital expenditure budget to these high return projects in the Marcellus Shale and Utica Shale plays. We intend to pursue strategic “bolt-on” acquisitions, primarily leasehold acreage, in our core areas, on a very selective and value accretive basis, to enhance long-term asset values and realize economies of scale.

Selected Monetization of Assets

Our strategy is to explore and develop our properties and to selectively monetize our developed properties at opportune times and attractive prices. In the past five years, we significantly expanded our positions in the Marcellus Shale, Utica Shale, Williston Basin, Eagle Ford Shale and southern Appalachian Basin through acquisitions and joint ventures and have monetized some of these assets through divestitures. We sold: (1) our core Eagle Ford Shale properties in April 2013 for a contract purchase price of $401 million of cash and stock; (2) certain non-core properties in Burke County, North Dakota in September 2013 for a contract purchase price

of $32.5 million in cash; (3) certain non-core properties in various counties of North Dakota in December 2013 for a contract purchase price of $45 million in cash; and (4) substantially all of our remaining Eagle Ford Shale and Pearsall Shale properties in south Texas in January 2014 for a contract purchase price of $24.5 million in cash and stock. These transactions resulted in aggregate proceeds in excess of $500 million in cash and stock. We expect to continue to develop our remaining core assets in 2014, while also monetizing certain of our non-core assets and interests. We have identified a number of non-core properties, which we believe represent in excess of $400 million in aggregate value (including our southern Appalachian properties in Kentucky and Tennessee and our Canadian assets in Saskatchewan and Alberta), for possible divestiture in 2014.

Allocate Capital to Projects with High Rates of Return

We intend to allocate capital to areas and projects with high potential rates of return. We have allocated a significant portion of our 2014 capital budget to the Marcellus Shale and Utica Shale plays to accelerate the development of our properties in these regions, to take advantage of our processing capacity at the Mobley Processing Plant (and the uplift in the realized price for our liquids-rich gas stream processed at the plant) and in anticipation of our continued build-out of our Eureka Hunter Gas Gathering System.

Utilize Expertise in Unconventional Resource Plays to Improve Rates of Return

We strive to use state-of-the-art drilling, completion and production technologies, including certain completion techniques that we have developed and continue to refine, allowing us the best opportunity for cost-effective drilling, completion and production success. Our technical team regularly reviews the most current technologies and, to the extent appropriate and cost-effective, applies them to our reserve base for the effective development of our project inventory. As a result of our improving drilling and completion techniques, our drilling and completion results in our core unconventional resource plays have improved significantly, resulting in substantially better initial production, or IP, rates, estimated ultimate recoveries, and, ultimately, rates of return on capital deployed. Additionally, our focus on increasing and concentrating our acreage provides the opportunity to capture economies of scale, such as pad drilling, and to reduce rig mobilization time and cost.

Focus on Properties with Operating Control

We believe that operatorship provides us with the ability to maximize the value of our assets, including control of the timing of drilling expenditures, greater control of operational costs and the ability to efficiently increase production volumes and reserves. During the past five years, we have significantly increased the number of wells that we operate and control. As of January 31, 2014, we were operating approximately 78% of our producing wells. As of December 31, 2013, we were the operator on leases accounting for approximately 65% of our proved reserves. Approximately 76% of our 2014 capital expenditure budget relates to our operated properties.

Continued Development of our Eureka Hunter Gas Gathering System

We are continuing the commercial development of our Eureka Hunter Gas Gathering System in West Virginia and Ohio to provide infrastructure to support the development of our existing and anticipated future Marcellus Shale and Utica Shale acreage positions, as well as to provide the opportunity for substantial cash flow from the increasing gathering needs of third party producers in these regions.

Our Competitive Strengths

We believe we have the following competitive strengths that will support our efforts to successfully execute our business strategy:

Long-Lived Asset Base with Substantial Oil and Liquids Reserves

We believe our mix of properties and drilling opportunities, combined with timely development and additional acquisitions of properties in our core resource areas, present us with a variety of highly economic growth opportunities. As of December 31, 2013, approximately 46% and 52% of our proved reserves and production, respectively, were oil and natural gas liquids. As of January 31, 2014, we held ownership interests in approximately 5,175 gross (3,658.7 net) wells. We expect to increase our oil and natural gas reserves over time through our focused drilling program in our core areas and through possible acquisitions.

Improving Results in Our Core Resource Areas

As a result of our improved drilling and completion techniques, our initial production, or IP, rates have steadily increased over the last couple years. As of January 31, 2014, IP‑24 rates for our five most recently completed Company-operated horizontal wells in the Marcellus Shale averaged approximately 12,158 MMcf/d. In the Utica Shale, we recently announced our first dry gas well located on the Stalder Pad in Monroe County, Ohio, was placed on production on February 9, 2014, and tested at a peak rate of 32.5 MMcf of natural gas per day. We plan to continue to refine our drilling and completion techniques in the Marcellus Shale and the Utica Shale plays and thereby improve initial production rates with a goal to lower drilling and completion costs.

Operational Control over Significant Portion of Assets

We operate a significant portion of our assets (approximately 78% of our producing wells as of January 31, 2014). Consequently, we have substantial control over the timing, allocation and amount of a significant portion of our planned 2014 capital expenditures, which allows us the flexibility to reallocate these expenditures depending on commodity prices, rates of return and prevailing industry conditions. We have continued to demonstrate increasingly robust drilling and completion results in our operated areas as we execute on our strategy.

Experienced Management Team with Proven Operating and Acquisition History

Our senior management team, on average, has over 25 years of experience in the oil and gas industry and has extensive experience in managing, financing and operating public oil and gas companies. Magnum Hunter Resources, Inc., founded by Gary C. Evans, our chairman and chief executive officer, in 1985, achieved an average annual internal rate of return to shareholders of 38% during the 15 years it was publicly traded before it was sold to Cimarex Energy Corporation for $2.2 billion in 2005. Additionally, our management team has collectively completed financing transactions and acquisitions in the oil and gas industry totaling billions of dollars, and our key personnel have extensive expertise in the principal operational disciplines in our core unconventional resource plays.

Our Significant Recent Developments

Eagle Ford Properties Sale

On April 24, 2013, we sold our core properties in the oil window of the Eagle Ford Shale in Gonzales and Lavaca Counties, Texas to an affiliate of Penn Virginia Corporation, or Penn Virginia, for a total contract purchase price of $401 million, consisting of $361 million in cash (before customary purchase price adjustments) and $40 million in Penn Virginia common stock. At closing, we received $422.1 million in cash and stock, based on initial cash purchase price adjustments and the market price of the Penn Virginia common stock on the closing date. The cash portion of the purchase price is subject to final settlement of the purchase price adjustment amounts, and we estimate that the final adjustment will result in an obligation to Penn Virginia of $22 million to $33 million, net of taxes. See “Item 3. Legal Proceedings—Eagle Ford Properties Sale Final Settlement.” We used the cash portion of the purchase price to repay all then outstanding borrowings under our revolving credit facility and for general corporate purposes. The properties sold to Penn Virginia included approximately 19,000 net Eagle Ford Shale leasehold acres, and our operating and non-operating leasehold working interests in certain existing wells, in Gonzales and Lavaca Counties, Texas. The effective date of the transaction was January 1, 2013.

Sale of Non-Core North Dakota Assets

On September 27, 2013, we sold our non-operated working interests in certain oil and natural gas properties located in Burke County, North Dakota, to Oasis Petroleum of North America LLC, or Oasis, for a contract purchase price of $32.5 million in cash (before customary purchase price adjustments). The effective date of the transaction was July 1, 2013.

On December 30, 2013, we sold our North Dakota waterflood properties located in Burke, Renville, Bottineau and McHenry Counties, North Dakota to Enduro Operating LLC, or Enduro, for a contract purchase price of $45 million in cash (before customary purchase price adjustments). The effective date of the transaction was September 1, 2013.

Sale of Remaining Eagle Ford Shale and Pearsall Shale Assets

On January 28, 2014, we sold substantially all of our remaining oil and natural gas properties in the Eagle Ford Shale and Pearsall Shale in south Texas to an affiliate of New Standard Energy Limited, or NSE, for a total contract purchase price of $24.5 million, consisting of $15 million in cash (before customary purchase price adjustments) and $9.5 million in ordinary shares of NSE. The effective date of the transaction was December 1, 2013.

MNW Leasehold Acquisition

On August 12, 2013, we entered into an asset purchase agreement with MNW Energy, LLC or MNW. MNW represents an informal association of various land owners, lessees of mineral acreage and sub lessees of mineral acreage who own or have rights in mineral acreage located in Monroe, Noble and/or Washington Counties, Ohio. Pursuant to the agreement, we agreed to acquire from MNW up to 32,000 net mineral acres, including currently leased and subleased acreage, located in Monroe, Noble and/or Washington Counties, Ohio, over a period of time, in staggered closings, subject to the satisfaction of certain closing conditions, including our right to receive satisfactory title to the acreage. As of January 31, 2014, we had acquired 6,129 net acres pursuant to MNW closings. On December 30, 2013, a lawsuit was filed against us, MNW and others asserting certain claims relating to the acreage covered by our agreement with MNW. We believe the claims asserted against us in the lawsuit are without merit. However, the claims asserted in the lawsuit may impair our right to receive satisfactory title to the acreage; therefore, future MNW closings may be delayed until this matter is resolved. See “Item 3. Legal Proceedings—Dux Litigation.”

Expansion of Eureka Hunter Gas Gathering System

In 2013, we expanded our Eureka Hunter Gas Gathering System, completing the construction of approximately 22 miles of additional pipeline in Monroe County, Ohio, for a total of over 100 miles of completed pipeline at January 31, 2014. In January 2013, we extended our Pursley lateral section of the pipeline (which is a 20-inch lateral section extending north from our main line) under the Ohio River from Wetzel County, West Virginia into Monroe County, Ohio. In December 2013, we completed our Tippens lateral section of the pipeline, which is a 20-inch lateral section that extends approximately 11 miles west-northwesterly from our Ohio River crossing near Sardis, Ohio, allowing for the gathering of dry Utica Shale gas production from multiple well pads, including our Stalder pad. We continue to construct the pipeline further into Ohio to support the continued development of our Marcellus Shale and Utica Shale acreage in Ohio, as well as acreage of third party producers.

2014 Capital Expenditure Budget

Our capital expenditure budget for fiscal year 2014 is currently (a) $310 million for our core upstream operations, consisting of approximately $260 million for the Marcellus and Utica Shales in West Virginia and Ohio and approximately $50 million for the Williston Basin/Bakken Shale in North Dakota, and (b) $90 million (net to our majority interest) for our midstream operations (excluding, in each case, any budgeted amounts for operations that may be acquired pursuant to acquisitions). We expect that the 2014 capital expenditure budget for our midstream operations will be funded by us and by the third-party equity and non-recourse debt facilities we have obtained for our midstream operations. See "Management's Discussion and Analysis of Financial Condition and Results of Operations" in this annual report for a description of these facilities, including the third-party equity commitment for our midstream operations (under which we have the right to make capital contributions in conjunction with or alongside the capital contributions from the third party).

Because of the volatility of commodity prices and the risks involved in our industry, we believe in remaining flexible in our capital budgeting process. When appropriate, we may defer existing capital projects to pursue an attractive acquisition opportunity or reallocate capital to projects we believe can generate higher rates of return on capital employed. We also believe in maintaining a strong balance sheet and using commodity price derivatives to mitigate uncontrollable risk. This allows us to be more opportunistic in a lower commodity price environment as well as providing more consistent financial results in the long-term.

Our Operations

Appalachian Basin Properties

The Appalachian Basin is considered one of the most mature oil and natural gas producing regions in the United States. Our core Appalachian Basin properties are located in West Virginia and Ohio, targeting the liquids rich Marcellus Shale and Utica Shale and the dry gas window of the Utica Shale.

We initially entered the Appalachian Basin through an asset acquisition in February 2010 and have subsequently expanded our operations through various acquisitions and joint ventures and development drilling efforts. As of January 31, 2014, we had approximately 78,709 net leasehold acres in the Marcellus Shale and approximately 99,078 net leasehold acres prospective for the Utica Shale (a portion of which acreage overlaps our Marcellus Shale acreage). We believe approximately 36,500 of these Utica Shale net acres are located in the wet gas window of the play.

As of December 31, 2013, proved reserves attributable to our Appalachian Basin properties were 53.4 MMBoe, of which 57% were classified as proved developed producing. As of December 31, 2013, these proved reserves had a PV-10 value of $507.3 million.

Our capital budget for 2014 includes approximately $260 million for capital expenditures in the Appalachian Basin, essentially all in the Marcellus Shale and Utica Shale regions. We intend to drill a total of approximately 25 gross horizontal wells in the Marcellus Shale and Utica Shale in 2014.

Marcellus Shale Properties

As of January 31, 2014, we had a total of approximately 78,709 net leasehold acres in the Marcellus Shale. Our Marcellus Shale acreage is located principally in Tyler, Pleasants, Richie, Wetzel and Lewis Counties, West Virginia and in Washington and Monroe Counties, Ohio. As of January 31, 2014, we had (a) 35 horizontal wells producing in the Marcellus Shale (including non-operated wells), and (b) 14 horizontal wells (7.9 net) awaiting completion, one horizontal well (one net) drilling, and one drilling rig operating on our Company-operated Marcellus Shale properties. As of January 31, 2014, approximately 76% of our mineral leases in the Marcellus Shale area were held by production. As of January 31, 2014, our five most recently completed Company-operated horizontal wells targeting the Marcellus Shale generated approximately 12,158 Mcfe/d (8,794 Mcfe/d wet gas and 3,364 Mcfe/d condensate) and 7,005 Mcfe/d (5,618 Mcfe/d wet gas and 1,387 Mcfe/d condensate) average IP-24 hour and IP-30 day rates, respectively.

The liquids rich natural gas produced in our core Marcellus Shale area (which has a Btu content ranging from 1,125 to 1,435), coupled with a location near the energy-consuming regions of the mid-Atlantic and northeastern U.S., typically allow us to sell our natural gas at a premium to prevailing NYMEX spot prices. Historically, producers in the Appalachian Basin developed oil and natural gas from shallow Mississippian age sandstone and Upper Devonian age shales with low permeability, which are prevalent in the region. Traditional shallow wells in the Appalachian Basin generally produce little or no water, contributing to a low cost of operation. However, in recent years, the application of horizontal well drilling and completion technology has led to the development of the Marcellus Shale, transforming the Appalachian Basin into one of the country’s premier natural gas reserves. The productive limits of the Marcellus Shale cover a large area within New York, Pennsylvania, Ohio and West Virginia. This Devonian age shale is a black, organic rich shale deposit productive at depths between 5,500 and 7,500 feet and ranges in thickness from 50 to 80 feet. It is considered the largest natural gas field in the country. Marcellus Shale gas is best produced from hydraulically fractured horizontal wellbores, exceeding 2,000 feet in lateral length, and involving multistage fracturing completions.

In December 2011, we entered into joint development and operating agreements with Stone Energy Corporation, or Stone Energy, pursuant to which we and Stone Energy agreed to jointly develop a contract area consisting of approximately 1,925 leasehold acres

in the Marcellus Shale in Wetzel County, West Virginia. Each party owns a 50% working interest in the contract area. Stone Energy is the operator for the contract area. Stone Energy also contributed to the joint venture certain infrastructure assets, including improved roadways, certain central field processing units (including water handling) and gas flow lines, and agreed to commit its share of natural gas production from the contract area to gathering by our Eureka Hunter Gas Gathering System. As of January 31, 2014, Stone Energy had drilled and completed 15 producing Marcellus Shale wells pursuant to this joint development program. We expect an additional four program wells to be on production in 2014.

In January 2013, we entered into joint development and operating agreements with Eclipse Resources I, LP, or Eclipse Resources, pursuant to which the parties agreed to jointly develop a contract area consisting of approximately 1,950 leasehold acres in the Marcellus Shale and Utica Shale in Monroe County, Ohio. Each party owns a 47% working interest in the contract area. We are the operator for the contract area. Eclipse Resources also agreed to dedicate its share of production from the contract area to gathering by our Eureka Hunter Gas Gathering System. As of January 31, 2014, we had drilled one Marcellus Shale well and one Utica Shale well (and are in the process of completing the Utica Shale well) pursuant to this joint development program. We expect to drill an additional nine Marcellus Shale wells and seven Utica Shale wells pursuant to this joint development program over the next 12 to 18 months.

The following table contains certain information regarding our Marcellus Shale horizontal wells drilled or completed in 2013.



		MHR Working	First	Horizontal Lateral	# of Frac	IP-24 Hour Rate	IP-7 Day Rate	IP-30 Day Rate
Well Name	County	Interest	Production	Length (feet)	Stages	(Mcfe/d)	(Mcfe/d)	(Mcfe/d)
Operated
Collins Unit #1116H	Tyler, WV	100%	12/21/2013	4,444	18	12,854	9,543	7,241
				Wet Gas⁽¹⁾		9,842	7,306	5,818
				Condensate⁽²⁾		3,012	2,237	1,423
Collins Unit #1117H	Tyler, WV	100%	12/20/2013	5,235	21	12,421	10,340	7,494
				Wet Gas⁽¹⁾		9,559	7,958	6,047
				Condensate⁽²⁾		2,862	2,382	1,447
Collins Unit #1118H	Tyler, WV	100%	12/7/2013	5,355	21	12,832	8,842	6,125
				Wet Gas⁽¹⁾		9,604	6,617	4,828
				Condensate⁽²⁾		3,228	2,225	1,297
Collins Unit #1119H	Tyler, WV	100%	12/5/2013	6,037	24	12,670	8,560	7,168
				Wet Gas⁽¹⁾		9,748	6,586	5,782
				Condensate⁽²⁾		2,922	1,974	1,386
Non-Operated
Mills Wetzel #9H	Wetzel, WV	50%	2/22/2013	4,900	20	3,257	2,945	2,892
				Wet Gas⁽¹⁾		3,257	2,945	2,784
				Condensate⁽²⁾		—	—	108
Mills Wetzel #12H	Wetzel, WV	50%	2/27/2013	3,400	14	4,661	2,701	2,456
				Wet Gas⁽¹⁾		4,386	2,544	2,396
				Condensate⁽²⁾		275	157	60
Mills Wetzel #13H	Wetzel, WV	50%	3/9/2013	4,000	16	3,140	4,009	3,286
				Wet Gas⁽¹⁾		3,122	3,985	3,214
				Condensate⁽²⁾		18	24	72
Mills Wetzel #15H	Wetzel, WV	50%	3/19/2013	4,600	18	3,951	2,412	2,891
				Wet Gas⁽¹⁾		3,945	2,407	2,693
				Condensate⁽²⁾		6	5	198
Mills Wetzel #4H	Wetzel, WV	50%	4/6/2013	4,150	17	3,044	3,144	2,882
				Wet Gas⁽¹⁾		3,044	3,119	2,749
				Condensate⁽²⁾		—	25	133
Mills Wetzel #5H	Wetzel, WV	50%	4/13/2013	4,200	17	3,225	3,700	3,217
				Wet Gas⁽¹⁾		2,361	2,824	2,894
				Condensate⁽²⁾		864	876	323
Mills Wetzel #6H	Wetzel, WV	50%	4/20/2013	4,050	17	3,787	6,412	4,360
				Wet Gas⁽¹⁾		3,553	6,059	4,078
				Condensate⁽²⁾		234	353	282
Mills Wetzel #7H	Wetzel, WV	50%	4/27/2013	4,600	18	3,560	3,380	3,612
				Wet Gas⁽¹⁾		3,560	3,277	3,359
				Condensate⁽²⁾		—	103	253

________________________________


(1)	Wet gas contains less methane than dry gas and has a higher percentage of natural gas liquids (NGLs). The combination of NGL’s and liquefied hydrocarbons make the gas “wet”.


(2)	Determined using the ratio of six Mcf of natural gas to one Bbl of condensate.

During 2014, we plan to drill a total of 18 gross (16 net) wells in the Marcellus Shale.

Utica Shale Properties

As of January 31, 2014, we had a total of approximately 99,078 net leasehold acres prospective for the Utica Shale. Approximately 63,877 of the net acres are located in Ohio (a portion of which acreage overlaps our Marcellus Shale acreage), and approximately 35,201 of the net acres are located in West Virginia (a portion of which acreage overlaps our Marcellus Shale acreage). Our Utica Shale acreage is located principally in Tyler, Pleasants and Wood Counties, West Virginia and in Washington, Monroe, Morgan and Noble Counties, Ohio. We believe approximately 36,500 of our Utica Shale net acres are located in the wet gas window of the play. As of January 31, 2014, we had two horizontal wells (1.5 net) awaiting completion, one horizontal well (one net) drilling, and one drilling rig operating on our Company-operated Utica Shale properties. Approximately 65% of our acreage in the Utica Shale is held by shallow production. Our first dry gas Utica Shale well located on the Stalder Pad in Monroe County, Ohio, was placed on production on February 9, 2014 and tested at a peak rate of 32.5 MMcf of natural gas per day. The Stalder #3UH well was drilled and cased to a true vertical depth of 10,653 feet with a 5,050 foot horizontal lateral, and successfully fraced with 20 stages.

On August 12, 2013, we entered into an asset purchase agreement with MNW. MNW represents an informal association of various land owners, lessees of mineral acreage and sub lessees of mineral acreage who own or have rights in mineral acreage located in Monroe, Noble and/or Washington Counties, Ohio. Pursuant to the agreement, we agreed to acquire from MNW up to 32,000 net mineral acres, including currently leased and subleased acreage, located in Monroe, Noble and/or Washington Counties, Ohio, over a period of time, in staggered closings, subject to the satisfaction of certain closing conditions, including our right to receive satisfactory title to the acreage. As of January 31, 2014, we had acquired 6,129 net acres pursuant to MNW closings. On December 30, 2013, a lawsuit was filed against us, MNW and others asserting certain claims relating to the acreage covered by our agreement with MNW. We believe the claims asserted against us in the lawsuit are without merit. However, the claims asserted in the lawsuit may impair our right to receive satisfactory title to the acreage; therefore, any future MNW closings may be delayed until this matter is resolved. See “Item 3. Legal Proceedings—Dux Litigation.”

The Utica Shale is located in the Appalachian Basin of the United States and Canada. The Utica Shale is a rock unit comprised of organic-rich calcareous black shale that was deposited about 440 million to 460 million years ago during the Late Ordovician period. It overlies the Trenton Limestone and is located a few thousand feet below the Marcellus Shale, which is considered to be the largest exploration play in the eastern United States.

The Utica Shale may be comparable or thicker and more geographically extensive than the Marcellus Shale, although reported drilling results in the play are still not sufficient to conclusively establish the geographical extent of the play. The potential source rock portion of the Utica Shale underlies portions of Kentucky, Maryland, New York, Ohio, Pennsylvania, Tennessee, West Virginia and Virginia in the United States and is also present beneath parts of Lake Ontario, Lake Erie and Ontario, Canada. Throughout the potential source rock area, the Utica Shale ranges in thickness from less than 100 feet to over 500 feet. Over the rock unit as a whole, there is a general thinning from east to west.

The Utica Shale is deeper than the Marcellus Shale. In some parts of Pennsylvania, the Utica Shale is estimated to be over two miles below sea level and up to 7,000 feet below the Marcellus Shale. However, the depth of the Utica Shale decreases to the west into Ohio and to the northwest under the Great Lakes and into Canada to less than approximately 2,000 feet below sea level. Most of our acreage is located at depths of 7,600 to 11,000 feet and approximately 3,000 feet below the Marcellus Shale.

The Utica Shale is estimated to have higher carbonate and lower clay mineral content than the Marcellus Shale. The difference in mineralogy generally produces a different response to hydraulic fracturing treatments. Operation drillers have redesigned and improved the fracturing methods in the Utica Shale, to generally match or improve upon, to the extent deemed beneficial, those methods used in other natural gas shales with comparable carbonate content. For example, drillers have discovered methods to make the brittle carbonate zones in the Utica Shale fracture at generally higher rates than gas shale rock units in the Eagle Ford Shale in Texas. Drillers are researching methods to make other similar fracturing improvements in the Utica Shale.

The Point Pleasant formation in the Utica Shale is generally 100 to 150 feet thick and is our primary targeted reservoir for horizontal drilling in the play. This formation is primarily limestone with inter-bedded shales deposited within an organic rich marine environment. The Point Pleasant formation has the composition for hydrocarbon generation and brittleness. Combined with the organic content, or TOC, a 6% to16% porosity, thermal maturity and a significant geo-pressured condition, the Point Pleasant formation has the characteristics for an ideal unconventional reservoir. The Point Pleasant formation appears to have a significant amount of hydrocarbons in place, and the techniques for successful drilling in the formation appear similar to those of the Eagle Ford Shale in Texas; longer laterals, more stages of fracture stimulation and more effective treatment of the horizontal lateral appear to be key to the optimization of recoverable reserves and return on investment.

Based on estimates published by the Ohio Department of Natural Resources, or ODNR, in 2012, the Utica Shale had a recoverable potential of 1.3 billion to 5.5 billion barrels of oil and 3.8 to 15.7 trillion cubic feet of natural gas in Ohio alone. During 2013, a number of oil and gas companies made significant investments in acquiring Utica Shale acreage in eastern Ohio. Recently, the ODNR reported that in the Utica Shale in Ohio there were 292 producing horizontal wells, 315 horizontal wells that had been drilled but were not yet completed or connected to a pipeline, 40 horizontal wells that were being drilled and 1,061 horizontal wells that had been permitted.

During 2013, most of the drilling activity in the Utica Shale occurred in eastern Ohio, where our acreage is located. Based on the initial drilling results of other producers, the Utica Shale is prospective for oil, natural gas and natural gas liquids. Early wells drilled in the Utica Shale by other producers have indicated greater potential for production of significant amounts of natural gas liquids, which generally have a higher value, on an energy-equivalent basis, than natural gas.

During 2014, we plan to drill a total of seven gross (seven net) wells in the Utica Shale.

Recent Marcellus Shale and Utica Shale Activities

During the fourth quarter of 2013, we completed the drilling of seven gross (seven net) wells and completed eight gross (six net) wells in the Marcellus Shale and Utica Shale plays. These eight gross (six net) completed wells are currently flowing to sales through the Eureka Hunter Gas Gathering System. Our net production in the fourth quarter of 2013 attributable to Triad Hunter, LLC’s operations was approximately 37.6 Mcfe/d.

As mentioned above, our first dry gas Utica Shale well, the Stalder #3UH located on the Stalder Pad (18 potential wells) in Monroe County, Ohio, was placed on production in early February 2014 and tested at a peak rate of 32.5 MMcf of natural gas per day. The well continues to flow to sales points through the Eureka Hunter Gas Gathering System with the amount of frac water continuing to decrease since the commencement of initial sales.

Our first Marcellus Shale well drilled on the Stalder Pad, the Stalder #2MH, is awaiting the start of completion operations, which we expect to commence in March 2014. The Stalder #2MH was drilled and cased to a true vertical depth of 6,070 feet with a 5,474 foot horizontal lateral. We expect the production from this well to be very liquids rich.

On our Farley Pad located in Washington County, Ohio, we drilled and cased the Farley #1306H well in the Utica Shale to a true vertical depth of 7,850 feet with a 6,313 foot horizontal lateral. We have commenced drilling another Utica Shale well on the Farley Pad, the Farley #1304H. We have commenced drilling the vertical section of this well and anticipate reaching a true vertical depth of 7,885 feet, and completing the drilling of a 5,500 foot horizontal lateral, in late March 2014. Following the drilling of the Farley #1304H, we will begin fracture stimulation of these two new Farley wells in mid-March 2014 and expect to report initial production test rates in May 2014 following an approximate 30-day resting period. We are in the advanced stages of negotiating new take-away capacity with a third-party midstream company and expect to be ready to flow production of all the wells on the Farley Pad to sales following the resting period.

On our WVDNR Pad located in Wetzel County, West Virginia, we have drilled and are in the process of completing three 100% owned Marcellus Shale wells, the WVDRN #1207, #1208 and #1209. The wells were drilled and cased to an average vertical depth of 7,500 feet with a 4,000 foot average horizontal lateral. We have fracture stimulated eight of the proposed 20 stages on each of the three wells. During the last several weeks, we have experienced substantial completion delays in this region primarily due to the effects of extreme cold weather conditions. We expect to finish fracture stimulating the three WVDNR wells over the next 7 to10 days, and anticipate production from the wells to begin to flow to sales in mid-March 2014.

On our Stewart Winland Pad located in Tyler County, West Virginia, we have drilled and cased the pad’s first Marcellus Shale well, the Stewart Winland #1301. The Stewart Winland #1301 was drilled to a true vertical depth of 6,144 feet with a 5,770 foot horizontal lateral. We skid the drilling rig and commenced the drilling of another Marcellus Shale well, the Stewart Winland #1302, on this pad. We expect to drill one additional Marcellus Shale well and one Utica Shale well on this pad. We expect to report initial production test rates from the four wells on the Stewart Winland Pad during mid-Summer 2014. We are in the process of making several midstream upgrades at both our Collins and Spencer Pads in Tyler County, West Virginia to adequately handle the expected additional liquids production. We expect to complete these production equipment changes in March or April 2014. As a result, we do not expect to encounter any liquids infrastructure issues associated with the initial production from the four wells on our Stewart Winland Pad.

Southern Appalachian Basin Properties

We have classified our southern Appalachian Basin properties located primarily in Kentucky and Tennessee as assets held for sale and the associated operations are reflected as discontinued operations in our financial statements. We anticipate completing the divestiture of such assets in the second half of 2014.

As of January 31, 2014, our southern Appalachian Basin properties included approximately 258,918 net acres, primarily in Kentucky. Our primary production from the southern Appalachian Basin properties comes from the Devonian Shale formation and the Mississippian Weir sandstone.

Our southern Appalachian properties also include (i) a non-operating interest in a coal bed methane project in the Arkoma Basin in Arkansas and Oklahoma, (ii) certain non-operated projects in West Virginia and Virginia and (iii) an operating interest in a New Albany Shale field in western Kentucky known as Haley’s Mill.

Williston Basin Properties

We refer to our properties in North Dakota, which are located in the Williston Basin, as our Williston Basin U.S. properties and our properties in Canada, which are located in the Williston Basin in Saskatchewan and in certain other formations in Alberta, as our Williston Hunter Canada properties.

We established our initial presence in the Bakken/Three Forks Sanish formations in North Dakota with an acquisition in May 2011 and have expanded our presence in the Bakken Shale through subsequent acquisitions. We recently sold certain non-core properties in North Dakota. See “—Our Significant Recent Developments—Sale of Non-Core North Dakota Assets.” As of January 31, 2014, our Williston Basin U.S. properties included approximately 102,869 net acres in the Bakken/Three Forks Sanish formations in North Dakota. Our Williston Basin U.S. acreage is located in Divide County, North Dakota.

As of January 31, 2014, we had drilled and completed approximately 298 gross (98.1 net) wells on our Bakken/Three Forks Sanish properties, including 255 gross (61 net) wells in the Bakken/Three Forks Sanish in North Dakota and 43 gross (37.1 net) wells in the Bakken/Three Forks Sanish in Saskatchewan. Of these wells, approximately 70 gross (21 net) wells in the Bakken/Three Forks Sanish in North Dakota, and approximately six gross (4.2 net) wells in the Bakken/Three Forks Sanish in Saskatchewan, were completed in 2013 and through January 31, 2014. As of January 31, 2014, we operated 52 of our Bakken/Three Forks Sanish wells, including nine wells in the Bakken/Three Forks Sanish in North Dakota and 43 wells in the Bakken/Three Forks Sanish in Saskatchewan. As of December 31, 2013, proved reserves attributable to our Williston Basin properties were 20.8 MMBoe, of which 94% were oil and natural gas liquids and 44% were classified as proved developed producing. As of December 31, 2013, these proved reserves had a PV-10 value of $400 million.

The Williston Basin is spread across North Dakota, Montana and parts of southern Canada with the U.S. portion of the basin encompassing approximately 143,000 square miles. The basin produces oil and natural gas from numerous producing horizons, including the Madison, Bakken, Three Forks Sanish and Red River formations. The Bakken formation is a Devonian age shale. The North Dakota Geological Survey and Oil and Gas Division estimates that the Bakken formation is capable of generating between 271 and 500 billion Bbl of oil. The Bakken formation underlies portions of North Dakota and Montana and southern Canada and is generally found at vertical depths of 9,000 to 10,500 feet. Below the Lower Bakken Shale lies the Three Forks Sanish formations, which have also proved to contain highly productive reservoir rock. The Three Forks Sanish formations typically consist of interbedded dolomites and shale with local development of a discontinuous sandy member at the top, known as the Sanish sand. Economic crude oil development and production from the Bakken/Three Forks Sanish reservoirs are made possible through the combination of advanced horizontal drilling and fracture stimulation technology. Horizontal wells in these formations are typically drilled on 640 acre or 1,280 acre spacing with horizontal laterals extending 4,500 to 9,500 feet into the reservoir. Ultimately, a spacing unit may be developed with up to four horizontal wells in each formation. Fracture stimulation techniques generally utilize multi-stage mechanically diverted stimulations.

Williston Basin U.S. Properties

Bakken/Three Forks Sanish Properties. As of January 31, 2014, our Williston Basin U.S. properties included approximately 102,869 net acres in the Bakken/Three Forks/Sanish formations in the Williston Basin in North Dakota located in Divide County, North Dakota. As of January 31, 2014, our Bakken/Three Forks Sanish properties in North Dakota included approximately 255 gross (61 net) productive wells, and we were operating 9 of these gross wells. As of January 31, 2014, 4 horizontal wells (1.4 net) were awaiting completion, 5 wells (1.4 net) were being drilled and 3 drilling rigs were operating on our Bakken/Three Forks Sanish properties in North Dakota.

Oneok Gas Gathering Arrangement. In 2012, we entered into a gas purchase agreement with Oneok Inc., or Oneok, pursuant to which Oneok is currently constructing a natural gas gathering system and related facilities in North Dakota for the gathering and processing by Oneok of associated natural gas production, including the associated natural gas production from certain of our oil properties in Divide County, North Dakota dedicated by us to Oneok for this purpose. Pursuant to this arrangement, Oneok will purchase our natural gas and natural gas liquids production from the dedicated properties, and we will be responsible for certain well tie-in and electrical power costs associated with the Oneok system and certain minimum yearly gas sale volume requirements. The sale of our natural gas and natural gas liquids production to Oneok pursuant to this arrangement allows us to realize revenues from our natural gas stream in the Divide County area. Oneok has completed the construction of the compressor station, 12-inch high-pressure discharge line and northern-most east/west gathering pipeline in Divide County. The Oneok system is complete and operational and we commenced tying in and flowing production in certain of our Divide County properties beginning in 2013. We also anticipate delivering certain of our Saskatchewan associated natural gas production into the Oneok system.

A significant amount of the associated natural gas produced from oil properties in certain regions of North Dakota is currently being flared or otherwise not marketed because of the lack of available gas gathering and processing infrastructure in these regions. Current and anticipated future North Dakota state regulations on gas flaring restrict and may further restrict, and may possibly prohibit, oil production in North Dakota as to which associated natural gas is flared rather than gathered. We expect that our arrangement with Oneok will permit us to continue to produce crude oil from our properties in Divide County, North Dakota in compliance with these existing or future state regulations.

The following table contains certain information regarding our Bakken/Three Forks Sanish horizontal wells drilled or completed in 2013.



Well Name	County	Formation	MHR Working Interest	First Production	Horizontal Lateral Length (Feet)	# of Frac Stages	IP-24 Hour Rate (Boe/d)	IP-7 Day Rate (Boe/d)	IP-30 Day Rate (Boe/d)
North Dakota - 1 Mile Wells
Bakke 3229-6TFH (32-29-164-99)	Divide	Sanish	39.3%	5/4/2013	5407	25	330	209	177
Titan 3625-5TFH (36-25-164-99)	Divide	Bakken	11.3%	7/13/2013	6006	18	302	194	138
Titan 3625-6TFH (36-25-164-99)	Divide	Bakken	11.3%	8/1/2013	6343	18	302	206	159
Tundra 3130-3H (31-30-164-98)	Divide	Sanish	90.4%	10/15/2013	5513	24	760	384	282
Tundra 3130-4H (31-30-164-98)	Divide	Bakken	90.4%	10/20/2013	4651	24	680	407	253
North Dakota - 2 Mile Wells
Strath 1-27H-1 (27-34-162-96)	Divide	Sanish	7.1%	10/1/2013	9613	30	681	380	338
Johnson 3-6HS (6-7-161-99)	Divide	Sanish	1.6%	10/5/2013	10037	26	639	412	261
Strom 2536-1H (25-36-163-99)	Divide	Bakken	46.1%	10/6/2013	9551	25	853	733	581
Kidd 1-19H1 (18-19-162-97)	Divide	Sanish	27.4%	10/17/2013	9443	30	822	706	488
Bel Air 2314-1H (23-14-163-99)	Divide	Bakken	43.9%	11/18/2013	9935	24	968	899	595
Morner 1-23H (14-23-161-97)	Divide	Bakken	0.1%	11/20/2013	9586	30	1,125	926	751
Meadow Valley 3-1H (1-12-162-100)	Divide	Sanish	1.9%	11/25/2013	9871	26	1,006	858	588
Comet 2635-1H (26-35-163-99)	Divide	Bakken	43.9%	11/29/2013	9386	25	388	222	193
Windfaldet 2-4H (4-9-161-99)	Divide	Sanish	2.0%	12/10/2013	9921	26	435	419	N/A
Comet 2635-3H (26-35-163-99)	Divide	Sanish	43.9%	12/16/2013	7171	25	269	166	130
Bel Air 2314-3H (23-14-163-99)	Divide	Sanish	43.9%	12/16/2013	9908	25	470	201	169
Comet 2635-2H (26-35-163-99)	Divide	Bakken	43.9%	12/18/2013	9774	25	238	191	164
Almos Farms 0112-4TFH (1-12-162-99)	Divide	Sanish	47.5%	12/20/2014	9275	25	682	615	N/A
Bel Air 2314-2H (23-14-163-99)	Divide	Bakken	43.9%	12/21/2013	10169	25	360	265	244
Almos Farms 0112-3TFH (1-12-162-99)	Divide	Bakken	47.5%	1/11/2014	9431	35	288	253	N/A

Williston Hunter Canada Properties

We have classified our Williston Hunter Canada properties as assets held for sale and the associated operations are reflected as discontinued operations in our financial statements. We anticipate completing the divestiture of such assets in the second quarter of 2014.

As of January 31, 2014, our Williston Hunter Canada properties included approximately 49,588 net acres in the Tableland Field in the Williston Basin in Saskatchewan and approximately 26,812 net acres in Alberta. As of January 31, 2014, our Williston Hunter Canada properties included approximately 87 gross (77.9 net) productive oil and natural gas wells, 98% of which we operate.

Saskatchewan. The Tableland Field properties target sweet light oil from the Bakken/Three Forks Sanish formations. At January 31, 2014, we had approximately 49,588 net acres of largely contiguous land that is prospective for Bakken/Three Forks Sanish oil in the Tableland Field. As of January 31, 2014, we had 43 producing oil wells (37.1 net) in the Tableland Field.

Alberta. Our Alberta properties target shallow natural gas and sweet light oil from the Enchant Second White Specks formation and the Kiskatinaw formation. At January 31, 2014, we had approximately 26,812 net acres in Alberta. At January 31, 2014, we had 4 producing oil wells (2.7 net) in Alberta.

Other Upstream Properties

The Company owns certain other scattered miscellaneous oil and gas properties in Texas and Louisiana. We have not allocated any significant capital to these assets for 2014.

Midstream Operations

Eureka Hunter Gas Gathering System

We acquired assets in 2010 that included gas gathering systems and pipeline rights-of-way in West Virginia and Ohio. We have developed and continue to develop these assets into our Eureka Hunter Gas Gathering System, which helps support our existing and anticipated future Marcellus Shale and Utica Shale acreage positions, as well as the expanding gathering needs of third-party producers. As of January 31, 2014, the Eureka Hunter Gas Gathering System consisted of over 100 miles of 20-inch and 16-inch high-pressure steel pipe with an estimated 350 MMcf/d of initial throughput capacity, of which approximately 86 miles is currently active, located in northwestern West Virginia and southeastern Ohio. The Eureka Hunter Gas Gathering System and associated rights-of-way run through Pleasants, Tyler, Ritchie, Wetzel, Marion, Harrison, Doddridge, Lewis and Monongalia Counties in West Virginia and Washington County, Ohio, in certain liquids rich portions of the Marcellus Shale and Utica Shale. The first completed six-mile section of the Eureka Hunter Gas Gathering System was turned to sales in December 2010.

In 2012, we completed the construction of our Pursley lateral section of the pipeline up to the Ohio River, which is a 20-inch lateral section of pipeline extending approximately 19 miles northerly through Tyler and Wetzel Counties, West Virginia, extending to the Ohio River, near Monroe County, Ohio. In January 2013, we successfully bored under the Ohio River to continue the construction of the lateral into Ohio.

In the fourth quarter of 2012, we completed the construction of our Lewis-Wetzel lateral, which is a 20-inch lateral section of pipeline extending approximately seven and one quarter miles originating near the eastern end of the mainline extending northerly through the Wetzel Wildlife Refuge in Wetzel County, West Virginia and terminating at our Eureka Carbide Facility, near the community of Carbide in Wetzel County.

We completed the initial construction of the Eureka Carbide Facility in 2012. This facility includes (a) an 8-inch low-pressure liquids gathering section of pipeline extending approximately two and one third miles for gathering wellhead produced condensate and liquids from wells located in the Lewis Wetzel Wildlife area, (b) a 12-inch low-pressure gas gathering section of pipeline extending approximately two and one third miles for gathering gas production from wells located in the Lewis Wetzel Wildlife area and (c) equipment utilized to handle and stabilize liquids extracted from the pipeline during routine pigging operations as well as liquids gathered by the Lewis Wetzel condensate gathering system. We are currently adding new mainline compression equipment at the facility, to handle expected additional volume demand and reduce line pressure for producers. The Eureka Carbide Facility facilitates our gathering of production from producing wells of us and Stone Energy in Wetzel County, West Virginia.

In the fourth quarter of 2012, we completed the construction of our Mobley lateral section of the pipeline, which is a 20-inch lateral section extending approximately eight miles originating at the Eureka Carbide Facility extending easterly and terminating at the inlet of the Mobley Processing Plant in Wetzel County, West Virginia, in order to provide access for gas processing at the plant.

In 2012, we began construction of our Doddridge lateral section of the pipeline, which is a 16-inch lateral section of pipeline extending southerly from the mainline into northwest Doddridge County, West Virginia. As of January 31, 2014, we had completed approximately three miles of the Doddridge lateral.

In 2012, we began construction of our Ritchie lateral section of the pipeline, which is a 16-inch lateral section of pipeline extending southerly from the western end of the mainline into northwest Richie County, West Virginia. As of January 31, 2014, we had completed approximately 14 miles of the Ritchie lateral.

In December 2013, we completed our Tippens lateral section of the pipeline which is a 20-inch lateral section that extends approximately 11 miles west-northwesterly from our Ohio River crossing near Sardis, Ohio, allowing for the gathering of dry Utica Shale gas production from multiple well pads, including our Stalder pad. We continue to construct the pipeline further into Ohio to support the continued development of our Marcellus Shale and Utica Shale acreage in Ohio, as well as acreage of third party producers.

We have budgeted approximately $90 million (net to our majority interest) for Eureka Hunter Gas Gathering System projects in 2014. We anticipate these funds will be utilized primarily for pipeline construction projects in Ohio and West Virginia, including the completion of a separate lateral section that will extend approximately eight miles northerly and will run parallel to the Ohio River terminating near our Ormet, Ohio area of operations. We also plan to construct our Crescent lateral section of the pipeline, which will consist of approximately 16 miles of 20-inch pipeline for gathering dry Utica Shale gas production extending from the

terminus of the Tippens lateral northeasterly toward Clarington, Ohio. Near Clarington, Ohio, we plan to construct a natural gas compressor station and an interconnection with Rockies Express Pipeline along with other pipeline interconnections including with Texas Eastern Transmission Company and Dominion Transmission in the same general vicinity. In addition, we plan to construct a separate pipeline system for gathering liquids rich gas production from our Eureka Hunter Gas Gathering System at our Ormet well pad northerly to interconnect with a third party pipeline for ultimate delivery of liquids rich gas to the third party's plant for processing.

Other projects for 2014 include the completion of the Ritchie lateral which will add approximately 12 miles of 16-inch gathering pipeline terminating approximately three miles southeast of Cairo, West Virginia and approximately seven miles of 24-inch residue gas line extending from the tailgate of the Mobley Processing Plant to interconnect with the Columbia Gas Pipeline near Smithville, West Virginia.

Mobley Processing Plant

In late 2011, we entered into certain midstream services agreements with MarkWest, pursuant to which MarkWest agreed to provide long-term gas processing and related services for natural gas produced by both us and other producers and gathered through our Eureka Hunter Gas Gathering System. In December 2012, following the startup of MarkWest’s Mobley Processing Plant in Wetzel County, West Virginia, we began flowing natural gas production through the Eureka Hunter Gas Gathering System for processing at the Mobley Processing Plant. We have supplied and expect to continue to supply the Mobley Processing Plant with both Company and third-party natural gas produced primarily from the Marcellus Shale formation. MarkWest also provides natural gas liquids handling and fractionation services for Mobley Processing Plant products at its nearby fractionation facility. These agreements with MarkWest allow us to offer third-party producers in the Marcellus Shale not only gas gathering services through our Eureka Hunter Gas Gathering System, but also access to natural gas processing at the Mobley Processing Plant. Also, our ability to process our natural gas at the Mobley Processing Plant has provided and is expected to continue to provide us with an uplift in the realized price for our liquids-rich gas stream. Effective as of December 2013, we have committed to approximately 190,000 Mcf per day of the processing capacity at the Mobley Processing Plant. In April 2014, that volume will be reduced to 140,000 Mcf per day as we will release 50,000 Mcf per day of processing to a third party producer committed to gathering volumes through the Eureka Hunter Gas Gathering System.

In September 2013, the Mobley Processing Plant was temporarily shut down due to a break in a MarkWest natural gas liquids pipeline caused by a landslide in northern Wetzel County, which temporarily impacted our gas gathering operations and resulted in the temporary shut-in by us of approximately 20,000 Mcfe per day of natural gas production from certain of our Marcellus Shale acreage. The facility resumed operations in mid-October 2013, and we restarted our delivery of natural gas volumes to the Mobley Processing Plant. As of February 16, 2014, we were flowing approximately 171,000 MMbtus of natural gas per day through the Eureka Hunter Gas Gathering System. We gathered 3.2 Bcf of gas during January 2014 with a peak day of approximately 170,000 MMBtu of natural gas delivered to the Mobley Processing Plant on January 5, 2014. During the first six months of 2014, we expect to bring on significant volumes from us and third party producers with production connected to the Eureka Hunter Gas Gathering System.

Natural Gas Treating and Processing

We are a full service provider for the natural gas treating and processing needs of producers and midstream companies. We currently conduct treating and processing operations in Texas, Louisiana, Oklahoma and West Virginia and anticipate possible future operations in Arkansas, Mississippi and Ohio. As of January 31, 2014, we owned approximately 50 natural gas treating and processing plants in varying sizes and capacities designed to remove carbon dioxide, or CO2, and hydrogen sulfide, or H2S, from the natural gas stream. Our services also include the installation and maintenance of Joule-Thomson, or JT, plants, which are refrigeration plants designed to remove hydrocarbon liquids from the natural gas stream for dew point control (so that the residue gas meets pipeline specifications) and to upgrade the liquids for processing and marketing. We also offer full turnkey services including the installation, operation and maintenance of facilities. Our customers include small, independent producers, as well as large, publicly-traded companies. Currently, we are building small and medium-size gas treating and processing equipment to meet current and anticipated producer demand.

Other Gas Gathering and Processing

Gas Gathering. Natural gas production from our southern Appalachian Basin properties is delivered and sold through gas gathering facilities owned by Seminole Energy Services, L.L.C. We operate these gathering facilities, which are located in southeastern Kentucky, northeastern Tennessee and western Virginia. We have gas gathering, gas sales and gas gathering facilities operating agreements with Seminole Energy and affiliates, or Seminole Energy. The Seminole Energy agreements provide us with long-term operating rights and firm capacity rights for daily delivery of up to 30,000 Mcf of controlled gas through Seminole Energy’s Appalachia gathering system, which interconnects with Spectra Energy Partners’ East Tennessee Interstate pipeline network at Rogersville, Tennessee. This ensures continued deliverability from our connected fields, representing over 90% of our southern Appalachian natural gas production, to major East Coast natural gas markets.

Gas Processing. Eureka Hunter Pipeline owns a 50% interest in a liquids extraction plant in Rogersville, Tennessee, used for the processing of natural gas delivered through Seminole Energy’s gathering system. The Rogersville processing plant extracts natural gas liquids at levels enabling us to flow dry pipeline quality natural gas into the interstate network. The Rogersville processing plant is currently configured for throughput at rates up to 25,000 Mcf per day, which can be increased to accommodate production growth and relief of constrained regional supplies. The Rogersville processing plant is co-owned and is operated by Seminole Energy. Gas processing fees are volume dependent and are shared with Seminole Energy.

Restructuring of the Seminole Energy Agreements. Our agreements with Seminole Energy referred to above were restructured in connection with a global settlement of certain legal proceedings which we and Seminole Energy entered into in January 2014. The restructured agreements resulted in the following: (i) we obtained a substantial reduction in the gas gathering rates we pay for the natural gas production owned or controlled by us which is gathered by Seminole Energy's Appalachia gathering system; (ii) the parties agreed to construct a mechanical enhancement of the Rogersville processing plant, designed to recover less ethane and more propane from the natural gas delivered to and processed at the plant (and to credit us for certain costs of the enhancement otherwise payable by us as part owner of the plant, in exchange for certain contract rights assigned by us to Seminole Energy and based on certain other terms of the restructuring); (iii) the parties agreed to reduce and extend our contractual horizontal well drilling obligations in the Appalachian Basin owed to Seminole Energy; (iv) the parties agreed to the modification of (a) the natural gas processing rates we pay for processing gas at the Rogersville plant, (b) the allocation to us of natural gas liquids recovered from gas processed at the Rogersville plant, (c) the allocation to us of the costs of blend stock necessary to blend with the natural gas liquids produced from the Rogersville plant for purposes of transportation of the natural gas liquids to fractionators and (d) certain deductions to the natural gas liquids purchase price we pay for the purchase by Seminole Energy of our natural gas liquids produced from the Rogersville plant; and (v) the sale by Seminole Energy to us of Seminole Energy’s 50% interest in a natural gas gathering trunk line and treatment facility located in southwestern Muhlenberg County, Kentucky, which had previously been owned equally by Seminole Energy and us.

As a result of the restructuring effected by the settlement agreement, we expect to realize operational savings estimated at approximately $250,000 per month, certain components of which savings will occur over time, depending on the timing of implementation or completion of certain of the benefits provided to us by the restructuring. In addition, as a result of the restructuring, as of December 31, 2013, we have realized an increase of approximately 20% in the PV-10 value of that portion of our estimated total proved reserves attributable to our oil and gas properties in the Appalachian Basin affected by the restructuring, compared to the estimated PV-10 value of those reserves as of December 31, 2013, calculated by us without taking into account the effects of the restructuring.

Oil Field Services

We own and operate portable, trailer-mounted drilling rigs capable of drilling to depths of between 6,000 to 19,000 feet, which are used primarily for vertical section (top-hole) air drilling in the Appalachian Basin. The drilling rigs are used primarily for our Appalachian Basin operations and to provide drilling services to third parties. At January 31, 2014, our operating fleet consisted of five Schramm T200XD drilling rigs and one Schramm T500XD drilling rig. The Schramm T500XD rig is a portable, robotic drilling rig capable of drilling to depths (both vertically and horizontally) of up to 19,000 feet. This rig can be used to drill the horizontal sections of our Marcellus Shale and Utica Shale wells.

The T200XD drilling rigs primarily drill the top-holes of the Company's and third parties' Marcellus Shale and Utica Shale wells in preparation for larger drilling rigs, which drill the horizontal sections of the wells. This style of drilling has proved to reduce overall drilling costs, by minimizing mobilization and demobilization charges and significantly decreasing the overall time to drill horizontal wells on each pad site.

At January 31, 2014, four of the Schramm T200XD drilling rigs were under contract to a large producer in the Appalachian Basin area for the top-hole drilling of multiple wells through December 2014; one Schramm T200XD drilling rig was under contract to an independent producer in the Appalachian Basin, and will also be utilized by us for our top-hole drilling program; and the Schramm T500XD drilling rig was under contract to our subsidiary for our Marcellus Shale and Utica Shale drilling program. All these contracts are term contracts.

Marketing and Pricing

General

We derive revenue principally from the sale of oil and natural gas. As a result, our revenues are determined, to a large degree, by prevailing prices for crude oil and natural gas. We sell our oil and natural gas on the open market at prevailing market prices. The market price for oil and natural gas is dictated by supply and demand, and we cannot accurately predict or control the price we may receive for our oil and natural gas.

The Company generally markets its U.S. and Canadian oil and natural gas production under “month-to-month” or “spot” contracts.

We also derive revenue from our midstream operations.

Marketing of U.S. Production

We market crude oil produced from our Company-operated properties in North Dakota through a marketing and distribution firm under “month-to-month” or “spot” contracts, pursuant to which we receive spot market prices for the production. The crude oil is produced to tanks and then trucked to market. The crude oil produced from our third-party operated properties in North Dakota is sold by the operator along with the other well production. The production is typically transported to market by rail.

We generally sell our natural gas production on “month-to-month” or “spot” pricing contracts to a variety of buyers, including large marketing companies, local distribution companies and industrial customers. We diversify our markets to help reduce buyer credit risk and to ensure steady daily deliveries of our natural gas production. As natural gas production increases in our core operating areas, especially in the Appalachian Basin region, we believe that we and other producers in these areas will find it increasingly important to find markets that have the ability to move natural gas volumes through an increasingly capacity-constrained infrastructure.

Our natural gas liquids (other than ethane, when and if extracted) extracted and fractionated by MarkWest through its Mobley Processing Plant and related fractionation facility are marketed by MarkWest at prevailing market prices. We will be responsible for the marketing of such ethane, if and when extracted, depending on when the Mobley Processing Plant goes into ethane recovery mode. We expect that several markets will be available at that time for ethane sales.

Marketing of Canadian Production

Our oil production in Alberta and Saskatchewan is sold through an international crude oil marketing firm. Our oil production is mostly 38 – 42 degrees API gravity and is considered “sweet” since it contains only a small percentage of sulfur. Typically, clean oil is hauled from our facilities to a truck terminal where it enters the North American pipeline system and is sold to purchasers at monthly spot prices. The majority of our oil production is sold at a bench mark price at Cromer, Canada and adjusted for equalization and all applicable transportation charges to Cromer. We have begun to ship some of our oil production from our Saskatchewan properties by rail, and we receive a price for this production similar to the benchmark price at Cromer after adjustments.

Our Canadian natural gas production is sold through a marketing consulting firm. We currently sell gas from our Alberta properties to a buyer at “spot” natural gas prices less transportation, fuel and measurement variance costs.

We sell a small amount of natural gas liquids extracted from some of our Alberta natural gas production to the processing plant operator at current spot prices.

Marketing of Midstream Services

We market our gathering services to area producers primarily through “one on one” industry contacts generated through general industry knowledge and new contacts made through participation in industry conferences, as well as by tracking drilling permits. Our business development team monitors exploration efforts within reach of the Eureka Hunter Gas Gathering System and is in regular contact with companies that may benefit from the gathering services offered by us.

We market our gas treatment plants and services in very much the same manner as our gathering services. Much of our gas treatment business growth comes from existing customers seeking additional plants and services. New business is generated by the our marketing team by regularly visiting with producers that have new or expanded drilling and production operations in those areas served by our gas treatment business, by tracking drilling permits and through other producer referrals. We also expand our presence by participating in industry conferences and trade shows and by helping to sponsor industry events that benefit charities and local community needs in our areas of operations.

Pricing

Our revenues, cash flows, profitability and future rate of growth depend substantially upon prevailing prices for oil and natural gas. Prices also affect the amount of cash flow available for capital expenditures and our ability to borrow money or raise additional capital. Lower prices may also adversely affect the value of our reserves and make it uneconomic for us to commence or continue drilling for crude oil and natural gas. Historically, the prices received for oil and natural gas have fluctuated widely. Among the factors that can cause these fluctuations are:


•	uncertainty in the global economy;


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


•	the condition of the United States, Canadian and global economies;


•	the actions of certain foreign countries;


•	the price and quantity of imports of foreign oil and liquid natural gas;


•	political conditions, including embargoes, war or civil unrest in or affecting oil producing activities of certain countries;


•	the level of United States and global oil and natural gas exploration and production activity;


•	the level of United States and global oil and natural gas inventories;


•	production or pricing decisions made by the Organization of Petroleum Exporting Countries;


•	weather conditions;


•	technological advances affecting energy consumption or production; and


•	the price and availability of alternative fuels.

Derivatives

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

Derivatives may expose us to risk of significant financial loss in certain situations, including circumstances where:


•	our production and/or sales of oil and natural gas are less than expected;


•	payments owed under a derivative contract come due prior to receipt of the covered month’s production revenue; or


•	the counterparty to the derivative contract defaults on its contract obligations.

In addition, derivative contracts we may enter into may limit the benefit we would receive from increases in the prices of oil and natural gas; if, for example, the increase in prices extends above the applicable ceiling under the derivative contract. Also, derivative contracts we may enter into may not adequately protect us from declines in the prices of oil and natural gas; if, for example, the decline in price does not extend below the applicable floor under the derivative contract.

Furthermore, should we choose not to engage in derivatives transactions in the future (to the extent we are not otherwise obligated to do so under our credit facilities), or we are unable to engage in such transactions due to a cross-default under a debt agreement, we may be adversely affected by volatility in oil and natural gas prices.

As of December 31, 2013, we had the following derivatives in place:



			Weighted Average
Natural Gas	Period	MMBtu/d	Price per MMBtu
Swaps	Jan 2014 - Dec 2014	10,000	$4.13
Ceilings purchased (call)	Jan 2014 - Dec 2014	10,000	$6.15
Ceilings sold (call)	Jan 2014 - Dec 2014	26,000	$5.47
Floors purchased (put)	Jan 2014 - Dec 2014	10,000	$4.25
Floors sold (put)	Jan 2014 - Dec 2014	10,000	$3.75

			Weighted Average
Crude Oil	Period	Bbl/d	Price per Bbl
Collars ⁽¹⁾	Jan 2014 - Dec 2014	663	$85.00 - $91.25
	Jan 2015 - Dec 2015	259	$85.00 - $91.25
Traditional three-way collar ⁽²⁾	Jan 2014 - Dec 2014	4,000	$64.94 - $85.00 - $102.50
Ceilings sold (call)	Jan 2015 - Dec 2015	1,570	$120.00
Floors sold (put)	Jan 2014 - Dec 2014	663	65.00
	Jan 2015 - Dec 2015	259	$70.00

________________________________

⁽¹⁾ A collar is a sold call and a purchased put. Some collars are "costless" collars with the premiums netting to approximately zero.

⁽²⁾ These three-way collars are a combination of three options: a sold call, a purchased put and a sold put.

Drilling Partnerships

Prior to our acquisition of NGAS Resources, Inc., or NGAS, in April 2011, NGAS had, from 1992 through 2010, sponsored approximately 38 private drilling partnerships for accredited investors to participate in certain of its drilling initiatives. Generally, under these NGAS drilling partnerships, proceeds from the private placement of interests in each investment partnership, together with an NGAS capital contribution, were contributed to a separate joint venture or “program” that NGAS formed with that partnership to conduct the drilling operations.

In December 2011, we completed a sponsored drilling partnership, Energy Hunter Partners 2011-A, Ltd., raising approximately $12.9 million from accredited investors. In December 2012, we completed another sponsored drilling partnership, Energy Hunter Partners 2012-A Drilling & Production Fund, Ltd., raising approximately $20.3 million from accredited investors.

These two drilling partnerships were structured to allow the investors to participate with us in certain Company drilling initiatives in certain operating regions of the Company, including unconventional resource plays. The drilling partnership participates in the designated project wells through a joint venture operating partnership, referred to as the program, with our Company, which serves as the managing general partner of both the drilling partnership and the program. Proceeds from the private placement of interests in the drilling partnership, together with our capital contributions, are contributed to the program to fund the program’s share of drilling and completion costs of the project wells. Generally, interests in the program are shared proportionately until distributions to the drilling partnership reach a certain percentage of its investment in the program (or in individual wells), after which we will earn an additional reversionary interest in the program, the amount of which depends on the timing of such payout. The program participates in the drilling and completion of the project wells on a "cost plus" basis.

We may sponsor additional drilling and/or income partnership or partnerships to participate in Company drilling initiatives. Our sponsored programs and any future sponsored programs are designed to enable us to accelerate the development of our properties without relinquishing control over drilling and operating decisions, while also enabling us to hold valuable acreage for future development.

Reserves

Our oil and natural gas properties are primarily located in (i) the Appalachian Basin in West Virginia, Ohio and Kentucky, with substantial acreage in the Marcellus Shale and Utica Shale areas in West Virginia and Ohio; and (ii) the Williston Basin in North Dakota and Canada. Cawley, Gillespie & Associates, Inc. (“CG&A”), independent petroleum consultants, has estimated our oil and natural gas reserves and the present value of future net revenues therefrom as of December 31, 2013. These estimates were determined based on prices for the twelve-month period ended December 31, 2013, and lease operating expenses as of August 31, 2013. Since January 1, 2013, we have not filed, nor were we required to file, any reports concerning our oil and gas reserves with any federal authority or agency, other than the SEC and regular survey reports provided to the U.S. Department of Energy. 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

At December 31, 2013, we held certain Eagle Ford Shale and Pearsall Shale assets that we retained when we sold most of our Eagle Ford Shale properties in April 2013. We sold substantially all of these remaining Eagle Ford Shale and Pearsall Shale assets in January 2014. See “—Our Significant Recent Developments—Sale of Remaining Eagle Ford Shale and Pearsall Shale Assets" below and "Note 19 - Subsequent Events" in the notes to our consolidated financial statements included in this report. The reserve information presented below includes reserves attributable to these January 2014 divested assets, as well as reserves attributable to our southern Appalachian Basin and Canadian assets held for sale.

The following table sets forth our estimated proved reserves quantities as defined in Rule 4.10(a) of Regulation S-X and Item 1200 of Regulation S-K promulgated by the SEC, as of December 31, 2013.



	Proved Reserves (SEC Prices at 12/31/13)
Category	Oil	NGL	Gas	PV-10 ⁽¹⁾
	(MBbl)	(MBbl)	(MMcf)	(in millions)
Proved Developed	12,085	6,990	176,585	$	707.9
Proved Undeveloped	12,250	3,432	70,197	214.2
Total Proved	24,335	10,422	246,782	$	922.1

_______________

(1)

Represents the present value, discounted at 10% per annum, or PV-10, of estimated future cash flows before income tax of our estimated proved reserves. The estimated future cash flows were determined based on proved reserve quantities and the periods in which they are expected to be developed and produced based on prevailing economic conditions. With respect to the PV-10 value in the table above, the estimated future production is priced based on the 12-month un-weighted arithmetic average of the first-day-of-the-month price for the period January through December 2013, using $96.78 per Bbl and $3.67 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. See “Non-GAAP Measures; Reconciliations” below.

All of our reserves are located within the continental U.S. and Canada. Reserve estimates are inherently imprecise and remain subject to revisions based on production history, results of additional exploration and development, prices of oil and natural gas and other factors. Please read “Item 1A. Risk Factors—Our estimated proved reserves are based on many assumptions that may turn out to be inaccurate. Any significant inaccuracies in these reserve estimates or underlying assumptions may materially affect the quantities and present value of our reserves”. You should also read the notes following the table below and our consolidated financial statements for the year ended December 31, 2013 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:



	2013		2012		2011
Description
Proved Developed Reserves
Oil (MBbl)	12,085.4		16,354.6		7,718.9
NGLs (MBbl)	6,989.4		6,262.6		1,459.8
Natural Gas (MMcf)	176,585.2		125,525.6		90,198.2
Proved Undeveloped Reserves⁽¹⁾
Oil (MBbl)	12,250.2		20,472.4		9,405.4
NGLs (MBbl)	3,432.4		2,862.7		3,125.8
Natural Gas (MMcf)	70,196.5		37,094.3		49,039.0

Total Proved Reserves (MBoe)⁽²⁾⁽³⁾	75,887.7		73,055.6		44,916.1

PV-10 Value (in millions)⁽⁴⁾	$	922.1	$	981.2	$	616.9
Standardized Measure (in millions)	$	844.5	$	847.7	$	474.4

_______________

(1)

We added 123 PUD locations during 2013, with the largest reserve value (nine PUDs with a value of 10.6 MMBoe) associated with the Marcellus Shale PUDs in Tyler County, West Virginia. 109 PUDs were added in 2013 in Divide County, North Dakota and the Tableland Field in Canada in the Bakken/Three Forks Sanish, with a reserve value of 7.4 MMBoe. Additionally, five PUDs were added in 2013 in the Eagle Ford Shale in Atascosa County, Texas, with a value of 1.1 MMBoe.

(2)

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.


(3)	We converted natural gas to oil equivalent at a ratio of six Mcf of natural gas to one Bbl of oil.

(4)

Represents the present value, discounted at 10% per annum, or PV-10, of estimated future cash flows before income tax of our estimated proved reserves. The estimated future cash flows were determined based on proved reserve quantities and the periods in which they are expected to be developed and produced based on prevailing economic conditions. With respect to the 2013 PV-10 value in the table above, the estimated future production is priced based on the 12-month un-weighted arithmetic average of the first-day-of-the-month price for the period January through December 2013, using $96.78 per Bbl and $3.67 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. See “Non-GAAP Measures; Reconciliations” below.

As of December 31, 2013, our proved undeveloped reserves, or PUDs, on an SEC case basis totaled 15.7 MMBoe of crude oil and NGL and 70.2 Bcf of natural gas for a total of 27.4 MMBoe. Increases in PUDs that occurred during the year were due primarily to increased drilling activity in our Marcellus Shale, Utica Shale and Bakken/Three Forks Sanish areas. Decreases in crude oil and NGLs were due to sales of proved reserves in place.

The following table summarizes the changes in our proved undeveloped reserves for the year ended December 31, 2013:



Proved Undeveloped Reserves (MBoe)	For the Year Ended December 31, 2013
Proved undeveloped reserves-beginning of year	29,517
Revisions of previous estimates ⁽¹⁾	(8,131	)
Extensions and discoveries	19,158
Conversions to proved developed reserves	(4,124	)
Purchases of reserves in place	—
Sales of reserves in place	(9,038	)
Proved undeveloped reserves-end of year	27,382

______________

(1) Downward revisions in estimated proved undeveloped reserve estimates were primarily related to our Williston Basin/Bakken Shale properties and resulted from lower than expected performance, higher operating expenses and downward fluctuating pricing during the year.

Our capital expenditures associated with the conversion of proved undeveloped reserves to proved developed reserves were approximately $32.8 million for the year ended December 31, 2013. We expect to develop all of our proved undeveloped reserves as of December 31, 2013 within five years of their initial booking.

The following table summarizes the changes in our proved reserves for the year ended December 31, 2013:



Proved Reserves (MBoe)	For the Year Ended December 31, 2013
Proved reserves—beginning of year	73,056
Revisions of previous estimates	22,891
Extensions and discoveries	862
Production	(5,034)
Purchases of reserves in place	15
Sales of reserves in place	(15,902)
Proved reserves—end of year	75,888
Proved developed reserves—beginning of year	43,538
Proved developed reserves—end of year	48,506

SEC Rules Regarding Reserves Reporting

In December 2008, the SEC adopted revisions to its rules designed to modernize oil and gas company reserves reporting requirements. The most significant amendments to the requirements included the following:


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


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


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


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


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


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

Reserve Estimation

CG&A evaluated our oil and gas reserves on a consolidated basis as of December 31, 2013. The technical persons responsible for preparing our proved reserves estimates meet the requirements with regard to qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. CG&A is a Texas Registered Engineering Firm (F-693), made up of independent registered professional engineers and geologists. The evaluation prepared by CG&A was supervised by Todd Brooker, Senior Vice President of CG&A. According to biographical information contained in CG&A’s reserve report, Mr. Brooker has been an employee of CG&A since 1992 and his responsibilities with CG&A include reserve and economic evaluations, fair market valuations, field studies, pipeline resource studies and acquisition / divestiture analysis. Also, according to biographical information contained in CG&A’s reserves report, Mr. Brooker graduated with honors from the University of Texas at Austin in 1989 with a B.S. in petroleum engineering, is a registered Professional Engineer in the State of Texas and is also a member of the Society of Petroleum Engineers. CG&A does not own an interest in any of our properties and is not employed by us on a contingent basis.

We maintain an internal staff of petroleum engineers and geoscience professionals who work closely with CG&A to ensure the integrity, accuracy and timeliness of the data used to calculate our proved oil and gas reserves. Our internal technical team members meet with CG&A periodically throughout the year to discuss the assumptions and methods used in the proved reserve estimation process. We provide historical information to CG&A for our properties such as ownership interest; oil and gas production; well test data; commodity prices; and operating and development costs. The preparation of our proved reserve estimates is completed in accordance with our internal control procedures, which include the verification of input data used by CG&A, as well as extensive management review and approval. All of our reserve estimates are reviewed and approved by our vice president of reservoir engineering. Our vice president of reservoir engineering holds a B.S. in chemical engineering from Ohio State University with more than 30 years of experience, was a member of the University of Texas External Advisory Committee for Petroleum and Geosystems Engineering and has served in various officer and board of director capacities for the Society of Petroleum Engineers. Reserve estimates for each of our divisions are also reviewed and approved by the president of that division.

The technologies used in the estimation of our proved reserves are commonly employed in the oil and gas industry and include seismic and micro-seismic operations, reservoir simulation modeling, analyzing well performance data and geological and geophysical mapping.

Acreage and Productive Wells Summary

The following table sets forth our gross and net developed and undeveloped oil and natural gas leasehold acreage as of January 31, 2014:



	Developed Acreage⁽¹⁾		Undeveloped Acreage⁽²⁾		Total Acreage
	Gross	Net	Gross	Net	Gross	Net
Appalachian Basin⁽³⁾	299,842	259,337	231,748	202,004	531,590	461,341

Williston Basin
United States	187,064	52,742	135,048	50,127	322,112	102,869
Canada	15,401	12,192	37,408	37,396	52,809	49,588
Texas and Louisiana ⁽⁴⁾	1,777	825	764	609	2,541	1,434
Other Canada ⁽⁵⁾	31,293	19,994	12,503	7,702	43,796	27,696
Total at January 31, 2014	535,377	345,090	417,471	297,838	952,848	642,928

_______________


(1)	Developed acreage is the number of acres allocated or assignable to producing wells or wells capable of production.


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


(3)	Approximately 47,409 gross acres and 42,418 net acres overlap in our Utica Shale and Marcellus Shale areas.


(4)	Pertains to certain miscellaneous properties in Texas and Louisiana.


(5)	Pertains to our Alberta properties.

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 the gross and net acres of undeveloped land subject to leases summarized in the preceding January 31, 2014 table that are not currently held by production and therefore will expire during the periods indicated below if not ultimately held by production by drilling efforts:



	Expiring Acreage
	2014		2015		2016		2017		2018
	Gross	Net	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Appalachian Basin⁽¹⁾	3,157	2,954	3,842	3,405	11,807	9,641	7,387	5,611	14,283	13,575
Williston Basin⁽²⁾	59,715	19,557	54,354	20,978	13,533	5,382	7,207	4,207	—	—
Texas and Louisiana⁽³⁾	—	—	—	—	764	609	—	—	—	—
	62,872	22,511	58,196	24,383	26,104	15,632	14,594	9,818	14,283	13,575


(1)	Expiring acreage in the Appalachian Basin does not include our southern Appalachian Basin properties that we intend to divest.


(2)	Expiring acreage in the Williston Basin does not include our Canadian properties that we intend to divest.


(3)	Pertains to certain miscellaneous properties in Texas and Louisiana.

Productive wells consist of producing wells and wells capable of production, including shut-in wells and gas wells awaiting pipeline connection to commence deliveries and oil wells awaiting connection to production facilities.

The following table sets forth the number of productive oil and gas wells attributable to the Company's properties (including our southern Appalachian Basin and Canadian assets held for sale) as of December 31, 2013:



	Producing Oil Wells		Producing Gas Wells		Total Producing Wells
	Gross	Net	Gross	Net	Gross	Net
Appalachian Basin	866	786.4	3,000	1,959.2	3,866	2,745.6
Williston Basin
United States	255	61.0	—	—	255	61
Canada	43	37.1	—	—	43	37.1
Texas and Louisiana ⁽¹⁾	4	3.3	6	1.7	10	5
Other Canada ⁽²⁾	4	2.7	40	38.0	44	40.7
Total	1,172	890.5	3,046	1,998.9	4,218	2,889.4

_______________


(1)	Pertains to certain miscellaneous properties in Texas and Louisiana and includes certain Eagle Ford Shale and Pearsall Shale assets that we sold in January 2014.


(2)	Pertains to our Alberta properties.

Drilling Results

The following table summarizes our drilling activity for the past three years. Gross wells reflect the sum of all wells in which we own an interest. Net wells reflect the sum of our working interests in gross wells. All of our drilling activities were conducted on a contract basis by independent drilling contractors, except for certain of our activities in the Eagle Ford Shale, Marcellus Shale and Utica Shale where we also utilized the drilling equipment of our oil field services business.



	2013					2012				2011
	Gross			Net		Gross		Net		Gross		Net
Exploratory Wells:
Productive	15		4.1	4.1		55		19.2		51		19.7
Unproductive	—			—		—		—		—		—
Total Exploratory	15			4.1		55		19.2		51		19.7
Developmental Wells:
Productive	86			36.3		84		33.5		47		19.8
Unproductive	—			—		—		—		—		—
Total Development	86			36.3		84		33.5		47		19.8
Productive	101			40.4		139		52.7		98		39.5
Unproductive	—			—		—		—		—		—
Total wells	101			40.4		139		52.7		98		39.5
Success Ratio ⁽¹⁾	100	%		100	%	100	%	100	%	100	%	100	%

_______________


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

As of January 31, 2014, we were in the process of drilling or completing, or awaiting frac on, 13 gross (9.6 net) wells on our Appalachian Basin properties and 9 gross (2.8 net) wells on our Williston Basin properties in North Dakota.

Oil and Gas Production, Prices and Costs

The following table shows the approximate net production from continuing operations attributable to our oil and gas interests, the average sales price and the average lease operating expense, attributable to our total oil and gas production and for fields that contain 15% of our total proved reserves. Production and sales information relating to properties acquired is reflected in this table only since the closing date of the acquisition and may affect the comparability of the data between the periods presented.



		2013		2012		2011
Post Rock (1)	Oil Production (Bbl)	4,325		2,280		4,131
	Natural Gas Production (Mcf)	4,442,449		4,434,407		1,979,842
	NGL Production (Bbl)	150,283		—		—
	Total Production (Boe)	895,016		741,348		334,104
	Oil Average Sales Price	$	83.84	$	72.79	$	80.9
	Natural Gas Average Sales Price	$	3.98	$	3.20	$	4.39
	NGL Average Sales Price	$	50.39	$	—	$	—
	Average LOE per Boe	$	10.30	$	2.44	5.01

Divide Field (2)	Oil Production (Bbl)	1,102,556		535,695		79,203
	Natural Gas Production (Mcf)	99,799		13,373		2,406
	Total Production (Boe)	1,119,190		537,924		79,604
	Oil Average Sales Price	$	90.72	$	80.17	$	84.92
	Natural Gas Average Sales Price	$	5.46	$	2.26	$	5.32
	Average LOE per Boe	$	12.21	$	11.04	$	15.2

Sistersville Field (3)	Oil Production (Bbl)	64,127		49,823		11,927
	Natural Gas Production (Mcf)	4,758,049		6,198,272		1,974,524
	NGL Production (Bbl)	153,413		24,659		—
	Total Production (Boe)	1,010,548		1,107,527		341,015
	Oil Average Sales Price	$	83.81	$	83.30	$	88.69
	Natural Gas Average Sales Price	$	4.14	$	3.24	$	4.93
	NGL Average Sales Price	50.4		33.67		$	—
	Average LOE per Boe	$	7.64	$	5.00	$	5.58

Total Company	Oil Production (Bbl)	1,564,331		939,019		429,611
	Natural Gas Production (Mcf)	10,351,610		11,211,764		4,573,898
	NGL Production (Bbl)	303,701		24,659		—
	Total Production (Boe)	3,593,302		2,832,305		1,191,927
	Oil Average Sales Price	$	89.79	$	82.19	$	87.26
	Natural Gas Average Sales Price	$	4.04	$	3.27	$	4.64
	NGL Average Sales Price	$	50.35	$	33.20	$	—
	Average LOE per Boe	$	15.02	$	9.47	$	12.58

_____________


(1)	This field is part of our Marcellus Shale acreage. This field consisted of 4,695 gross (4,666 net) acres in Wetzel County, West Virginia with 22 gross (13.5 net) producing wells as of January 31, 2014.


(2)	This field is part of our Bakken/Three Forks Sanish formations acreage. This field consisted of 322,112 gross (102,869 net) acres in Divide County, North Dakota, with 255 gross (61 net) producing wells as of January 31, 2014.


(3)	This field is part of our Marcellus Shale acreage. This field consisted of 26,446 gross (22,340 net) acres in Tyler County, West Virginia, with 15 gross (14.6 net) producing wells as of January 31, 2014.

Title to Properties

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


•	customary royalty interests;


•	liens incident to operating agreements and for current taxes;


•	obligations or duties under applicable laws;


•	development obligations under oil and gas leases;


•	net profit interests;


•	overriding royalty interests;


•	non-surface occupancy leases; and


•	lessor consents to placement of wells.

Non-GAAP Measures; Reconciliations

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

The standardized measure of discounted future net cash flows relating to our total proved oil and gas reserves as of December 31, 2013 is as follows:



	As of December 31, 2013 (unaudited)
	(in thousands)
Future cash inflows	$	3,711,260
Future production costs	(1,423,306		)
Future development costs	(421,797		)
Future income tax expense	(149,367		)
Future net cash flows	1,716,790
10% annual discount for estimated timing of cash flows	(872,280		)
Standardized measure of discounted future net cash flows related to proved reserves	$	844,510

Reconciliation of Non-GAAP Measure
PV-10	$	922,071
Less income taxes:
Undiscounted future income taxes	(149,368		)
10% discount factor	71,807
Future discounted income taxes	(77,561		)
Standardized measure of discounted future net cash flows	$	844,510

Competition

The oil and natural gas industry is highly competitive in all phases. We encounter competition from other oil and natural gas companies, including midstream services companies, in all areas of operation, including the acquisition of leases and properties, the securing of drilling, fracturing and other oilfield services and equipment and, with respect to our midstream operations, the acquisition of commitments from third party producers for the treating and gathering of natural gas. Our competitors include numerous independent oil and natural gas companies and individuals, as well as major international oil companies. Many of our competitors are large, well established companies that have substantially larger operating staffs and greater capital resources than we do.

The prices of our products are driven by the world oil market and North American natural gas markets. Thus, competitive pricing behavior in this regard is considered unlikely. However, competition in the oil and natural gas exploration industry exists in the form of competition to acquire the most promising properties and obtain the most favorable prices for the costs of drilling and completing wells. Competition for the acquisition of oil and gas properties is intense with many properties available in a competitive bidding process in which we may lack technological information or expertise available to other bidders. Therefore, we may not be

successful in acquiring and developing profitable properties in the face of this competition. Our ability to acquire additional properties in the future will depend upon our ability to evaluate and select suitable properties and to consummate transactions in an efficient manner even in a highly competitive environment. See “Item 1A. Risk Factors—Competition in the oil and natural gas industry is intense, which may adversely affect our ability to compete.”

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

Governmental Regulation

Our oil and natural gas exploration, development and production activities, and our midstream services activities, are subject to extensive laws, rules and regulations promulgated by federal, state and foreign legislatures and agencies. Failure to comply with such laws, rules and regulations can result in substantial penalties, including the delay or stopping of our operations. The legislative and regulatory burden on the oil and natural gas industry increases our cost of doing business and affects our profitability.

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

We commonly use hydraulic fracturing as part of our operations. Hydraulic fracturing typically is regulated by state oil and natural gas commissions, but the U.S. Environmental Protection Agency, referred to as the EPA, has asserted federal regulatory authority pursuant to the Safe Drinking Water Act over certain hydraulic fracturing activities involving the use of diesel. In addition, legislation has been introduced before Congress to provide for federal regulation of hydraulic fracturing under the Safe Drinking Water Act and to require disclosure of the chemicals used in the hydraulic fracturing process. Several states are also considering implementing, and some states, including Texas, have implemented, new regulations pertaining to hydraulic fracturing, including the disclosure of chemicals used in connection therewith. These existing and any future regulatory requirements may result in additional costs and operational restrictions and delays, which could have an adverse impact on our business, financial condition, results of operations and cash flows. See “Item 1A. Risk Factors—Federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.”

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

Formation

We were incorporated in the State of Delaware on June 4, 1997. In 2005, we began oil and gas operations under the name Petro Resources Corporation. In May 2009, we restructured our management team and refocused our business strategy, and in July 2009 we changed our name to Magnum Hunter Resources Corporation.

Employees

As of January 31, 2014, we had approximately 445 full-time employees. None of our employees is represented by a union. Management considers our relations with employees to be very good.

Facilities

Our principal executive offices are located in Houston, Texas, and consist of approximately 20,700 square feet of leased commercial office space. Our lease expires with respect to approximately 15,300 and 5,400 square feet of this space in April 2016 and May 2019, respectively.

Our Appalachian Basin offices consist of approximately 22,000 square feet of office space in an approximately 29,000 square foot commercial office building we own in Marietta, Ohio, and an additional 7,800 square feet of field office space in buildings (including portable buildings) we own in Reno, Ohio. We also occupy approximately 9,100 square feet of office space in a 45,000 square foot office building owned by us in Lexington, Kentucky. We also lease certain other field offices in Kentucky and West Virginia and an equipment storage yard in Kentucky.

Our Williston Basin offices consist of approximately 4,500 square feet of leased office space in Denver, Colorado, under a lease that expires in December 2014. We have approximately 8,300 square feet of leased office space in Calgary, Alberta, Canada, under a lease that expires in December 2014.

We maintain a field office and equipment storage yard on approximately 10 acres of land we own in Lavaca County, Texas related to our natural gas treating operations, and we maintain a field office and equipment storage yard on approximately 12 acres of land we own in Gonzalez County, Texas related to our oil field services operations.

We own a commercial office building in Grapevine, Texas containing approximately 10,200 square feet of office space and also lease approximately 3,500 square feet of office space in another commercial office building in Grapevine under a lease that expires in 2017. These offices house our principal accounting, financial reporting, information systems and human resources functions.

Segment Reporting; Major Customers

For information as to the geographic areas and industry segments in which we operate, namely U.S. Upstream, Canadian Upstream, Midstream and Oil Field Services, see "Note 15 - Other Information" in the notes to our consolidated financial statements included in this annual report. For information regarding our major customers for fiscal years 2011, 2012 and 2013, see "Note 13 - Major Customers" in the notes to our consolidated financial statements. This information is incorporated in this Item 1 by reference.

Available Information

Our principal executive offices are located at 777 Post Oak Blvd., Suite 650, Houston, Texas 77056. Our telephone number at this office is (832) 369-6986. We file annual, quarterly and current reports, proxy statements and other documents with the SEC under the Exchange Act. The public may read and copy any materials that we file with the SEC at the SEC’s Public Reference Room at 100 F Street N.E., Washington, D.C. 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. In addition, the SEC maintains a website that contains reports, proxy and information statements and other information that is electronically filed with the SEC. The public can obtain any documents that we file with the SEC at www.sec.gov.

We also make available free of charge on our website (www.magnumhunterresources.com) our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, any amendments to those reports and our proxy statements filed with or furnished to the SEC under the Exchange Act as soon as reasonably practicable after we file such material with, or furnish it to, the SEC. Information on our website does not constitute part of this or any other report filed with or furnished to the SEC.

GLOSSARY OF OIL AND NATURAL GAS TERMS

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



Bbl	Stock tank barrel, or 42 U.S. gallons liquid volume, used in this report in reference to crude oil or other liquid hydrocarbons.

Bcf	Billion cubic feet of natural gas.

Boe	Barrels of crude oil equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.

Condensate	Hydrocarbons which are in the gaseous state under reservoir conditions and which become liquid when temperature or pressure is reduced. A mixture of pentanes and higher hydrocarbons.

DDA&A	Depreciation, Depletion, Amortization & Accretion.

Development well	A well drilled within the proved area of a natural gas or oil reservoir to the depth of a stratigraphic horizon known to be productive.

EUR	Estimated ultimate recovery.

Exploratory well	A well drilled to find and produce natural gas or oil reserves not classified as proved, to find a new reservoir in a field previously found to be productive of natural gas or oil in another reservoir or to extend a known reservoir.

Field	An area consisting of either a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.

Frac or fracing	Hydraulic fracturing, a common practice that is used to stimulate production of oil and natural gas from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, sand and chemicals under pressure into a formation to fracture the surrounding rock and stimulate production.

IP-24 hour or IP-24	A measurement of the gross amount of production by a newly-opened well during the first 24 hours of production.

IP-7 day or IP-7	A measurement of the average daily gross amount of production by a newly-opened well during the first seven days of production.

IP-30 day or IP-30	A measurement of the average daily gross amount of production by a newly-opened well during the first 30 days of production.

LOE	Lease operating expense.

MBbl	Thousand barrels of crude oil or other liquid hydrocarbons.

MBoe	Thousand barrels of crude oil equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.

Mcf	Thousand cubic feet of natural gas.

Mcfe	Thousand cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.

MMBbl	Million barrels of crude oil or other liquid hydrocarbons.

MMBoe	Million barrels of crude oil equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.

MMBtu	Million British Thermal Units.

MMcf	Million cubic feet of natural gas.

NYMEX	New York Mercantile Exchange.

NGL	Natural gas liquids, or liquid hydrocarbons found in association with natural gas.



Proved oil and gas reserves	Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

	(i)	The area of the reservoir considered as proved includes: (A) The area identified by drilling and limited by fluid contacts, if any, and (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

	(ii)	In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering or performance data and reliable technology establish a lower contact with reasonable certainty.

	(iii)	Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering or performance data and reliable technology establish the higher contact with reasonable certainty.

	(iv)	Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (B) The project has been approved for development by all necessary parties and entities, including governmental entities.

	(v)	Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. For 2009 and subsequent years, the price shall be the average price during the 12-month period prior to the ending date of the period covered by the reserve report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

Proved developed oil and gas reserves		Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as “proved developed reserves” only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.

Proved undeveloped oil and gas reserves		Proved undeveloped oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.



Probable reserves	Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered. When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates. Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir. Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.

Possible reserves	Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates. Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project. Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves. Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the Company believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir. Where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.

R/P	The reserves to production ratio. The reserve portion of the ratio is the amount of a resource known to exist in an area and to be economically recoverable. The production portion of the ratio is the amount of resource used in one year at the current rate.



Secondary recovery	A recovery process that uses mechanisms other than the natural pressure of the reservoir, such as gas injection or water flooding, to produce residual oil and natural gas remaining after the primary recovery phase.

Standardized measure	The present value of estimated future cash inflows from proved oil and natural gas reserves, less future development, abandonment costs, net of salvage value, production and income tax expenses, discounted at 10% per annum to reflect timing of future cash flows and using the same pricing assumptions as were used to calculate PV-10. Standardized measure differs from PV-10 because standardized measure includes the effect of future income taxes.

Water flood	A method of secondary recovery in which water is injected into the reservoir formation to displace residual oil and enhance hydrocarbon recovery.

Working interest	The operating interest that gives the owner thereof the right to drill, produce and conduct operating activities on the property and receive a share of production and requires the owner to pay a share of the costs of drilling and production operations.

/d	"Per day" when used with volumetric volumes.

PART II

Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Report of Independent Registered Public Accounting Firm

Board of Directors and Shareholders

Magnum Hunter Resources Corporation

Houston, Texas

We have audited the accompanying consolidated balance sheets of Magnum Hunter Resources Corporation as of December 31, 2013 and 2012, and the related consolidated statements of operations, comprehensive loss, shareholders' equity, and cash flows for the years then ended. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

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

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Magnum Hunter Resources Corporation at December 31, 2013 and 2012, and the results of its operations and its cash flows for the years then ended, in conformity with accounting principles generally accepted in the United States of America.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Magnum Hunter Resources Corporation's internal control over financial reporting as of December 31, 2013, based on criteria established in Internal Control - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 25, 2014, expressed an adverse opinion thereon.

/s/ BDO USA, LLP

Dallas, Texas

February 25, 2014

F-1

Report of Independent Registered Public Accounting Firm

Board of Directors and Shareholders

Magnum Hunter Resources Corporation

Houston, Texas

We have audited Magnum Hunter Resources Corporation's internal control over financial reporting as of December 31, 2013, based on criteria established in Internal Control - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission (1992 COSO Framework). Magnum Hunter Resources Corporation's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying, “Item 9a. Management's Report on Internal Control Over Financial Reporting”. Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

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

A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the company's annual or interim financial statements will not be prevented or detected on a timely basis. Material weaknesses regarding management's failure to design and maintain internal control over financial reporting have been identified and include the following as described in management's assessment:


•	Controls over the intraperiod allocation of income taxes.


•	Controls over timely preparation and review of account reconciliations.


•	Controls over property accounting with respect to the accuracy and completeness of property records and related information, as a result of aggregated deficiencies.

These material weaknesses were considered in determining the nature, timing, and extent of audit tests applied in our audit of the 2013 consolidated financial statements, and this report does not affect our report dated February 25, 2014 on those consolidated financial statements.

F-2

In our opinion, Magnum Hunter Resources Corporation did not maintain, in all material respects, effective internal control over financial reporting as of December 31, 2013, based on the 1992 COSO Framework.

We do not express an opinion or any other form of assurance on management's statements referring to any corrective actions taken by the Company after the date of management's assessment.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Magnum Hunter Resources Corporation as of December 31, 2013 and 2012, and the related consolidated statements of operations, comprehensive loss, shareholders' equity, and cash flows for the years then ended and our report dated February 25, 2014, expressed an unqualified opinion thereon.

/s/ BDO USA, LLP

Dallas, Texas

February 25, 2014

F-3

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Stockholders

Magnum Hunter Resources Corporation

We have audited the accompanying consolidated statements of operations, comprehensive loss, shareholders' equity, and cash flows for the year ended December 31, 2011, of Magnum Hunter Resources Corporation and subsidiaries (collectively, the “Company”). These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audit.

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

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the results of operations of the Company and subsidiaries and their cash flows for the year ended December 31, 2011, in conformity with U.S. generally accepted accounting principles.

/s/ Hein & Associates LLP

Dallas, Texas

February 29, 2012, except for Note 18 and Note 2 as to which the dates are January 11, 2013 and November 27, 2013, respectively

F-4

Table of Contents

MAGNUM HUNTER RESOURCES CORPORATION

CONSOLIDATED BALANCE SHEETS

(in thousands, except share and per share data)



	December 31,
	2013			2012
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	41,713		$	57,623
Restricted cash	5,000			1,500
Accounts receivable, net of allowance for doubtful accounts of $292 and $448 as of December 31, 2013 and 2012, respectively	55,681			124,861
Derivative assets	608			5,146
Inventory	7,158			9,162
Investments	2,262			3,278
Prepaid expenses and other assets	2,938			2,249
Assets held for sale	5,366			500
Total current assets	120,726			204,319

PROPERTY, PLANT AND EQUIPMENT
Oil and natural gas properties, successful efforts method of accounting	1,355,288			1,908,659
Accumulated depletion, depreciation, and accretion	(130,629		)	(186,156		)
Total oil and natural gas properties, net	1,224,659			1,722,503
Gas transportation, gathering and processing equipment and other, net	289,420			201,910
Total property, plant and equipment, net	1,514,079			1,924,413

OTHER ASSETS
Deferred financing costs, net of amortization of $12,842 and $8,024 as of December 31, 2013 and 2012, respectively	20,008			23,862
Derivatives assets	25			—
Intangible assets, net	6,530			8,981
Goodwill	30,602			30,602
Other assets	1,994			6,455
Assets held for sale	162,687			—
Total assets	$	1,856,651		$	2,198,632

The accompanying Notes to Consolidated Financial Statements are an integral part of these Statements

F-5

Table of Contents

MAGNUM HUNTER RESOURCES CORPORATION

CONSOLIDATED BALANCE SHEETS

(in thousands, except share and per share data)



	December 31,
	2013			2012
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES
Current portion of notes payable	$	3,804		$	3,991
Accounts payable	107,860			196,515
Accrued liabilities	44,629			11,212
Revenue payable	6,313			20,394
Derivatives liabilities	1,903			3,501
Other liabilities	6,491			8,043
Liabilities associated with assets held for sale	12,865			—
Total current liabilities	183,865			243,656

Long-term debt	876,106			886,769
Asset retirement obligation	16,163			28,322
Deferred tax liability	—			74,258
Derivative liabilities	76,310			47,524
Other long-term liabilities	2,279			5,573
Liabilities associated with assets held for sale	14,523			—
Total liabilities	1,169,246			1,286,102

COMMITMENTS AND CONTINGENCIES (Note 18)
REDEEMABLE PREFERRED STOCK
Series C Cumulative Perpetual Preferred Stock, ("Series C Preferred Stock") cumulative dividend rate 10.25% per annum, 4,000,000 authorized, 4,000,000 issued and outstanding as of December 31, 2013 and 2012, with liquidation preference of $25.00 per share	100,000			100,000
Series A Convertible Preferred Units of Eureka Hunter Holdings, LLC, cumulative distribution rate of 8.0% per annum, 9,885,048 and 7,672,892 issued and outstanding as of December 31, 2013 and 2012, respectively, with liquidation preference of $200,620 and $167,403 as of December 31, 2013 and 2012, respectively	136,675			100,878
	236,675			200,878

SHAREHOLDERS' EQUITY
Preferred Stock of Magnum Hunter Resources Corporation, 10,000,000 authorized, including authorized shares of Series C Preferred Stock
Series D Cumulative Preferred Stock, ("Series D Preferred Stock") cumulative dividend rate 8.0% per annum, 5,750,000 authorized, 4,424,889 and 4,208,821 issued and outstanding as of December 31, 2013 and December 31, 2012, respectively, with liquidation preference of $50.00 per share	221,244			210,441
Series E Cumulative Convertible Preferred Stock, ("Series E Preferred Stock") cumulative dividend rate 8.0% per annum, 12,000 authorized, 3,803 and 3,755 issued and 3,722 and 3,705 shares outstanding as of December 31, 2013 and 2012, respectively, with liquidation preference of $25,000 per share	95,069			94,371
Common stock, $0.01 par value; 350,000,000 and 250,000,000 authorized, 172,409,023 and 170,032,999 issued and 171,494,071 and 169,118,047 outstanding as of December 31, 2013 and 2012, respectively	1,724			1,700
Exchangeable common stock, par value $0.01 per share, none and 505,835 shares issued and outstanding as of December 31, 2013 and 2012, respectively	—			5
Additional paid in capital	733,753			715,033
Accumulated deficit	(586,365		)	(307,484		)
Accumulated other comprehensive loss	(19,901		)	(8,889		)
Treasury Stock, at cost
Series E Cumulative Preferred Stock, 81 and 70 shares as of December 31, 2013 and 2012, respectively	(2,030		)	(1,750		)
Common stock, 914,952 shares as of December 31, 2013 and 2012	(1,914		)	(1,914		)
Total Magnum Hunter Resources Corporation shareholders' equity	441,580			701,513
Non-controlling interest	9,150			10,139
Total shareholders' equity	450,730			711,652
Total liabilities and shareholders’ equity	$	1,856,651		$	2,198,632

The accompanying Notes to Consolidated Financial Statements are an integral part of these Statements

F-6

Table of Contents

MAGNUM HUNTER RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except share and per share data)



	Year Ended December 31,
	2013			2012			2011

REVENUES AND OTHER
Oil and natural gas sales	$	197,599		$	114,659		$	58,726
Natural gas transportation, gathering, processing, and marketing	60,632			13,040			494
Oilfield services	18,431			12,333			7,149
Other revenue	3,749			324			86
Total revenue	280,411			140,356			66,455
OPERATING EXPENSES
Lease operating expenses	53,961			26,839			14,998
Severance taxes and marketing	17,721			7,854			5,341
Exploration	97,342			78,221			2,605
Natural gas transportation, gathering, processing, and marketing	52,099			8,028			373
Oilfield services	14,825			10,037			6,759
Impairment of proved oil and gas properties	9,968			3,772			—
Depreciation, depletion, amortization and accretion	99,198			59,730			23,246
Loss on sale of assets, net	44,654			628			361
General and administrative	75,407			53,454			54,360
Total operating expenses	465,175			248,563			108,043

OPERATING LOSS	(184,764		)	(108,207		)	(41,588		)

OTHER INCOME (EXPENSE)
Interest income	220			199			10
Interest expense	(72,423		)	(51,616		)	(11,752		)
Gain (loss) on derivative contracts, net	(25,274		)	22,239			(6,346		)
Other income (expense)	7,892			(1,583		)	—
Total other expense, net	(89,585		)	(30,761		)	(18,088		)
LOSS FROM CONTINUING OPERATIONS BEFORE INCOME TAX	(274,349		)	(138,968		)	(59,676		)
Income tax benefit (expense)	70,297			19,312			2,862
LOSS FROM CONTINUING OPERATIONS	(204,052		)	(119,656		)	(56,814		)
Loss from discontinued operations, net of tax	(71,131		)	(19,474		)	(19,598		)
Gain on disposal of discontinued operations, net of tax	52,019			2,409			—
NET LOSS	(223,164		)	(136,721		)	(76,412		)
Net loss (income) attributable to non-controlling interest	988			4,013			(249		)
NET LOSS ATTRIBUTABLE TO MAGNUM HUNTER RESOURCES CORPORATION	(222,176		)	(132,708		)	(76,661		)
Dividends on preferred stock	(56,705		)	(34,706		)	(14,007		)
NET LOSS ATTRIBUTABLE TO COMMON SHAREHOLDERS	$	(278,881	)	$	(167,414	)	$	(90,668	)
Weighted average number of common shares outstanding, basic and diluted	170,088,108			155,743,418			113,154,270
Loss from continuing operations per share, basic and diluted	$	(1.53	)	$	(0.96	)	$	(0.63	)
Income (loss) from discontinued operations per share, basic and diluted	(0.11		)	(0.11		)	(0.17		)
NET LOSS PER COMMON SHARE, BASIC AND DILUTED	$	(1.64	)	$	(1.07	)	$	(0.80	)

AMOUNTS ATTRIBUTABLE TO MAGNUM HUNTER RESOURCES
Loss from continuing operations, net of tax	$	(203,064	)	$	(115,643	)	$	(57,063	)
Income (loss) from discontinued operations, net of tax	(19,112		)	(17,065		)	(19,598		)
Net loss attributable to Magnum Hunter Resources	$	(222,176	)	$	(132,708	)	$	(76,661	)

The accompanying Notes to Consolidated Financial Statements are an integral part of these Statements

F-7

Table of Contents

MAGNUM HUNTER RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS

(in thousands)



	Year ended December 31,
	2013			2012			2011
NET LOSS	$	(223,164	)	$	(136,721	)	$	(76,412	)
OTHER COMPREHENSIVE INCOME (LOSS)
Foreign currency translation gain (loss)	(10,928		)	3,883			(12,477		)
Unrealized gain (loss) on available for sale investments	8,178			(309		)	14
Amounts reclassified from accumulated other comprehensive income upon sale of available for sale securities	(8,262		)	—			—
Total other comprehensive income (loss)	(11,012		)	3,574			(12,463		)
COMPREHENSIVE LOSS	(234,176		)	(133,147		)	(88,875		)
Comprehensive (income) loss attributable to non-controlling interests	988			4,013			(249		)
COMPREHENSIVE LOSS ATTRIBUTABLE TO MAGNUM HUNTER RESOURCES CORPORATION	$	(233,188	)	$	(129,134	)	$	(89,124	)

The accompanying Notes to Consolidated Financial Statements are an integral part of these Statements

F-8

Table of Contents

MAGNUM HUNTER RESOURCES CORPORATION

CONSOLIDATED STATEMENT OF SHAREHOLDERS' EQUITY

(in thousands)



	Number of Shares
	Series D Preferred Stock	Series E Preferred Stock	Common Stock	Exchangeable Common Stock		Series D Preferred Stock		Series E Preferred Stock		Common Stock		Exchangeable Common Stock			Additional Paid in Capital			Accumulated Deficit			Accumulated Other Comprehensive Loss			Treasury Stock			Unearned Common Shares in KSOP			Non-controlling Interest		Total Shareholders' Equity
BALANCE, January 1, 2011	—	—	74,863	—		$	—	$	—	$	749	$	—		$	152,439		$	(49,402	)	$	—		$	(1,310	)	$	(604	)	$	1,450	$	103,322
Share based compensation	—	—	121	—		—		—		1		—			25,056			—			—			—			—			—		25,057
Sale of Common Stock	—	—	1,714	—		—		—		17		—			13,875			—			—			—			—			—		13,892
Sale of Preferred Stock	1,438	—	—	—		71,878		—		—		—			(6,878		)	—			—			—			—			—		65,000
Shares of Common Stock issued upon exercise of warrants and options	—	—	6,293	—		—		—		63		—			7,555			—			—			—			—			—		7,618
Preferred dividends	—	—	—	—		—		—		—		—			—			(14,007		)	—			—			—			—		(14,007		)
Dividends on common stock in the form of 12,875,093 warrants with fair value of $6.7 million	—	—	—	—		—		—		—		—			—			—			—			—			—			—		—
Dividends on MHR Exchangeco Corporation's exchangeable common stock in the form of 378,174 warrants with fair market value of $197 thousand	—	—	—	—		—		—		—		—			—			—			—			—			—			—		—
Shares of Common Stock issued for acquisitions	—	—	45,713	—		—		—		456		—			342,278			—			—			—			—			—		342,734
Shares of Common Stock issued to employees for change in control payments for NGAS Resources	—	—	351	—		—		—		4		—			2,798			—			—			—			—			—		2,802
138,388 warrants issued in replacement of NGAS Resources warrants	—	—	—	—		—		—		—		—			190			—			—			—			—			—		190
Non-controlling interest acquired in NGAS acquisition	—	—	—	—		—		—		—		—			—			—			—			—			—			497		497
Exchangeable shares issued for acquisition of NuLoch Resources	—	—	—	4,276		—		—		—		43			31,600			—			—			—			—			—		31,643
shares of Common Stock issued upon exchange of MHR Exchangeco Corporation's exchangeable shares	—	—	582	(582	)	—		—		6		(6		)	—			—			—			—			—			—		—
Shares of Common Stock issued for commitment fee	—	—	166	—		—		—		2		—			777			—			—			—			—			—		779
Net loss	—	—	—	—		—		—		—		—			—			(76,661		)	—			—			—			249		(76,412		)
Foreign currency translation	—	—	—	—		—		—		—		—			—			—			(12,477		)	—			—			—		(12,477		)
Unrealized gain on available for sale securities	—	—	—	—		—		—		—		—			—			—			14			—			—			—		14
BALANCE, December 31, 2011	1,438	—	129,803	3,694		$	71,878	$	—	$	1,298	$	37		$	569,690		$	(140,070	)	$	(12,463	)	$	(1,310	)	$	(604	)	$	2,196	$	490,652
Share based compensation	—	—	108	—		—		—		1		—			15,695			—			—			—			—			—		15,696
Shares of common stock issued for payment of 401K plan matching contribution	—	—	199	—		—		—		2		—			872			—			—			—			—			—		874
Sale of Preferred Stock	2,771	1	—	—		138,563		25,000		—		—			(18,928		)	—			—			—			—			—		144,635
Sale of Common Stock	—	—	35,000	—		—		—		350		—			147,891			—			—			—			—			—		148,241
Shares of Common Stock issued upon exercise of warrants and options	—	—	1,438	—		—		—		14		—			2,317			—			—			—			—			—		2,331
Preferred dividends	—	—	—	—		—		—		—		—			—			(34,706		)	—			—			—			—		(34,706		)
Shares of Common Stock issued for acquisitions	—	—	297	—		—		—		3		—			1,899			—			—			—			—			—		1,902
Shares of Preferred Stock issued for acquisitions	—	3	—	—		—		69,371		—		—			(4,403		)	—			—			—			—			—		64,968

The accompanying Notes to Consolidated Financial Statements are an integral part of these Statements

F-9

Table of Contents

MAGNUM HUNTER RESOURCES CORPORATION

CONSOLIDATED STATEMENT OF SHAREHOLDERS' EQUITY

(in thousands)



shares of Common Stock issued upon exchange of MHR Exchangeco Corporation's exchangeable shares	—	—	3,188	(3,188	)	—		—		32		(32		)	—			—			—			—			—		—			—
Purchase of outstanding non-controlling interest in a subsidiary	—	—	—	—		—		—		—		—			—			—			—			—			—		(497		)	(497		)
Common units of Eureka Hunter Holdings issued for asset acquisition	—	—	—	—		—		—		—		—			—			—			—			—			—		12,453			12,453
Common shares returned to Treasury from KSOP	—	—	—	—		—		—		—		—			—			—			—			(604		)	604		—			—
Purchase of treasury shares	—	—	—	—		—		—		—		—			—			—			—			(1,750		)	—		—			(1,750		)
Net loss	—	—	—	—		—		—		—		—			—			(132,708		)	—			—			—		(4,013		)	(136,721		)
Foreign currency translation	—	—	—	—		—		—		—		—			—			—			3,883			—			—		—			3,883
Unrealized loss on available for sale securities	—	—	—	—		—		—		—		—			—			—			(309		)	—			—		—			(309		)
BALANCE, December 31, 2012	4,209	4	170,033	506		$	210,441	$	94,371	$	1,700	$	5		$	715,033		$	(307,484	)	$	(8,889	)	$	(3,664	)	$	—	$	10,139		$	711,652
Share based compensation	—	—	183	—		—		—		2		—			13,622			—			—			—			—		—			13,624
Shares of common stock issued for payment of 401k plan matching contribution	—	—	221	—		—		—		2		—			1,190			—			—			—			—		—			1,192
Sale of Preferred Stock	216	—	—	—		10,803		698		—		—			(1,320		)	—			—			—			—		—			10,181
Dividends on preferred stock	—	—	—	—		—		—		—		—			—			(56,705		)	—			—			—		—			(56,705		)
Conversion of exchangeable common stock for common stock	—	—	506	(506	)	—		—		5		(5		)	—			—			—			—			—		—			—
Fees on equity issuance	—	—	—	—		—		—		—		—			(109		)	—			—			—			—		—			(109		)
Depositary shares representing Series E Preferred Stock returned from escrow	—	—	—	—		—		—		—		—			—			—			—			(280		)	—		—			(280		)
Shares of common stock issued upon exercise of common stock options	—	—	1,466	—		—		—		15		—			5,337			—			—			—			—		—			5,352
Dividends on common stock in the form of 17,030,622 warrants with fair value of $21.6 million	—	—	—	—		—		—		—		—			—			—			—			—			—		—			—
Net loss	—	—	—	—		—		—		—		—			—			(222,176		)	—			—			—		(988		)	(223,164		)
Foreign currency translation	—	—	—	—		—		—		—		—			—			—			(10,928		)	—			—		—			(10,928		)
Unrealized loss on available for sale securities, net	—	—	—	—		—		—		—		—			—			—			(84		)	—			—		—			(84		)
Other																													(1		)	(1		)
BALANCE, December 31, 2013	4,425	4	172,409	—		$	221,244	$	95,069	$	1,724	$	—		$	733,753		$	(586,365	)	$	(19,901	)	$	(3,944	)	$	—	$	9,150		$	450,730

The accompanying Notes to Consolidated Financial Statements are an integral part of these Statements

F-10

Table of Contents

MAGNUM HUNTER RESOURCES CORPORATION

CONSOLIDATED STATEMENT OF CASH FLOWS

(in thousands)



	Year Ended December 31,
	2013			2012			2011
CASH FLOWS FROM OPERATING ACTIVITIES
Net loss	$	(223,164	)	$	(136,721	)	$	(76,412	)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Depletion, depreciation, amortization and accretion	134,867			135,896			49,090
Share-based compensation	13,624			15,696			25,057
Impairment of oil and gas properties	89,041			4,096			21,782
Exploration	115,069			116,686			1,118
Gain on sale of assets	(7,318		)	(3,074		)	(186		)
Cash paid for plugging wells	(14		)	—			—
Loss (gain) on open derivative contracts	17,058			(10,945		)	4,210
Loss (gain) on investments	(7,009		)	2,200			—
Amortization and write off of deferred financing cost and discount on Senior Notes included in interest expense	4,836			7,399			3,636
Deferred tax benefit	(84,527		)	(21,595		)	(696		)
Changes in operating assets and liabilities:
Accounts receivable, net	22,781			(73,549		)	(25,075		)
Inventory	4,658			(6,198		)	(3,889		)
Prepaid expenses and other current assets	(1,073		)	(538		)	(124		)
Accounts payable	42,050			16,390			25,883
Revenue payable	(11,589		)	8,776			6,979
Accrued liabilities	2,421			3,492			2,465
Net cash provided by operating activities	111,711			58,011			33,838
CASH FLOWS FROM INVESTING ACTIVITIES
Change in restricted cash	(3,500		)	—			—
Capital expenditures and advances	(631,511		)	(568,610		)	(291,942		)
Cash paid in acquisitions, net of cash received of $0; $34; and $2,500, respectively	—			(444,844		)	(78,524		)
Proceeds from sale of assets	506,297			4,158			8,709
Change in deposits and other long-term assets	854			89			42
Net cash used in investing activities	(127,860		)	(1,009,207		)	(361,715		)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from issuing Senior Notes	—			596,907			—
Proceeds from borrowings on debt	373,991			546,043			493,906
Principal repayments of debt	(380,923		)	(542,654		)	(242,472		)
Proceeds from sale of Series A preferred units in Eureka Hunter Holdings	35,280			149,655			—
Net proceeds from sale of common stock	—			148,241			13,892
Net proceeds from sale of preferred shares	10,072			144,635			94,764
Proceeds from exercise of warrants and options	5,352			2,331			7,618
Change in other long-term liabilities	(1,222		)	186			69
Purchase of treasury shares	—			(1,750		)	—
Payment of deferred financing costs	(1,246		)	(20,313		)	(11,577		)
Preferred stock dividends paid	(40,648		)	(26,839		)	(14,007		)
Net cash provided by financing activities	656			996,442			342,193
Effect of foreign exchange rate changes on cash	(417		)	(2,474		)	(19		)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	(15,910		)	42,772			14,297
CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR	57,623			14,851			554
CASH AND CASH EQUIVALENTS, END OF YEAR	$	41,713		$	57,623		$	14,851

The accompanying Notes to Consolidated Financial Statements are an integral part of these Statements

F-11

MAGNUM HUNTER RESOURCES CORPORATION

Notes to Consolidated Financial Statements

NOTE 1 - ORGANIZATION, NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Magnum Hunter Resources Corporation, a Delaware corporation, operating directly and indirectly through its subsidiaries (“Magnum Hunter” or the “Company”), is a Houston, Texas based independent exploration and production company engaged in the acquisition and development of producing properties and undeveloped acreage and the production of oil and natural gas in the United States and Canada, along with certain midstream and oil field service activities.

Presentation of Consolidated Financial Statements

The consolidated financial statements include the accounts of the Company and entities in which it holds a controlling interest. Our financial statements are prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP"). All significant intercompany balances and transactions have been eliminated. The preparation of our financial statements requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses. These estimates are based on information that is currently available to us and on various other assumptions that it believes to be reasonable under the circumstances. Actual results could differ from those estimates under different assumptions and conditions. Significant estimates are required for proved oil and gas reserves which may have a material impact on the carrying value of oil and gas property, and of assets held for sale.

Non-Controlling Interest in Consolidated Subsidiaries

The Company has consolidated Eureka Hunter Holdings, LLC (“Eureka Hunter Holdings”) in which it owns 56.4% and 61.0% as of December 31, 2013 and 2012, respectively. Eureka Hunter Holdings owns, directly or indirectly, 100% of the equity interests of Eureka Hunter Pipeline, LLC ("Eureka Hunter Pipeline"), TransTex Hunter, LLC and Eureka Hunter Land, LLC. On December 30, 2013, the Company’s subsidiary, PRC Williston, LLC ("PRC Williston"), in which the Company owned 87.5%, sold substantially all of its assets. The consolidated financial statements also reflect the interests of Magnum Hunter Production, Inc. (MHP) in various managed drilling partnerships. The Company accounts for the interests in these partnerships using the proportionate consolidation method.

Divestitures and Discontinued Operations

As a result of the sale of Hunter Disposal, LLC in 2012, the Company reclassified the assets and liabilities of this entity to assets and liabilities held for sale and the gain on sale and all prior operating income and expense for this entity as discontinued operations. On April 24, 2013, the Company sold all of its ownership interest in its 100%-owned subsidiary, Eagle Ford Hunter, Inc. ("Eagle Ford Hunter"). In September 2013, the Company adopted a plan to divest all of its interests in (i) MHP, a 100%-owned subsidiary of the Company whose oil and natural gas operations are located primarily in the southern Appalachian Basin in Kentucky and Tennessee, and (ii) the Canadian operations of Williston Hunter Canada, Inc., a 100%-owned subsidiary of the Company ("WHI Canada"). The Company has reflected the operations of Eagle Ford Hunter and MHP, which have historically been included as part of the U.S. Upstream operating segment and WHI Canada, which historically has been the only member of our Canadian Upstream segment, as discontinued operations for all periods presented. See "Note 2 - Divestitures and Discontinued Operations".

Reclassification of Prior-Year Balances

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

Cash and cash equivalents

Cash and cash equivalents include cash in banks and highly liquid debt securities that have original maturities of three months or less. At December 31, 2013, the Company had cash deposits in excess of FDIC insured limits at various financial institutions.

F-12

Financial Instruments

The carrying amounts of financial instruments including cash and cash equivalents, accounts receivable, notes receivable, accounts payable and accrued liabilities, derivatives, and certain long-term debt approximate fair value as of December 31, 2013 and 2012. See "Note 3 - Fair Value of Financial Instruments".

Inventory

The Company’s materials and supplies inventory is primarily comprised of frac sand used in the completion process of hydraulic fracturing. Frac sand is acquired for use in future well completion operations or repair operations and is carried at the lower of cost or market, on a first-in, first-out cost basis. “Market,” in the context of inventory valuation, represents net realizable value, which is the amount that the Company is allowed to bill to the joint accounts under joint operating agreements to which the Company is a party. Valuation reserve allowances for materials and supplies inventories are recorded as reductions to the carrying values of the materials and supply inventories in the Company’s consolidated balance sheets and as operating expense in the accompanying consolidated statements of operations. As of December 31, 2012 , the Company estimated that $3.5 million of its frac sand inventory would not be utilized within one year. Accordingly, those inventory values were classified as other long term assets in the accompanying consolidated balance sheet as of December 31, 2012. As of December 31, 2013 the frac sand inventory is anticipated to be entirely used within the coming year, and all inventories are classified as current.

Commodities inventories are carried at the lower of average cost or market, on a first-in, first-out basis. The Company’s commodities inventories consist of crude oil held in storage and is carried at the lower of average cost or market, on a first in, first out basis. Any valuation allowances of commodities inventories are recorded as reductions to the carrying values of the commodities inventories included in the Company’s consolidated balance sheets and as charges to lease operating expense in the consolidated statements of operations.

The following table sets forth the Company's inventory as of December 31, 2013 and December 31, 2012, respectively:



	2013		2012
	(in thousands)
Materials and supplies	$	6,790	$	11,531
Commodities	368		1,095
Less:
Materials included in other long term assets	—		(3,464		)
Inventory	$	7,158	$	9,162

Oil and Natural Gas Properties

Capitalized Costs

Our oil and natural gas properties comprised the following:



	December 31,
	2013			2012
	(in thousands)
Mineral interests in properties:
Unproved leasehold costs	$	469,337		$	645,164
Proved leasehold costs	336,357			454,556
Wells and related equipment and facilities	438,275			727,711
Uncompleted wells, equipment and facilities	97,748			71,665
Advances to operators for wells in progress	13,571			9,563
Total costs	1,355,288			1,908,659
Less accumulated depreciation, depletion, and amortization	(130,629		)	(186,156		)
Net capitalized costs	$	1,224,659		$	1,722,503

The Company follows the successful efforts method of accounting for oil and gas producing activities. Costs to acquire mineral interests in oil and gas properties and to drill and equip new development wells and related asset retirement costs are capitalized. Costs to acquire mineral interests and drill exploratory wells are also capitalized pending determination of whether the wells have

F-13

proved reserves or not. If the Company determines that the wells do not have proved reserves, the costs are charged to exploration expense. Geological and geophysical costs, including seismic studies and related costs of carrying and retaining unproved properties are charged to exploration expense as incurred.

On the sale or retirement of a complete unit of a proved property, the cost and related accumulated depreciation, depletion, and amortization are eliminated from the property accounts, and the resultant gain or loss is recognized. On the retirement or sale of a partial unit of proved property, the cost is charged to accumulated depreciation, depletion, and amortization with no resulting gain or loss recognized in income. A sale of an entire field is generally treated as discontinued operations.

Leasehold costs attributable to proved oil and gas properties are depleted by the unit-of-production method over total proved reserves. Capitalized development costs are depleted by the unit-of-production method over producing proved reserves. Depreciation, depletion, amortization and accretion expense for oil and gas producing property and related equipment was $69.0 million, $49.2 million, and $18.4 million for the years ended December 31, 2013, 2012, and 2011, respectively.

Unproved oil and gas leasehold costs that are individually significant are periodically assessed for impairment of value by comparing current quotes and recent acquisitions, and taking into account management's intent, and a loss is recognized at the time of impairment by providing an impairment allowance in exploration expense.

Capitalized costs related to proved oil and gas properties, including wells and related equipment and facilities, are evaluated for impairment quarterly based on an analysis of undiscounted future net cash flows. If undiscounted future net cash flows are insufficient to recover the net capitalized costs related to proved properties, then the Company recognizes an impairment charge in income from operations equal to the difference between the net capitalized costs related to proved properties and their estimated fair values based on the present value of the related future net cash flows and other relevant market value data. Impairment of proved oil and gas properties is calculated on a field by field basis.

It is common for operators of oil and gas properties to request that joint interest owners pay for large expenditures, typically for drilling new wells, in advance of the work commencing. This right to call for cash advances is typically a provision of the joint operating agreement that working interest owners in a property adopt. The Company records these advance payments to Advances in the property accounts and reclassifies amounts from this account when the actual expenditure is later billed to us by the operator.

If an unproved property is sold or the lease expires without identifying proved reserves, the cost of the property is charged to the impairment allowance. If a partial interest in an unproved property is sold, the amount received is treated as a reduction of the cost of the interest retained.

Estimates of Proved Oil and Natural Gas Reserves

Estimates of our proved reserves included in this report are prepared in accordance with U.S. SEC guidelines for reporting corporate reserves and future net revenue. The accuracy of a reserve estimate is a function of:

· the quality and quantity of available data;

· the interpretation of that data;

· the accuracy of various mandated economic assumptions; and

· the judgment of the persons preparing the estimate.

Our proved reserve information included in this report was predominately based on evaluations reviewed by independent third party petroleum engineers. Estimates prepared by other third parties may be higher or lower than those included herein. Because these estimates depend on many assumptions, all of which may substantially differ from future actual results, reserve estimates will be different from the quantities of oil and gas that are ultimately recovered. In addition, results of drilling, testing and production after the date of an estimate may justify material revisions to the estimate.

In accordance with SEC requirements, the Company based the estimated discounted future net cash flows from proved reserves on the unweighted arithmetic average of the prior 12-month commodity prices as of the first day of each of the months constituting the period and costs on the date of the estimate.

The estimates of proved reserves materially impact depreciation, depletion, amortization and accretion (DDA&A) expense. If the estimates of proved reserves decline, the rate at which the Company records DDA&A expense will increase, reducing future net income. Such a decline may result from lower market prices, which may make it uneconomic to drill for and produce from higher-cost fields.

Oil and Natural Gas Operations

Revenue Recognition

Revenues associated with sales of crude oil, natural gas, and natural gas liquids are recognized when title passes to the customer, which is when the risk of ownership passes to the purchaser and physical delivery of goods occurs, either immediately or within a fixed delivery schedule that is reasonable and customary in the industry.

F-14

Revenues from the production of natural gas and crude oil from properties in which the Company has an interest with other producers are recognized based on the actual volumes sold during the period. Any differences between volumes sold and entitlement volumes, based on our net working interest, which are deemed to be non-recoverable through remaining production, are recognized as accounts receivable or accounts payable, as appropriate. Cumulative differences between volumes sold and entitlement volumes are generally not significant.

During the years ended December 31, 2013, 2012, and 2011 the Company recognized sales of oil, natural gas and NGL as follows:



	Year Ended December 31,
	2013		2012		2011
			(in thousands)
Oil	$	140,426	$	77,172	$	37,520
Natural gas	41,867		36,657		21,206
NGL	15,306		830		—
Total oil and natural gas sales	$	197,599	$	114,659	$	58,726

Revenues from field servicing activities are recognized at the time the services are provided and earned as provided in the various contract agreements. Gas gathering revenues are recognized at the time the natural gas is delivered at the destination point.

Accounts Receivable

The Company recognizes revenue for our production when the quantities are delivered to or collected by the respective purchaser. Prices for such production are defined in sales contracts and are readily determinable or estimable based on available data.

Accounts receivable from joint interest owners consist of joint interest owner obligations due within 30 days of the invoice date. Accounts receivable, oil and gas sales, consist of accrued revenues due under normal trade terms, generally requiring payment within 30 to 60 days of production. The Company reviews accounts receivable periodically and reduce the carrying amount by a valuation allowance that reflects our best estimate of the amount that may not be collectible. As of December 31, 2013 and 2012, the Company had allowances for doubtful accounts of $0.3 million and $0.4 million respectively.

Revenue Payable

Revenue payable represents amounts collected from purchasers for oil and gas sales which are either revenues due to other working or royalty interest owners or severance taxes due to the respective state or local tax authorities. Generally, the Company is required to remit amounts due under these liabilities within 30 days of the end of the month in which the related production occurred.

Lease Operating Expenses

Lease operating expenses, including compressor rental and repair, pumpers’ salaries, saltwater disposal, ad valorem taxes, insurance, repairs and maintenance, workovers and other operating expenses are expensed as incurred. Transportation, gathering, and processing costs are expensed as incurred and included in lease operating expenses.

Exploration

Exploration expense consists primarily of impairment reserves for abandonment costs associated with unproved properties for which the Company has no further exploration or development plans, exploratory dry hole costs, and geological and geophysical costs. The following table provides the Company's exploration expense for 2013, 2012 and 2011:



	Year Ended December 31,
	2013		2012		2011
	(in thousands)
Geological and geophysical	$	1,402	$	2,570	$	1,497
Leasehold impairments:
Williston Basin	89,167		59,214		—
Appalachian Basin	6,773		15,033		802
South Texas	—		1,404		306
	$	97,342	$	78,221	$	2,605

F-15

The Company's exploration expense was primarily attributable to leasehold impairments, due to the large acreage position the Company initially acquired and results to date in the area, which led us to focus on other areas, thereby letting certain acreage expire in that region. The Company did not drill any dry holes in 2013, 2012, or 2011.

Impairment of Proved Oil and Natural Gas Properties

During the years ended December 31, 2013, 2012 and 2011, the Company recorded proved property impairments as follows:



	Year Ended December 31,
	2013		2012		2011
	(in thousands)
Williston Basin	$	8,498	$	3,631	$	—
Appalachian Basin	1,151		76		—
South Texas	319		65		—
	$	9,968	$	3,772	$	—

Severance Taxes and Marketing Costs

Severance taxes are comprised of production taxes charged by most states on oil, natural gas, and natural gas liquids produced. These taxes are computed on the basis of volumes and/or value of production or sales. These taxes are usually levied at the time and place the minerals are severed from the producing reservoir. Marketing costs are those directly associated with marketing our production and are based on volumes.

Gas Gathering and Processing Costs

Gas gathering and processing costs are those costs associated with oil and gas gathering revenues of our midstream operations.

Dependence on Major Customers

The Company's share of oil and gas production is sold to various purchasers who must be prequalified under the Company's credit risk policies and procedures. The Company records allowances for doubtful accounts based on the age of accounts receivables and the financial condition of its purchasers and, depending on facts and circumstances, may require purchasers to provide collateral or otherwise secure their accounts. The loss of any one significant purchaser could have a material, adverse effect on the ability of the Company to sell its oil and gas production in a certain region. Although the Company is exposed to a concentration of credit risk, it believes that all of its purchasers are credit worthy. See "Note 13 - Major Customers".

Dependence on Suppliers

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

Gas Transportation, Gathering and Processing Equipment and Other

Our gas gathering system assets and field servicing assets are carried at cost. The Company capitalizes interest on expenditures for significant construction projects that last more than six months while activities are in progress to bring the assets to their intended use. Interest of $2.6 million and $4.4 million was capitalized on our Eureka Hunter Gas Gathering System during the years ended 2013 and 2012, respectively. The Company did not capitalize any interest in 2011. Depreciation of gas gathering system assets is provided using the straight line method over an estimated useful life of fifteen years. Depreciation of field servicing assets is provided using the straight line method over various useful lives ranging from three to ten years. Gain or loss on retirement or sale or other disposition of assets is included in income in the period of disposition.

F-16

Furniture, fixtures and equipment are carried at cost. Depreciation of furniture, fixtures and equipment is provided using the straight-line method over estimated useful lives ranging from five to fifteen years. Gain or loss on retirement or sale or other disposition of assets is included in other income in the period of disposition.

Such equipment is comprised of the following:



	December 31,
	2013			2012
	(in thousands)
Gas transportation, gathering and processing equipment and other	$	315,642		$	218,656
Less accumulated depreciation and depletion	(26,222		)	(16,746		)
Net capitalized costs	$	289,420		$	201,910

Depreciation expense for other property and equipment was $15.6 million, $8.1 million, and $7.8 million, for the years ended December 31, 2013, 2012, and 2011, respectively.

TransTex Hunter sells and leases gas treating and processing equipment, much of which is leased to third party operators for treating gas at the wellhead. The leases generally have a term of three years or less. The equipment under leases in place as of December 31, 2013 had terms for future payments extending as far as December 2016. TransTex Hunter has non-cancelable leases to third parties in place as of December 31, 2013, with future minimum base rentals of $4.4 million, and $0.9 million, and $0.2 million for the years ending December 31, 2014, 2015, and 2016, respectively. Equipment leasing revenue is reported in gas transportation, gathering, and processing revenue in our statement of operations.

Deferred Financing Costs

In connection with debt financings, the Company paid $1.2 million and $20.3 million in fees in the year ended December 31, 2013, and 2012, respectively. These fees were recorded as deferred financing costs and are being amortized over the life of the debt instrument using the straight line method for debt in the form of a line of credit and effective interest method for term loans. Amortization and write off of deferred financing costs for the years ended December 31, 2013, 2012, and 2011 was $4.8 million, $7.1 million, and $3.6 million, respectively.

Commodity and Financial Derivative Instruments

The Company uses commodity and financial derivative instruments, typically options and swaps, to manage the risk associated with fluctuations in oil and gas prices, and the Company accounts for these instruments in accordance with ASC 815 - Derivatives and Hedging. The Company also has an embedded derivative liability resulting from certain conversion features, redemption options, and other features of our Series A Convertible Preferred Units of Eureka Hunter Holdings, LLC and an embedded derivative asset resulting from the bifurcated conversion feature associated with the convertible note received as partial consideration upon the sale of Hunter Disposal, LLC. See "Note 3 - Fair Value of Financial Instruments", "Note 2 - Divestitures and Discontinued Operations", "Note 10 - Shareholders' Equity", and "Note 16 - Related Party Transactions".

Derivative instruments are recorded at fair value in the balance sheet as either an asset or liability, with those contracts maturing in the next twelve months classified as current, and those maturing thereafter as long-term. The Company recognizes changes in the derivatives' fair values in earnings, as it has not designated our oil and gas price derivative contracts as cash flow hedges. The Company recognizes the gains and losses on settled and open transactions on a net basis within the “Gain (loss) on derivative contracts” line item within the “Other Income (expense)” section of the Consolidated Statement of Operations.

Investments

Investments are comprised of common and preferred stock of companies publicly traded on the TSX Venture Exchange and the NYSE MKT (formerly NYSE Amex) with quoted prices in active markets. On February 17, 2012, the Company received 1,846,722 restricted common shares of GreenHunter Resources, Inc., which has a carrying value of $0.6 million and $1.3 million at December 31, 2013 and 2012, respectively, and 88,000 shares of GreenHunter Resources, Inc. 10% Series C Preferred Stock, which has a fair value of $1.7 million and $1.7 million at December 31, 2013 and 2012, respectively, as partial consideration for the sale by our wholly-owned subsidiary, Triad Hunter, LLC, of its equity ownership interest in Hunter Disposal, LLC to GreenHunter Resources, Inc. The GreenHunter common stock investment is accounted for under the equity method within the scope of ASC 323: Investments - Equity Method. The Company initially accounted for its investment in GreenHunter’s Series C Preferred Stock under the cost method specified in ASC 325: Investments - Other. The preferred shares were cost basis investments from February 17, 2012 through July 31, 2012, since the preferred stock was not publicly traded and did not have a readily determinable fair value, and therefore ineligible for accounting under ASC 320: Investments - Debt and Equity Securities.

F-17

Beginning July 31, 2012, the GreenHunter Series C Preferred Stock is publicly traded with a readily determinable fair value and is classified as available for sale within the scope of ASC 320. Available-for-sale assets are securities and other financial investments that are neither held for trading, nor held to maturity, nor held for strategic reasons, and that have a readily available market price. As such, the gains and losses resulting from marking available-for-sale investments to market are not included in net income but are reflected in other comprehensive income until they are realized.

Below is a summary of changes in investments for the years ended December 31, 2013 and 2012:



	Available for Sale Securities (1)			Equity Method Investments (2)			Cost Method Investments
	(in thousands)
Fair value at December 31, 2011	$	497		$	—		$	—
Additional cost basis from acquisition	—			3,943			1,870
Transfers	1,770			—			(1,770		)
Decrease in carrying amount return of capital	—			—			(100		)
Equity in net loss recognized in other income (expense)	—			(1,333		)	—
Impairment in carrying value of equity method investment recognized in other income (expense)	—			(538		)	—
Change in fair value recognized in other comprehensive loss	(309		)	—			—
Fair value at December 31, 2012	$	1,958		$	2,072		$	—
Securities received as consideration	42,300			—			—
Sales of securities	(50,562		)	—			—
Realized gain recognized in net income	8,262			—			—
Decrease in carrying amount return of capital	—			(138		)	—
Equity in net loss recognized in other income (expense)	—			(767		)	—
Impairment in carrying value of equity method investment recognized in other income (expense)	—			(227		)	—
Other adjustments	(55		)	—
Change in fair value recognized in other comprehensive loss	(84		)	—			—
Fair value as of December 31, 2013	$	1,819		$	940		$	—

⁽¹⁾ Available for sale securities above includes $147,000 that has been classified as held for sale associated with the classification of the MHP subsidiary.

⁽²⁾Equity method investments includes $350,000 classified as long term other assets.

On April 24, 2013, the Company received 10.0 million shares of common stock of Penn Virginia Corporation valued at approximately $42.3 million as partial consideration for the sale of our wholly-owned subsidiary, Eagle Ford Hunter. As of September 30, 2013, the Company had sold all of the shares of Penn Virginia common stock, for total gross proceeds of approximately $50.6 million in cash, recognizing a gain of $8.3 million in other income.

Goodwill and Other Intangible Assets

During 2012, the Company recorded goodwill associated with the acquisition of the assets of TransTex Gas Services, LP, which represents the fair value of the acquired entity over the net amounts assigned to assets acquired and liabilities assumed. In accordance with GAAP, goodwill is not amortized to earnings, but is assessed annually in April for impairment, or whenever events or circumstances indicate that impairment of the carrying value of goodwill is likely. The Company has established April 1 as the annual testing date. If the carrying value of goodwill is determined to be impaired, it is reduced to its implied fair value with a corresponding charge to pretax earnings in the period in which it is determined to be impaired. Financial Accounting Standards Board ("FASB") Accounting Standards Update No. 2011-08, Intangibles - Goodwill and Other (Topic 350) permits an entity to first assess qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount as a basis for determining whether it is necessary to perform the two-step goodwill impairment test. The Company used this approach, and performed a full qualitative analysis of the need for impairment as of April 1, 2013. The Company performed a follow up analysis to determine if there were any triggering events as of December 31, 2013, and if an interim analysis was necessary, and none were determined to exist, as TransTex Gas Services, LP has experienced positive results on the Company's performance measures, and it has not experienced any significant adverse conditions.

F-18

Intangible assets consist primarily of the fair value of the acquired gas treating agreements and customer relationships in the TransTex Gas Services, LP assets acquisition. The intangible assets were valued at fair value using a discounted cash flow model with a discount rate at the date of acquisition of 13%. Such assets are being amortized over the weighted average term of 8.5 years. The customer relationships are being amortized with a 12.5 year life. The Company assesses the carrying amount of its other intangible assets for impairment when events or changes in circumstances indicate the carrying value may not be recoverable. At December 31, 2013, our other intangible assets were not impaired. See "Note 6 - Goodwill and Intangible Assets ".

Assets Held for Sale

Assets held for sale as of December 31, 2013 relate to the Company's interests in (i) Magnum Hunter Production, Inc. (“MHP”), a wholly-owned subsidiary of the Company whose oil and natural gas operations are located primarily in the southern Appalachian Basin in Kentucky and Tennessee, and (ii) the Canadian operations of Williston Hunter Canada, Inc., a wholly-owned subsidiary of the Company ("WHI Canada"). The Company is actively marketing these interests and anticipates completing the divestitures by the second quarter of 2014. Assets for sale as of December 31, 2012 relate to a drilling rig owned by Alpha Hunter Drilling, a subsidiary of Triad Hunter, LLC. The following table summarizes assets held for sale for the years indicated. See "Note 2 - Divestitures and Discontinued Operations.”



	December 31,
	2013		2012
	(in thousands)
MHP
Current portion	$	3,495	$	—
Long term portion	99,616		—
Total MHP assets held for sale	$	103,111	$	—
WHC
Current portion	$	1,871	$	—
Long term portion	63,071		—
Total WHC assets held for sale	$	64,942	$	—
Alpha Hunter Drilling
Current portion	$	—	$	500
Long-term portion	—		—
Total Alpha Hunter Drilling assets held for sale	$	—	$	500

Asset Retirement Obligation

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

The liability is determined using significant assumptions, including current estimates of plugging and abandonment costs, annual inflation of these costs, the productive lives of wells and our risk-adjusted interest rate. Changes in any of these assumptions can result in significant revisions to the estimated ARO. The liability for current and long term AROs were approximately $0.1 million and $16.2 million, respectively, at December 31, 2013, and $2.4 million and $28.3 million, respectively, at December 31, 2012. The liability for current AROs is reported in other current liabilities. See "Note 7 - Asset Retirement Obligations".

F-19

Share-Based Compensation

The Company estimates the fair value of share-based payment awards made to employees and directors, including stock options, restricted stock and matching contributions of stock to employees under our employee stock ownership plan, on the date of grant using an option-pricing model. The value of the portion of the award that is ultimately expected to vest is recognized as an expense ratably over the requisite service periods. Awards that vest only upon achievement of performance criteria are recorded only when achievement of the performance criteria is considered probable. The Company estimated the fair value of each share-based award using the Black-Scholes option pricing model or a lattice model. These models are highly complex and dependent on key estimates by management. The estimates with the greatest degree of subjective judgment are the estimated lives of the stock-based awards, the estimated volatility of our stock price, and the assessment of whether the achievement of performance criteria is probable.

Income Taxes

Income taxes are accounted for in accordance with FASB ASC 740, under which deferred income taxes are recognized for the future tax effects of temporary differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities using the enacted statutory tax rates in effect at year-end. The effect on deferred taxes for a change in tax rates is recognized in earnings in the period that includes the enactment date. A valuation allowance for deferred tax assets is recorded when it is more likely than not that the benefit from the deferred tax asset will not be realized.

Uncertain Income Tax Positions

Under accounting standards for uncertainty in income taxes (ASC 740-10), a company recognizes a tax benefit in the financial statements for an uncertain tax position only if management's assessment is that the position is “more likely than not” (i.e., a likelihood greater than 50 percent) to be allowed by the tax jurisdiction based solely on the technical merits of the position. The term “tax position” in the accounting standards for income taxes refers to a position in a previously filed tax return or a position expected to be taken in a future tax return that is reflected in measuring current or deferred income tax assets and liabilities for interim or annual periods. The Company had no uncertain tax positions at December 31, 2013 or 2012.

Loss per Common Share

Basic net income or loss per common share is computed by dividing the net income or loss attributable to common shareholders by the weighted average number of shares of common stock outstanding during the period. Diluted net income or loss per common share is calculated in the same manner, but also considers the impact to net income and common shares for the potential dilution from stock options, stock warrants and any outstanding convertible securities.

The Company has issued potentially dilutive instruments in the form of our restricted common stock granted and not yet issued, common stock warrants, common stock options granted to our employees and directors, and our Series E Cumulative Convertible Preferred Stock. The Company did not include any of these instruments in its calculation of diluted loss per share during the periods because to include them would be anti-dilutive due to the Company's loss from continuing operations during the periods.

The following table summarizes the types of potentially dilutive securities outstanding as of December 31, 2013, 2012 and 2011:



	December 31,
	2013	2012	2011
	(in thousands of shares)
Series E Preferred Stock	10,946	10,897	—
Warrants	17,169	13,376	13,526
Restricted shares granted, not yet issued	28	—	38
Common stock options	16,891	14,847	12,566
Total	45,034	39,120	26,130

Regulated Activities

Energy Hunter Securities, Inc. is a 100%-owned subsidiary and is a registered broker-dealer and member of the Financial Industry Regulatory Authority. Among other regulatory requirements, it is subject to the net capital provisions of Rule 15c3-1 under the Securities Exchange Act of 1934, as amended. Because it does not hold customer funds or securities or owe money or securities to customers, Energy Hunter Securities, Inc. is required to maintain minimum net capital equal to the greater of $5,000 or 6.67% of its aggregate indebtedness. At December 31, 2013 and 2012, Energy Hunter Securities, Inc. had net capital of $77,953 and $71,928, respectively, and aggregate indebtedness of $16,657 and $291,307, respectively.

Sentra Corporation, a 100%-owned subsidiary, owns and operates distribution systems for retail sales of natural gas in south central Kentucky. Sentra Corporation’s gas distribution billing rates are regulated by Kentucky’s Public Service Commission based on recovery of purchased gas costs. The Company accounts for its operations based on the provisions of ASC 980-605, Regulated

F-20

Operations–Revenue Recognition, which requires covered entities to record regulatory assets and liabilities resulting from actions of regulators. For the years ended December 31, 2013, 2012, and 2011, the Company had gas transmission, compression and processing revenue, reported in other revenue, which included gas utility sales from Sentra Corporation’s regulated operations aggregating $216,000, $511,000, and $61,000, respectively.

Other Comprehensive Income (Loss)

The functional currency of the Company's operations in Canada (which operations are reflected in these financial statements as discontinued operations) is the Canadian dollar. For purposes of consolidation, the Company translates the assets and liabilities of its Canadian subsidiary into U.S. dollars at current exchange rates while revenues and expenses are translated at the average rates in effect for the period. The related translation gains and losses are included in accumulated other comprehensive income. During the year ended December 31, 2013, 2012, and 2011 the Company recognized a translation loss of $10.9 million, a gain of $3.9 million, and a loss of $12.5 million, respectively.

Unrealized gains and losses on changes in fair value of common and preferred stock of publicly traded companies are included in accumulated other comprehensive income. As of September 30, 2013, the Company had completed the sale of all of the shares of the Penn Virginia common stock it acquired in connection with its sale of Eagle Ford Hunter in April 2013. The Company received gross proceeds of $50.6 million, resulting in a reclassification out of comprehensive income of $8.3 million, which is classified within other income.

NOTE 2 - DIVESTITURES AND DISCONTINUED OPERATIONS

Discontinued Operations

Sale of Hunter Disposal

On February 17, 2012, the Company, through its 100%-owned subsidiary, Triad Hunter, LLC, sold 100% of its equity ownership interest in Hunter Disposal, LLC, to a 100%-owned subsidiary of GreenHunter Resources, Inc., for total consideration of $9.3 million, comprised of cash of $2.2 million, 1,846,722 restricted common shares of GreenHunter Resources, Inc., valued at $2.6 million based on a closing price of $1.79 per share, discounted for restrictions, 88,000 shares of GreenHunter Resources, Inc. 10% Series C Preferred Stock, with a fair value of $1.9 million, and a promissory note of $2.2 million which is convertible, at the option of the Company, into 880,000 shares of GreenHunter Resources, Inc. common stock based on the conversion price of $2.50 per share. The Company recognized an embedded derivative asset resulting from the conversion option on the convertible promissory note with an initial fair value of $405,000. See "Note 3 - Fair Value of Financial Instruments". The cash proceeds from the sale were adjusted downward to $783,000 for changes in working capital and certain fees to reflect the effective date of the sale of December 31, 2011. Triad Hunter recognized a gain on the sale of discontinued operations of $3.7 million, $2.4 million net of tax of $1.3 million. GreenHunter Resources, Inc. is a related party as described in "Note 16 - Related Party Transactions".

Sale of Eagle Ford Hunter

On April 24, 2013, the Company closed on the sale of all of its ownership interest in its wholly-owned subsidiary, Eagle Ford Hunter to an affiliate of Penn Virginia for a total purchase price of approximately $422.1 million paid to the Company in the form of $379.8 million in cash (after estimated customary initial purchase price adjustments) and 10.0 million shares of common stock of Penn Virginia valued at approximately $42.3 million (based on the closing market price of the stock of $4.23 as of April 24, 2013). The effective date of the sale was January 1, 2013. Upon closing of the sale, $325.0 million of sale proceeds were used to pay down outstanding borrowings under the MHR Senior Revolving Credit Facility. During the third quarter of 2013, the Company had completed the sale of all of its Penn Virginia common stock for gross proceeds of $50.6 million, recognizing a gain of $8.3 million in other income. Initially, the Company has recognized a gain on the sale of $172.5 million, net of tax.

On August 24, 2013, the Company presented Penn Virginia with the Company’s estimate of the final settlement of the adjustments to the cash portion of the purchase price, to which Penn Virginia responded on October 21, 2013 with its calculation of the final adjustment amounts. On February 3, 2014, the Company submitted its updated calculation of the final adjustment amount to the arbitrator in the amount of $26.6 million (on a pre-tax basis) and Penn Virginia submitted its updated calculation of the final adjustment amount in the amount of $56.4 million. The Company is currently in the process of reviewing Penn Virginia’s calculation of the final adjustment amounts. As of December 31, 2013, the Company estimated that the final settlement of the adjustment amounts may result in an obligation to Penn Virginia ranging from $22 million to $33 million, net of taxes, but such estimate is subject to further review by the Company and discussions with Penn Virginia. Therefore, the Company has recorded a liability for its revised estimate of the final settlement of the adjustment amounts, after taxes, as a reduction in the gain on disposal of discontinued operations of Eagle Ford Hunter.

F-21

Planned Divestitures of Magnum Hunter Production and Williston Hunter Canada

In September 2013, the Company adopted a plan to divest all of its interests in (i) Magnum Hunter Production, Inc. (“MHP”), a wholly-owned subsidiary of the Company whose oil and natural gas operations are located primarily in the southern Appalachian Basin in Kentucky and Tennessee, and (ii) the Canadian operations of Williston Hunter Canada, Inc., a wholly-owned subsidiary of the Company ("WHI Canada"). The Company is actively marketing these interests and anticipates completing the divestitures by the second quarter of 2014. The Company has reclassified the associated assets and liabilities to assets and liabilities held for sale and the operations are reflected as discontinued operations for all periods presented. The Company has recorded an impairment expense of $56.7 million , net of tax, for the year ended December 31, 2013 relating to the discontinued operations which is recorded in income (loss) from discontinued operations and an expense of $92.4 million, net of tax, to reflect the net assets at their estimated selling prices, less costs to sell, which is recorded in loss on disposal of discontinued operations for the year ended December 31, 2013.

The Company included the results of operations of MHP and WHI Canada for all periods presented, Eagle Ford Hunter through April 24, 2013, and Hunter Disposal through February 17, 2012 in discontinued operations as follows:



	Year Ended December 31,
	2013			2012			2011
	(in thousands)
Revenues	$	91,364		$	133,643		$	60,633
Expenses ⁽¹⁾	(174,049		)	(160,127		)	(79,431		)
Other income (expense)	6,847			3,431			1,366
Income (loss) from discontinued operations before tax	(75,838		)	(23,053		)	(17,432		)
Income tax benefit (expense) ⁽²⁾	4,707			3,579			(2,166		)
Income (loss) from discontinued operations, net of tax	(71,131		)	(19,474		)	(19,598		)
Gain on disposal of discontinued operations, net of taxes ⁽³⁾⁽⁴⁾	52,019			2,409			—
Loss from discontinued operations, net of tax	$	(19,112	)	$	(17,065	)	$	(19,598	)

_____________________


(1)	Includes impairment expense of $78.5 million, $324,000, and none for the years ended December 31, 2013, 2012, and 2011, respectively, and exploration expense of $19.6 million, $38.7 million, and none for the years ended December 31, 2013, 2012, and 2011, respectively relating to the discontinued operations of MHP and WHI Canada, which is recorded in income (loss) from discontinued operations.


(2)	The Company’s effective tax rate on the loss from discontinued operations is 6.2% primarily due to the significant losses generated in WHI Canada, which has an overall lower statutory tax rate further lowered by the utilization of certain net operating losses.


(3)	Income tax expense associated with gain/(loss) on sale of discontinued operations was $1.4 million, $1.3 million, and none for the years ended December 31, 2013, 2012, and 2011, respectively.


(4)	The Company’s effective tax rate on the gain on disposal of discontinued operations is 2.6% primarily due to the anticipated utilization of a capital loss on the sale of WHI Canada against the capital gains included in discontinued operations.

Other Divestitures

Sale of Certain North Dakota Oil and Natural Gas Properties

On September 2, 2013, Williston Hunter, Inc., a wholly owned subsidiary of the Company, entered into a purchase and sale agreement with Oasis Petroleum of North America LLC, or Oasis, to sell its non-operated working interest in certain oil and natural gas properties located in Burke County, North Dakota, to Oasis for $32.5 million in cash, subject to customary adjustments. The transaction closed on September 26, 2013, and was effective as of July 1, 2013. The Company recognized a loss of $38.1 million on the sale for the year ended December 31, 2013.

On December 30, 2013, PRC Williston, LLC and Williston Hunter ND, LLC , subsidiaries of the Company, closed on the sale of certain assets to Enduro Operating LLC, (“Enduro”). The Enduro sale included certain oil and gas properties and assets located in Burke, Renville, Bottineau and McHenry Counties, North Dakota, including operated working interests in approximately 180 wells producing primarily from the Madison formation in the Williston Basin. The effective date of the sale was September 1, 2013. The total purchase price, after initial purchase price adjustments, was $44.1 million in cash. The Company recognized a preliminary loss of $8.2 million and final determination of the customary adjustments to the purchase price will be made by the parties approximately 120 days after closing.

F-22

NOTE 3 - FAIR VALUE OF FINANCIAL INSTRUMENTS

Accounting standards define fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The standards also establish a framework for measuring fair value and a valuation hierarchy based upon the transparency of inputs used in the valuation of an asset or liability. Classification within the hierarchy is based upon the lowest level of input that is significant to the fair value measurement. The valuation hierarchy contains three levels:



●	Level 1 — Quoted prices (unadjusted) for identical assets or liabilities in active markets;

●	Level 2 — Quoted prices for similar assets or liabilities in active markets; quoted prices for identical or similar assets or liabilities in markets that are not active; and model-derived valuations whose inputs or significant value drivers are observable;

●	Level 3 — Significant inputs to the valuation model are unobservable.

The Company used the following fair value measurements for certain of its assets and liabilities during the years ended December 31, 2013 and 2012:

Level 1 Classification:

Available for Sale Securities

At December 31, 2013, the Company held common and preferred stock of companies publicly traded on the TSX Venture Exchange and the NYSE MKT (formerly NYSE Amex) with quoted prices in active markets. Accordingly, the fair market value measurements of these securities have been classified as Level 1.

Level 2 Classification:

Commodity Derivative Instruments

At December 31, 2013 and December 31, 2012, the Company had commodity derivative financial instruments in place. The Company does not designate its derivative instruments as hedges and therefore does not apply hedge accounting. Changes in fair value of derivative instruments subsequent to the initial measurement are recorded as gain (loss) on derivative contracts, in other income (expense). The estimated fair values of the Company’s derivative instruments have been determined at discrete points in time based on relevant market information which resulted in the Company classifying such derivatives as Level 2. Although the Company’s derivative instruments are valued using public indices, the instruments themselves are traded with unrelated counterparties and are not openly traded on an exchange. See "Note 4 - Financial Instruments and Derivatives".

As of December 31, 2013 and December 31, 2012, the Company’s derivative contracts were with financial institutions, all of which were either senior lenders to the Company or affiliates of such senior lenders, and some of which had investment grade credit ratings. All of the counterparties are believed to have minimal credit risk. Although the Company is exposed to credit risk to the extent of nonperformance by the counterparties to these derivative contracts, the Company does not anticipate such nonperformance and monitors the credit worthiness of its counterparties on an ongoing basis.

Level 3 Classification:

Preferred Stock Embedded Derivative

At December 31, 2013, the Company had preferred stock derivative liabilities resulting from certain conversion features, redemption options, and other features of its Series A Convertible Preferred Units of Eureka Hunter Holdings, LLC. See "Note 11 - Redeemable Preferred Stock".

The preferred stock embedded derivative was valued using the “with and without” analysis in a simulation model. The key inputs used in the model to determine fair value at December 31, 2013 were a volatility of 25.0%, credit spread of 13.90%, and an estimated enterprise value of Eureka Hunter Holdings of $568.0 million.

Convertible Security Embedded Derivative

The Company recognized an embedded derivative asset resulting from the fair value of the bifurcated conversion feature associated with the convertible note received as partial consideration upon the sale of Hunter Disposal, LLC ("Hunter Disposal") to GreenHunter Resources, Inc. ("GreenHunter"), a related party. See "Note 2 - Divestitures and Discontinued Operations". The convertible security embedded derivative was valued using a Black-Scholes model valuation of the conversion option.

F-23

The key inputs used in the Black-Scholes option pricing model were as follows:



	December 31, 2013
Life	3.1		years
Risk-free interest rate	0.93		%
Estimated volatility	40		%
Dividend	—
GreenHunter Resources Stock price at end of period	$	1.18

The following table presents the changes in the fair value of the derivative assets and liabilities measured at fair value using significant unobservable inputs for the year ended December 31, 2013:



	Embedded Derivatives
	Series A Preferred Units			Convertible Security
	(in thousands)
Fair value at December 31, 2012	$	(43,548	)	$	264
Issued or acquired embedded derivative asset (liability)	(14,645		)	—
Change in fair value recognized in other income (expense)	(17,741		)	(185		)
Fair value as of December 31, 2013	$	(75,934	)	$	79

F-24

The following tables present financial assets and liabilities which are adjusted to fair value on a recurring basis at December 31, 2013 and 2012:



	Fair Value Measurements on a Recurring Basis
	December 31, 2013
	(in thousands)
	Level 1		Level 2		Level 3
Available for sale securities	$	1,819	$	—	$	—
Commodity derivative assets	—		554		—
Convertible security derivative assets	—		—		79
Total assets at fair value	$	1,819	$	554	$	79

Commodity derivative liabilities	$	—	$	2,279	$	—
Convertible preferred stock derivative liabilities	—		—		75,934
Total liabilities at fair value	$	—	$	2,279	$	75,934



	Fair Value Measurements on a Recurring Basis
	December 31, 2012
	(in thousands)
	Level 1		Level 2		Level 3

Available for sale securities	$	1,958	$	—	$	—
Commodity derivative assets	—		4,882		—
Convertible security derivative assets	—		—		264
Total assets at fair value	$	1,958	$	4,882	$	—

Commodity derivative liabilities	$	—	$	7,477	$	—
Convertible preferred stock derivative liabilities	—		—		43,548
Total liabilities at fair value	$	—	$	7,477	$	43,548

Other Fair Value Measurements

The carrying value of the Company's senior revolving credit facility (the “MHR Senior Revolving Credit Facility") approximates fair value as it is subject to short-term floating interest rates that approximate the rates available to us for those periods. The fair value hierarchy for the MHR Senior Revolving Credit Facility is Level 3.

The fair value of the Company's Senior Notes is based on quoted market prices available for our senior notes. The estimated fair value of the Company's Senior Notes as of December 31, 2013 and December 31, 2012 was $651.3 million and $613.5 million, respectively. The fair value hierarchy for the Company's Senior Notes is Level 2 (quoted prices for similar assets in active markets).

The fair value of Eureka Hunter Pipeline's second lien term loan is the estimated cost to acquire the debt, including a credit spread for the difference between the issue rate and the period end market rate. The credit spread is the Company’s default or repayment risk. The credit spread (premium or discount) is determined by comparing the Company’s fixed-rate notes and credit facility to new issuances (secured and unsecured) and secondary trades of similar size and credit statistics for both public and private debt. The fair value of all fixed-rate notes and the credit facility is based on interest rates currently available to the Company. Eureka Hunter Pipeline's second lien term loan is valued using an income approach and classified as Level 3 in the fair value hierarchy.

F-25

The Company uses available market data and valuation methodologies to estimate the fair value of debt. The carrying amounts and fair values of long-term debt are as follows:



	Fair Value	December 31, 2013				December 31, 2012
	Hierarchy Level	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
		(in thousands)
Senior Notes ⁽¹⁾	Level 2	$	597,230	$	651,300	$	597,212	$	613,500
MHR Senior Revolving Credit Facility ⁽²⁾	Level 3	218,000		218,000		225,000		225,000
Eureka Hunter Pipeline, LLC second lien term loan ⁽³⁾	Level 3	50,000		58,921		50,000		58,550
Equipment notes payable ⁽³⁾	Level 3	18,615		17,676		18,548		17,450

________________________________

⁽¹⁾ The fair value of the Company's Senior Notes is based on quoted market prices.

⁽²⁾The carrying value of each of the MHR Senior Revolving Credit Facility and Magnum Hunter's second lien term loan approximates fair value as it is subject to short-term floating interest rates that approximate the rates available to us at such date.

⁽³⁾ The fair value of (a) Eureka Hunter Pipeline’s second lien term loan and (b) equipment note payable, is the estimated cost to acquire the debt, including a credit spread for the difference between the issue rate and the period end market rate.

Fair Value on a Non-Recurring Basis

The Company follows the provisions of ASC 820-10 for nonfinancial assets and liabilities measured at fair value on a non-recurring basis. As it relates to Magnum Hunter, ASC 820-10 applies to certain nonfinancial assets and liabilities as may be acquired in a business combination and thereby measured at fair value; measurements of oil and natural gas property impairments; and the initial recognition of AROs, for which fair value is used. These ARO estimates are derived from historical costs as well as management's expectation of future cost environments. As there is no corroborating market activity to support the assumptions used, Magnum Hunter has designated these measurements as Level 3.

A reconciliation of the beginning and ending balances of Magnum Hunter's ARO is presented in "Note 7 - Asset Retirement Obligations".

New fair value measurements of proved oil and natural gas properties during the year ended December 31, 2013 and 2012 consist of:



Fair Value Measurements on a Non-recurring Basis
	(Level 1)		(Level 2)		(Level 3)
	(in thousands)
Proved properties impaired ⁽¹⁾	$	—	$	—	$	1,024
Total during the year ended December 31, 2013	$	—	$	—	$	1,024

Proved properties impaired ⁽¹⁾	$	—	$	—	$	58,082
Acquisitions ⁽²⁾	—		—		532,150
Total during the year ended December 31, 2012	$	—	$	—	$	590,232

________________________________

⁽¹⁾The Company recorded impairment charges from continuing operations of $10.0 million and $3.8 million during the years ended December 31, 2013 and 2012, respectively, as a result of writing down the carrying value of certain properties to fair value. In order to determine fair value, Magnum Hunter compares net capitalized costs of proved oil and natural gas properties to estimated undiscounted future net cash flows using management's expectations of economically recoverable reserves. If the net capitalized cost exceeds the undiscounted future net cash flows, Magnum Hunter impairs the net cost basis down to the discounted future net cash flows, which is management's estimate of fair value. Significant inputs used to determine the fair value include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average

cost of capital rate. The underlying commodity prices embedded in the Company's estimated cash flows are the product of a process that begins with third party analyst forward curve pricing, adjusted for estimated location and quality differentials, as well as other factors that Magnum Hunter's management believes will impact realizable prices. The inputs used by management for the fair value

F-26

measurements utilized in this review include significant unobservable inputs, and therefore, the fair value measurements employed are classified as Level 3 for these types of assets.

⁽²⁾Magnum Hunter records the fair value of assets and liabilities acquired in business combinations. During the year ended December 31, 2012, Magnum Hunter acquired oil and natural gas properties with a fair value of $532.2 million. Properties acquired are recorded at fair value, which correlates to the discounted future net cash flow. Significant inputs used to determine the fair value of proved properties include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital rate. The underlying commodity prices embedded in the Company's estimated cash flows are the product of a process that begins with third party analyst forward curve pricing, adjusted for estimated location and quality differentials, as well as other factors that Magnum Hunter's management believes will impact realizable prices. For acquired unproved properties, the market-based weighted average cost of capital rate is subjected to additional project specific risking factors. The inputs used by management for the fair value measurements of these acquired oil and natural gas properties include significant unobservable inputs, and therefore, the fair value measurements employed are classified as Level 3 for these types of assets.

NOTE 4 - FINANCIAL INSTRUMENTS AND DERIVATIVES

The Company periodically enters into certain commodity derivative instruments such as futures contracts, swaps, collars, and basis swap contracts, which are effective in mitigating commodity price risk associated with a portion of its future monthly natural gas and crude oil production and related cash flows. The Company has not designated any of its commodity derivatives as hedges under ASC 815.

In a commodities swap agreement, the Company trades the fluctuating market prices of oil or natural gas at specific delivery points over a specified period, for fixed prices. As a producer of oil and natural gas, the Company holds these commodity derivatives to protect the operating revenues and cash flows related to a portion of its future natural gas and crude oil sales from the risk of significant declines in commodity prices, which helps reduce exposure to price risk and improves the likelihood of funding its capital budget. If the price of a commodity rises above what the Company has agreed to receive in the swap agreement, the amount that it agreed to pay the counterparty would theoretically be offset by the increased amount it received for its production.

The Company also enters into three-way collars with third parties. These instruments typically establish two floors and one ceiling. Upon settlement, if the index price is below the lowest floor, the Company receives the difference between the two floors. If the index price is between the two floors, the Company receives the difference between the higher of the two floors and the index price. If the index price is between the higher floor and the ceiling, the Company does not receive or pay any amounts. If the index price is above the ceiling, the Company pays the excess over the ceiling price. The advantage to the Company of the three-way collar is that the proceeds from the second floor allow us to lower the total cost of the collar.

The Company's failure to service any of its debt or to comply with any of its debt covenants (including failures stemming from its late SEC filings) could result in a default under the related debt agreement, and under any commodity derivative contract under which such debt default is a cross-default, which could result in the early termination of the commodity derivative contract (and an early termination payment obligation) and/or otherwise materially adversely affect its business, financial condition and results of operations.

F-27

The table below is a summary of the Company's commodity derivatives as of December 31, 2013:



			Weighted Avg
Natural Gas	Period	MMBtu/d	Price per MMBtu
Swaps	Jan 2014 - Dec 2014	10,000	$4.13
Ceilings purchased (call)	Jan 2014 - Dec 2014	10,000	$6.15
Ceilings sold (call)	Jan 2014 - Dec 2014	26,000	$5.47
Floors purchased (put)	Jan 2014 - Dec 2014	10,000	$4.25
Floors sold (put)	Jan 2014 - Dec 2014	10,000	$3.75

			Weighted Avg
Crude Oil	Period	Bbl/d	Price per Bbl
Collars ⁽¹⁾	Jan 2014 - Dec 2014	663	$85.00 - $91.25
	Jan 2015 - Dec 2015	259	$85.00 - $91.25
Traditional three-way collars ⁽²⁾	Jan 2014 - Dec 2014	4,000	$64.94 - $85.00 - $102.50
Ceilings sold (call)	Jan 2015 - Dec 2015	1,570	$120.00
Floors sold (put)	Jan 2014 - Dec 2014	663	$65.00
	Jan 2015 - Dec 2015	259	$70.00

________________________________

⁽¹⁾ A collar is a sold call and a purchased put. Some collars are "costless" collars with the premiums netting to approximately zero.

⁽²⁾ These three-way collars are a combination of three options: a sold call, a purchased put and a sold put.

Currently, Bank of Montreal, KeyBank National Association, Credit Suisse Energy, LLC, Bank of America - Merrill Lynch, Deutsche Bank AG London Branch, Citibank, N.A., J. Aron & Company, an affiliate of Goldman Sachs, are the only counterparties to the Company's commodity derivatives positions. The Company is exposed to credit losses in the event of nonperformance by the counterparties on its commodity derivatives positions. However, the Company does not anticipate nonperformance by the counterparties over the term of the commodity derivatives positions. All counterparties or their affiliates are participants in the Company's senior revolving credit facility, and the collateral for the outstanding borrowings under its senior revolving credit facility is used as collateral for its commodity derivatives with those counterparties.

At December 31, 2013, the Company has preferred stock derivative liabilities resulting from certain conversion features, redemption options, and other features of its Series A Convertible Preferred Units of Eureka Hunter Holdings, LLC. See "Note 3 - Fair Value of Financial Instruments" and "Note 10 - Shareholders' Equity".

At December 31, 2013, the Company also has a convertible security embedded derivative asset primarily due to the conversion feature of the promissory note receivable from GreenHunter Resources, Inc. received as partial consideration for the sale of Hunter Disposal, LLC. See "Note 3 - Fair Value of Financial Instruments", "Note 2 - Divestitures and Discontinued Operations" and "Note 16 - Related Party Transactions".

F-28

The following table summarizes the fair value of the Company's derivative contracts as of the dates indicated:



	Derivatives not designated as hedging instruments
	Gross Derivative Assets				Gross Derivative Liabilities
	December 31,				December 31,
	2013		2012		2013			2012
Commodity	(in thousands)
Derivative assets	$	529	$	4,882	$	—		$	—
Derivatives assets, long term	25		—		—			—
Derivative liabilities	—		—		(1,903		)	(3,501		)
Derivative liabilities, long term	—		—		(376		)	(3,976		)
Total commodity	$	554	$	4,882	$	(2,279	)	$	(7,477	)

Financial
Derivative assets	$	79	$	264	$	—		$	—
Derivative liabilities, long term	—		—		(75,934		)	(43,548		)
Total financial	$	79	$	264	$	(75,934	)	$	(43,548	)
Total derivatives	633		5,146		(78,213		)	(51,025		)

The following table summarizes the net gain (loss) on all derivative contracts included in other income (expense) on the consolidated statements of operations for the years ended December 31, 2013, 2012 and 2011:



	For the Year Ended December 31,
	2013			2012		2011
	(in thousands)
Gain (loss) on settled transactions	$	(8,216	)	$	11,294	$	(2,136	)
Gain (loss) on open transactions	(17,058		)	10,945		(4,210		)
Total gain (loss)	$	(25,274	)	$	22,239	$	(6,346	)

NOTE 5 - ACQUISITIONS

The Company has recognized $2.8 million, $4.7 million, and $8.9 million of transaction expenses related to acquisitions in its general and administrative expenses for the years ended December 31, 2013, 2012, and 2011, respectively. Substantially all of the Company's acquisitions contained a significant amount of unproved acreage, as is consistent with the Company's business strategy.

Utica Shale Assets Acquisition

On February 17, 2012, the Company closed on the acquisition of leasehold mineral interests located predominately in Noble County, Ohio for a total purchase price of $24.8 million in cash.

Eagle Operating Assets Acquisition

On March 30, 2012, the Company, through its wholly-owned subsidiary, Williston Hunter ND, LLC, a Delaware limited liability company (“Williston Hunter”), closed on the purchase of operating working interest in certain oil and gas leases and wells located in several counties in North Dakota from Eagle Operating, Inc. (“Eagle Operating”), an unrelated third party, effective April 1, 2011. Total consideration was $52.9 million consisting of $51.0 million in cash and 296,859 shares of Magnum Hunter restricted common stock valued at $1.9 million based on a price of $6.41 per share. The purpose of the acquisition was to expand the Company’s position in the Williston Basin. The Company already owned a non-operated ownership interest in the properties acquired.

F-29

The acquisition was accounted for using the acquisition method of accounting, which requires the net assets acquired to be recorded at their fair values. The following table summarizes the purchase price and the estimates of fair values of the net assets acquired (in thousands, except shares and per share information):



Fair value of total purchase price:
296,859 shares of common stock issued on March 30, 2012 at $6.41 per share	$	1,902
Cash	50,974
Total	$	52,876
Amounts recognized for assets acquired and liabilities assumed:
Oil and gas properties	$	54,832
ARO	(1,956		)
Total	$	52,876

TransTex Gas Services, LP Assets Acquisition

On April 2, 2012, the Company, through its majority owned subsidiary, Eureka Hunter Holdings, LLC, and its wholly-owned subsidiary, Eureka Hunter Acquisition Sub, LLC, closed on their purchase of certain assets of TransTex Gas Services, LP (“TransTex”), a related third party, under an asset purchase agreement dated March 21, 2012, which resulted in the recognition of approximately $30.6 million in goodwill and $10.5 million of intangible assets. See "Note 6 - Goodwill and Intangible Assets". The Company expects all of the goodwill, which is associated with the Company’s midstream operating segment, to be deductible for tax purposes. The purpose of the acquisition was to complement the Company’s existing midstream assets. The total purchase price paid for the acquired assets was $58.5 million, comprised of $46.0 million in cash and 622,641 Eureka Hunter Holdings Class A Common Units representing membership interests in Eureka Hunter Holdings, with a value of $12.5 million based on an estimated enterprise value of $400.0 million at that time determined utilizing a discounted future cash flow analysis.

The following table summarizes the purchase price and the estimates of fair values of the net assets acquired from TransTex (in thousands):



Fair value of total purchase price:
Cash	$	46,047
Eureka Hunter Holdings Class A Common Units	12,453
Total	$	58,500
Amounts recognized for assets acquired and liabilities assumed:
Working capital	$	525
Equipment and other fixed assets	15,575
Other assets	1,306
Goodwill (Note 8)	30,602
Intangible assets (Note 8)	10,492
Total	$	58,500

Gary C. Evans, the Company's Chairman and CEO, previously held a small limited partnership interest in TransTex, and participated in the purchase of certain Eureka Hunter Holdings Class A Common Units offered to all limited partners of TransTex in connection with the acquisition. See "Note 16 - Related Party Transactions".

Baytex Energy USA Assets Acquisition

On May 22, 2012, the Company, through its wholly-owned subsidiary, Bakken Hunter, LLC, closed on the acquisition of certain Williston Basin assets of Baytex Energy USA, Ltd. (“Baytex Energy USA”), an affiliate of Baytex Energy Corporation, an unrelated third party, for a total purchase price of $312.0 million. The purpose of the acquisition was to significantly increase the Company’s ownership interest in existing mineral leases in a key shale play where the Company has increased its drilling activities. To a lesser extent, proved reserves were added attributable to the acquired properties. The acquired assets include all of Baytex Energy USA’s non-operated working interest in oil and gas properties and wells located in Divide and Burke Counties, North Dakota, within an area subject to an operating agreement among Samson Resources Company, as operator, Baytex Energy Corporation, and Williston Hunter, Inc., a wholly-owned subsidiary of Magnum Hunter.

F-30

The following table summarizes the purchase price and the preliminary estimates of fair values of the net assets acquired (in thousands):



Fair value of total purchase price:
Cash	$	312,018
Total	$	312,018
Amounts recognized for assets acquired and liabilities assumed:
Oil and gas properties	$	312,294
ARO	(276		)
Total	$	312,018

Acquisition of Viking International Resources Co., Inc.

On November 2, 2012, Triad Hunter, LLC, a wholly-owned subsidiary of the Company, closed on the acquisition of all outstanding capital stock of Viking International Resources Co., Inc. (“Virco”) effective January 1, 2012. The total fair market value of consideration paid was approximately $100.8 million, made up of approximately $37.3 million paid in cash and 2,774,850 depositary shares representing 2,774.85 shares of 8.0% Series E Cumulative Convertible Preferred Stock of the Company with market value of approximately $65.2 million and stated liquidation preference of approximately $69.4 million. See "Note 10 - Shareholders' Equity" regarding the Series E Preferred Stock. The primary purpose of the acquisition was to acquire leasehold acreage and wells complementary to the Company's existing acreage position of this region and expand its ownership interest in the Marcellus Shale and Utica Shale plays in West Virginia and Ohio.

The following table summarizes the purchase price and the preliminary estimates of fair values of the net assets acquired (in thousands):



Fair value of total purchase price:
Cash	$	37,349
2,774,850 depositary shares evidencing Series E Preferred Stock issued on November 2, 2012, valued at $23.50 per share	65,209
Escrow settlement	(1,750		)
Total	$	100,808
Amounts recognized for assets acquired and liabilities assumed:
Oil and gas properties	$	110,224
Current assets	1,676
Equipment and other fixed assets	970
Accounts payable and accrued expenses	(3,928		)
Other long-term liabilities	(2,362		)
ARO	(5,772		)
Total	$	100,808

Samson Resources Assets Acquisition

On December 20, 2012, Bakken Hunter, LLC, a wholly-owned subsidiary of the Company, closed on the acquisition of certain existing wells and Williston Basin lease acres located in Divide County, North Dakota from Samson Resources Company. The purchase price for the assets was $30.0 million in cash, subject to customary adjustments. The effective date of the transaction was August 1, 2012.

With the closing of this transaction, the Company owns varied working ownership interests in these properties up to approximately 100%. The acquisition established the Company as an operator in certain of this Bakken acreage, covering four Townships and Ranges in northern Divide County, North Dakota, previously operated by Samson Resources Company.

Agreement to Purchase Utica Shale Acreage

F-31

has agreed to acquire, subject to certain conditions, from MNW up to 32,000 net mineral acres, including currently leased and subleased acreage, located in such counties, over the next 10 months or possibly longer. The maximum purchase price, if MNW delivers 32,000 acres with acceptable title, would be $142.1 million, excluding title costs. During 2013, Triad Hunter purchased leasehold acreage from MNW for an aggregate purchase price of $24.5 million.

The following summarizes the revenue and operating income (loss) from the acquisitions included in the Company's consolidated statements of operations for the years ended December 31, 2013 and 2012:



	For the year ended December 31,
	2013					2012
	Revenues		Operating Income (loss)			Revenues		Operating Income (loss)
	(in thousands)					(in thousands)
Eagle Operating assets	$	7,331	$	(26,867	)	$	5,500	$	(3,019	)
TransTex assets	$	12,765	$	(812	)	$	7,014	$	(393	)
Baytex Energy USA assets	$	100,572	$	(101,627	)	$	18,430	$	(6,649	)
VIRCO acquisition	$	4,453	$	(177	)	$	1,094	$	450

The following unaudited summary, prepared on a pro forma basis, presents the results of operations for the year ended December 31, 2012, as if the above acquisitions along with transactions necessary to finance the acquisitions, had occurred as of the beginning of 2012. The pro forma information includes the effects of adjustments for interest expense, depreciation and depletion expense, and dividend expense. The pro forma results are not necessarily indicative of what actually would have occurred if the acquisition had been completed as of the beginning of each period presented, nor are they necessarily indicative of future consolidated results. The Company determined that pro forma presentation of the leasehold acreage acquired from MNW was not necessary, as the acquisitions were not significant to its balance sheet and the undeveloped acreage had no operating results.



	Pro Forma
	For the Year Ended December 31,
		2012
	(in thousands except for per share amount, unaudited)
Total revenue		$	159,085
Operating loss		(108,177		)
Net loss		(150,777		)
Net loss attributable to Magnum Hunter Resources Corporation		(146,764		)
Net loss attributable to common shareholders		$	(188,736	)
Loss per common share, basic and diluted		$	(1.21	)

NOTE 6 - GOODWILL AND INTANGIBLE ASSETS

Goodwill

Goodwill represents the excess of the purchase price of an entity over the estimated fair value of the assets acquired and the liabilities assumed. The Company assesses the carrying amount of goodwill by testing the goodwill for impairment annually or whenever interim impairment indicators arise. Goodwill of $30.6 million was recorded related to the Company's midstream segment during 2012 as a result of its acquisition of the assets of TransTex Gas Services, LP, discussed in "Note 5 - Acquisitions". The Company assessed goodwill for impairment on April 1, 2013, and determined that no impairment existed. The Company updated its annual impairment test through December 31, 2013, with an evaluation of any triggering events or circumstances that would indicate that impairment of the carrying value of goodwill is likely, and none were determined to exist.

F-32

Intangible Assets

Intangible assets consist primarily of the fair value of the acquired gas treating agreements and customer relationships in the TransTex Gas Services, LP assets acquisition completed in 2012. The intangible assets were valued at fair value using a discounted cash flow model with a discount rate of 13%. Such assets are being amortized over the weighted average term of 8.54 years.

The following table summarizes the Company's changes in intangible assets during the years ended December 31, 2013 and 2012:



	Amortization		December 31,			December 31,
	Period		2013			2012
			(in thousands)
Intangible assets, at beginning of the period			$	10,492		$	—
Additions through acquisition:
Customer relationships	12.5	years	—			5,434
Trademark	11.0	years	—			859
Existing contracts	2.9	years	—			4,199
Total intangible assets			10,492			10,492
Accumulated amortization:
Customer relationships			(1,248		)	(326		)
Trademark			(137		)	(58		)
Existing contracts			(2,577		)	(1,127		)
Intangible assets, net of accumulated amortization			$	6,530		$	8,981

The following table summarizes the aggregate amortization of intangible assets over the next five years:



	(in thousands)
2014	$	2,007
2015	$	981
2016	$	586
2017	$	519
2018	$	457
Thereafter	$	1,980

NOTE 7 - ASSET RETIREMENT OBLIGATIONS

The Company's ARO primarily represents the estimated present value of the amount the Company will incur to plug, abandon and remediate its producing properties at the end of their productive lives, in accordance with applicable federal, state and local laws. The Company determined its ARO by calculating the present value of estimated cash flows related to the liability. The retirement obligation is recorded as a liability at its estimated present value as of the asset’s inception, with a corresponding increase to proved properties. The Company records accretion of the estimated liability as accretion expense in depreciation, depletion, amortization, and accretion in the consolidated statements of operations.

The Company's liability is determined using significant assumptions, including current estimates of plugging and abandonment costs, annual inflation of these costs, the productive lives of wells and its risk-adjusted interest rate. Changes in any of these assumptions can result in significant revisions to the estimated ARO. Revisions to the ARO are recorded with a corresponding change to producing properties, resulting in prospective changes to depreciation, depletion and amortization expense and accretion of discount. Because of the subjectivity of assumptions and the relatively long lives of most of the Company's wells, the costs to ultimately retire its wells may vary significantly from prior estimates. The Company's liability for AROs was approximately $16.2 million and $30.7 million at December 31, 2013 and 2012, respectively.

The Company's midstream operating assets generally consist of underground pipelines and related components along rights-of-way and above ground storage tanks and related facilities. The Company's right-of-way agreements typically do not require the dismantling, removal and reclamation of the right-of-way upon permanent cessation of pipeline service. Additionally, management is unable to predict when, or if, the Company's pipelines, storage tanks and related facilities would become completely obsolete and require decommissioning. Accordingly, the Company has recorded no liability or corresponding asset as an ARO as both the amounts and timing of such future costs are indeterminable.

F-33

The following table summarizes the changes in the Company’s ARO transactions during the years ended December 31, 2013 and 2012:



	2013			2012
	(in thousands)
Asset retirement obligation at beginning of period	$	30,680		$	20,584
Assumed in acquisition	17			8,027
Liabilities incurred	253			373
Liabilities settled	(98		)	(80		)
Liabilities associated with assets sold	(7,614		)	—
Accretion expense	2,264			1,671
Revisions in estimated liabilities	1,935			76
Reclassified as liabilities associated with assets held for sale	(11,148		)	13
Effect of foreign currency translation	(73		)	16
Asset retirement obligation at end of period	16,216			30,680
Less: current portion	(53		)	(2,358		)
Asset retirement obligation at end of period	$	16,163		$	28,322

NOTE 8 - LONG-TERM DEBT

Notes payable at December 31, 2013 and 2012 consisted of the following:



	As of December 31,
	2013			2012
	(in thousands)
Senior Notes Payable due May 15, 2020, interest rate of 9.75%, net of unamortized discount of $2.8 million at December 31, 2013 and 2012	$	597,230		$	597,212
Various equipment and real estate notes payable with maturity dates February 2015 - November 2017, interest rates of 4.25% - 5.70% ⁽¹⁾	18,615			18,548
Eureka Hunter Pipeline, LLC second lien term loan due August 16, 2018, interest rate of 12.5%	50,000			50,000
MHR Senior revolving credit facility due April 13, 2016, interest rate of 3.42% at December 31, 2013 and 3.56% at December 31, 2012	218,000			225,000
	$	883,845		$	890,760
Less: current portion	(3,967		)	(3,991		)
Total long-term debt	$	879,878		$	886,769

^{_________________}

⁽¹⁾Includes notes classified as liabilities associated with assets held for sale of which $163,000 is current and $3.8 million is long term

The following table presents the approximate annual maturities of debt, gross of unamortized discount:



	(in thousands)
2014	$	3,967
2015	7,940
2016	224,378
2017	330
2018	50,000
Thereafter	597,230
	$	883,845

F-34

Senior Notes

On May 16, 2012, the Company completed the issuance of $450.0 million aggregate principal amount of its 9.75% Unregistered Senior Notes which mature on May 15, 2020 for total proceeds of $431.2 million net of issuing costs of $12.8 million, resulting in a discount of $6.0 million.

On December 13, 2012, the Company completed the issuance of an additional $150.0 million aggregate principal amount of its 9.75% Unregistered Senior Notes for total proceeds of $149.9 million net of issuing costs of $3.1 million, resulting in a premium of $3.0 million.

On November 8, 2013 we completed an exchange offer pursuant to which we exchanged $600 million of Senior Notes registered under the Securities Act for all of the Unregistered Notes. We refer to the exchange Senior Notes as the Exchange Notes or our Senior Notes. The Exchange Notes have substantially identical terms to our former Unregistered Senior Notes except the Exchange Notes are generally freely transferable under the Securities Act.

The Senior Notes are unsecured and are guaranteed, jointly and severally, on a senior unsecured basis by certain of the Company’s domestic subsidiaries. The indenture governing the Senior Notes permits a guarantor of the Senior Notes to be released from its guarantee under certain circumstances, including in connection with a sale or other disposition of all or substantially all of the assets of the guarantor, a sale of other disposition of the capital stock of the guarantor to a third party, or upon the liquidation or dissolution of the guarantor.

Interest on the Senior Notes is paid semi-annually in arrears on May 15 and November 15 of each year. The Company paid penalty interest totaling $1.1 million during 2013 due to its untimely filing of a Registration Statement on Form S-4 to consummate an exchange offer.

The Company used the net proceeds of the Senior Notes, together with other sources of liquidity, (i) to finance a portion of the $312.0 million acquisition of oil properties in the Williston Basin from Baytex Energy USA, Ltd., which closed on May 22, 2012, (ii) to pay off all amounts outstanding under the Company’s second lien term loan, (iii) to repay outstanding debt under the Company’s senior revolving credit facility, (iv) for capital expenditures and (v) general corporate purposes.

The Senior Notes were issued pursuant to an indenture entered into on May 16, 2012 as supplemented, among the Company, the subsidiary guarantors party thereto, Wilmington Trust, National Association, as the trustee, and Citibank, N.A., as the paying agent, registrar and authenticating agent. The terms of the Senior Notes are governed by the indenture, which contains affirmative and restrictive covenants that, among other things, limit the Company’s and the guarantors’ ability to incur or guarantee additional indebtedness or issue certain preferred stock; pay dividends on capital stock or redeem, repurchase or retire capital stock or subordinated indebtedness or make certain other restricted payments; transfer or sell assets; make loans and other investments; create or permit to exist certain liens; enter into agreements that restrict dividends or other payments from restricted subsidiaries to the Company; consolidate, merge or transfer all or substantially all of their assets; engage in transactions with affiliates; and create unrestricted subsidiaries.

The indenture also contains events of default. Upon the occurrence of events of default arising from certain events of bankruptcy or insolvency, the Senior Notes shall become due and payable immediately without any declaration or other act of the trustee or the holders of the Senior Notes. Upon the occurrence of certain other events of default, the trustee or the holders of at least 25% in aggregate principal amount of the then outstanding Senior Notes may declare all outstanding Senior Notes to be due and payable immediately.

At December 31, 2013, the Company was in compliance with all of its requirements under the indenture related to the Senior Notes.

The Senior Notes are redeemable by the Company at any time on or after May 15, 2016, at the redemption price of 104.875%, after May 15, 2017, at the redemption price of 102.438%, and after May 15, 2018, at the redemption price of 100.00%. The Senior Notes are redeemable by the Company prior to May 15, 2016 at the redemption price equal to 100.00% of the principal amount of the notes redeemed, plus a “make-whole” premium of the greater of:

(1)1.0% of the principal amount of the note; and

(2)The excess of:

(a)

The present value at such redemption date of (i) the redemption price of the note at May 15, 2016 plus (ii) all required interest payments due on the note through May 15, 2016 (excluding accrued but unpaid interest to the redemption date), computed using a discount rate equal to the treasury rate as of such redemption date plus 50 basis points discounted to such redemption date on a semi-annual basis, over


(b)	The principal amount of the note.

F-35

The Company is also entitled to redeem up to 35% of the aggregate principal amount of the Senior Notes before May 15, 2015 with net proceeds that the Company raises in certain equity offerings at a redemption price of 109.750%, so long as at least 65% of the aggregate principal amount of the Senior Notes issued under the indenture (excluding Senior Notes held by the Company) remains outstanding immediately after such redemption and the redemption occurs within 180 days of the closing date of such equity offering. If the Company experiences certain change of control events, each holder of Senior Notes may require the Company to repurchase all or a portion of the Senior Notes for cash at a price equal to 101% of the aggregate principal amount of such Senior Notes, plus any accrued and unpaid interest up to, but not including the date of repurchase.

Eureka Hunter Pipeline Credit Facilities

On August 16, 2011, Eureka Hunter Pipeline, LLC (“Eureka Hunter Pipeline ”), a majority-owned subsidiary of the Company, entered into (i) a First Lien Credit Agreement (the “First Lien Agreement”) by and among Eureka Hunter Pipeline, the lenders party thereto and SunTrust Bank, as administrative agent, and (ii) a Second Lien Term Loan Agreement (the “Second Lien Agreement”), by and among Eureka Hunter Pipeline, the lenders party thereto and U.S. Bank National Association, as collateral agent (the First Lien Agreement and the Second Lien Agreement being collectively referred to as the “Eureka Credit Agreements”).

The First Lien Agreement provides for a revolving credit facility (the “Revolver”) in an aggregate principal amount of up to $100 million (with an initial committed amount of $25 million), secured by a first lien on substantially all of the assets of Eureka Hunter Pipeline. The Second Lien Agreement provides for a $50 million term loan facility (the “Term Loan”), secured by a second lien on substantially all of the assets of Eureka Hunter Pipeline. The entire $50 million Term Loan had previously been drawn. As of May 1, 2013, the revolving credit facility was not available due to the Company's inability to satisfy certain financial ratios included in the agreement. The Revolver has a maturity date of August 16, 2016, and the Term Loan has a maturity date of August 16, 2018. Both the Revolver and the Term Loan are non-recourse to Magnum Hunter Resources Corporation. See "Effect of Late SEC Filings on Liquidity and Capital Resources."

The terms of the First Lien Agreement provide that the Revolver may be used for (i) revolving loans, (ii) swingline loans in an aggregate amount of up to $5 million at any one time outstanding, or (iii) letters of credit in an aggregate amount of up to $5 million at any one time outstanding. The Revolver provides for a commitment fee of 0.5% per annum based on the unused portion of the commitment under the Revolver.

Borrowings under the Revolver will, at Eureka Hunter Pipeline’s election, bear interest at:

•

a base rate equal to the highest of (i) the prime lending rate announced from time to time by the Administrative Agent, (ii) the then-effective Federal Funds Rate (as definited in the Eureka Hunter Pipeline Revolver) plus 0.5% per annum, or (iii) the Adjusted LIBO Rate (as defined in the First Lien Agreement) for a one-month interest period on such day plus 1.0% per annum, plus an applicable margin ranging from 1.25% to 2.25%; or


•	the Adjusted LIBO Rate, plus an applicable margin ranging from 2.25% to 3.5%.

Borrowings under the Term Loan will bear interest at 12.50% per annum in cash (increasing to 13.50% on and at all times when Eureka Hunter Pipeline and its subsidiaries incur indebtedness (other than the Term Loan) in excess of $1 million).

If an event of default occurs under either the Revolver or the Term Loan, the lenders may increase the interest rate then in effect by an additional 2.0% per annum for the period that the default exists under the Revolver or the Term Loan.

The Eureka Credit Agreements contain negative covenants that, among other things, restrict the ability of Eureka Hunter Pipeline and its subsidiaries to, with certain exceptions: (1) incur indebtedness; (2) grant liens; (3) dispose of all or substantially all of its assets or enter into mergers, consolidations, or similar transactions; (4) change the nature of its business; (5) make investments, loans, or advances or guarantee obligations; (6) pay cash dividends or make certain other payments; (7) enter into transactions with affiliates; (8) enter into sale and leaseback transactions; (9) enter into hedging transactions; (10) amend its organizational documents or material agreements; or (11) make certain undisclosed capital expenditures.

The Eureka Credit Agreements also require Eureka Hunter Pipeline to satisfy certain financial covenants, including maintaining:


•	a consolidated total debt to capitalization ratio of not more than 60%;


•	a ratio of consolidated EBITDA to consolidated interest expense, in each case, for the four fiscal quarter period then ended ranging from:

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(i) for the Term Loan, not less than (A) 2.25 to 1.00, for the fiscal quarters ending December 31, 2013 and March 31, 2014, (B) 2.50 to 1.00, for the fiscal quarters ending June 30, 2014 and September 30, 2014, and (C) 2.75 to 1.0 for the fiscal quarter ending December 31, 2014 and each fiscal quarter ending thereafter, and

(ii) in the event any portion of the Revolver has been drawn, for the Revolver, not less (A) 2.50 to 1.00, for the fiscal quarters ending December 31, 2013 and March 31, 2014, (B) 2.75 to 1.00, for the fiscal quarters ending June 30, 2014 and September 30, 2014, and (C) 3.00 to 1.0 for the fiscal quarter ending December 31, 2014 and each fiscal quarter ending thereafter;


•	a ratio of consolidated total debt to consolidated EBITDA for the four fiscal quarter period then ended ranging from:

(i) for the Term Loan, not greater than (A) 4.50 to 1.0 for the fiscal quarters ending December 31, 2013, March 31, 2014, June 30, 2014, and September 30, 2014, and (B) 4.25 to 1.0 for the fiscal quarter ending December 31, 2014 and each fiscal quarter ending thereafter, and

(ii) in the event any portion of the Revolver has been drawn, for the Revolver, not greater than (A) 4.50 to 1.0 for the fiscal quarters ending December 31, 2013 and March 31, 2014, and (B) 4.00 to 1.0 for the fiscal quarter ending June 30, 2014 and each fiscal quarter ending thereafter; and


•	a ratio of consolidated debt under the Revolver to consolidated EBITDA of (i) for the Term Loan, not greater than 3.5 to 1.0, and (ii) for the Revolver, if any portion of the Revolver has been drawn, not greater than 3.25 to 1.0 for each fiscal quarter.

The obligations of Eureka Hunter Pipeline under each of the Revolver and the Term Loan may be accelerated upon the occurrence of an Event of Default (as such term is defined in such Eureka Credit Agreement) under such Eureka Credit Agreement. Events of Default include customary events for these types of financings, including, among others, payment defaults, defaults in the performance of affirmative or negative covenants, the inaccuracy of representations or warranties, defaults under the Term Loan (with respect to the Revolver) or the Revolver (with respect to the Term Loan), defaults relating to judgments, material defaults under certain material contracts of Eureka Hunter Pipeline, and defaults by the Company which cause the acceleration of the Company’s debt under its existing MHR Senior Revolving Credit Facility.

Under the Eureka Credit Agreements, (i) Eureka Hunter Pipeline and its subsidiaries have entered into customary ancillary agreements and arrangements, which provide that the obligations under the Eureka Credit Agreement are secured by substantially all of the assets of Eureka Hunter Pipeline and such subsidiaries, consisting primarily of pipelines, pipeline rights-of-way, and gas treating and processing equipment and certain other equipment, and (ii) Eureka Hunter Holdings, the sole parent of Eureka Hunter Pipeline and a majority owned subsidiary of the Company, entered into customary ancillary agreements and arrangements, which granted the lenders under the Eureka Credit Agreements a non-recourse security interest in Eureka Hunter Holdings' equity interests in Eureka Hunter Pipeline.

Availability under the Revolver is subject to satisfaction of certain financial covenants that are tested on a quarterly basis.

At December 31, 2013, the Company was in compliance with all of its covenants, as amended or waived, contained in the Eureka Hunter Pipeline credit facilities.

Eureka Hunter Pipeline had loans outstanding under this second lien facility of $50.0 million as of December 31, 2013 and 2012.

The Amended and Restated Limited Liability Company Agreement of Eureka Hunter Holdings, referred to as the EH Operating Agreement, contains certain covenants that, among other things, restrict the ability of Eureka Hunter Holdings and its subsidiaries, including Eureka Hunter Pipeline and TransTex Hunter, LLC, to, with certain exceptions:


•	incur funded indebtedness, whether direct or contingent;


•	issue additional equity interests;


•	pay distributions to its owners, or repurchase or redeem any of its equity securities;


•	make any material acquisitions, dispositions or divestitures; or


•	enter into a sale, merger, consolidation or other change of control transaction.

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Revolving Credit Facility

On December 13, 2013, the Company entered into a Third Amended and Restated Credit Agreement (the “Credit Agreement”) by and among the Company, Bank of Montreal, as Administrative Agent, the lenders party thereto and the agents party thereto. The Credit Agreement amended and restated that certain Second Amended and Restated Credit Agreement, dated as of April 13, 2011, by and among such parties, as amended (the "Prior Credit Agreement"). The terms of the Credit Agreement are substantially similar to the Prior Credit Agreement.

The Credit Agreement provides for an asset-based, senior secured revolving credit facility maturing April 13, 2016 (the "Revolving Facility"). As of December 31, 2013 the borrowing base under the Revolving Facility was $242.5 million. The Revolving Facility is governed by a semi-annual borrowing base redetermination derived from the Company's proved crude oil and natural gas reserves, and based on such redeterminations, the borrowing base may be decreased or increased up to a maximum commitment level of $750 million. The borrowing base is subject to such periodic redeterminations commencing May 1, 2014.

The terms of the Credit Agreement provide that the Revolving Facility may be used for loans, and subject to a $10.0 million sublimit,

letters of credit. The Credit Agreement provides for a commitment fee of 0.5% of the unused portion of the borrowing base and commitments under the Revolving Facility.

Borrowings under the Revolving Facility will, at the Company’s election, bear interest at either (i) an alternate base rate (“ ABR ”)

equal to the highest of (A) the Prime Rate (as defined in the Credit Agreement) in effect on such day, (B) the Federal Funds Effective Rate (as defined in the Credit Agreement) in effect on such day, plus 0.5% per annum, and (C) the LIBO Rate (as defined in the Credit Agreement) for a one month interest period on such day, plus 1.00% or (ii) the Adjusted LIBO Rate (as defined in the Credit Agreement) for one, two, three, six or twelve months (as the Company may elect), plus, in each of the cases described in clauses (i) and (ii), an applicable margin ranging from 1.5% to 2.25% for ABR loans and from 2.5% to 3.25% for Adjusted LIBO Rate loans. Overdue amounts shall bear interest at a rate equal to 2.00% per annum plus the rate applicable to ABR loans.

The Credit Agreement contains negative covenants that, among other things, restrict the ability of the Company and its restricted

subsidiaries to, with certain exceptions, (i) incur indebtedness, (ii) grant liens, (iii) make certain payments, (iv) change the nature of its business, (v) dispose of all or substantially all of its assets or enter into mergers, consolidations or similar transactions, (vi) make investments, loans or advances, (vii) pay dividends, unless certain conditions are met, and with respect to the payment of dividends on preferred stock, subject to (A) no Event of Default (as defined in the Credit Agreement) existing, (B) after giving effect to any such preferred stock dividend payment, the Company maintaining availability under the borrowing base in an amount greater than the greater of (x) 2.50% percent of the borrowing base then in effect or (y) $5,000,000 and (C) a “basket” of $45,000,000 per year, and (viii) enter into transactions with affiliates.

In addition, the Credit Agreement requires the Company and its restricted subsidiaries to satisfy certain financial covenants, including maintaining:

(i) a ratio of consolidated current assets to consolidated current liabilities of not less than 1.0 to 1.0 as of the last day of any fiscal quarter;

(ii) a ratio of EBITDAX (as defined in the Credit Agreement) for the trailing four fiscal quarter period then ended to Interest Expense (as defined in the Credit Agreement) for such period of not less than (A) 2.00 to 1.00 for the fiscal quarter ending December 31, 2013, (B) 2.25 to 1.00 for the fiscal quarter ending March 31, 2014 and (C) 2.50 to 1.00 for the fiscal quarter ending June 30, 2014 and for each fiscal quarter ending thereafter; provided that solely for calculating such ratio for the fiscal quarter ending December 31, 2013, EBITDAX and interest expense for that fiscal quarter shall be calculated on an actual basis without giving effect to any pro forma adjustments;

(iii) beginning with the fiscal quarter ending June 30, 2014, a ratio of total debt to EBITDAX for the trailing four fiscal quarter period then ended of not more than (A) 4.50 to 1.0 for the fiscal quarters ending June 30, 2014 and September 30, 2014 and (B) 4.25 to 1.0 for the fiscal quarter ending December 31, 2014 and for each fiscal quarter ending thereafter; and

(iv) as of the last day of any fiscal quarter period ending through March 31, 2014, a ratio of total debt (less the outstanding principal amount of the Company’s 9.750% Senior Notes due 2020) to EBITDAX for the trailing four fiscal quarter period then ended of not more than 2.00 to 1.00.

At December 31, 2013, the Company was in compliance with all of its covenants, as amended or waived, contained in the Revolving Facility.

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The obligations of the Company under the Credit Agreement may be accelerated upon the occurrence of an Event of Default. Events of Default include customary events for a financing agreement of this type, including, without limitation, payment defaults, defaults in the performance of affirmative or negative covenants, the inaccuracy of representations and warranties, bankruptcy or related defaults, defaults relating to judgments and the occurrence of a Change of Control (as defined in the Credit Agreement), subject, in certain circumstances, to certain cure periods.

Subject to certain permitted liens, the Revolving Facility is secured by the grant of a first priority lien on all or substantially all of the assets of the Company and its restricted subsidiaries, including, without limitation, a lien on no less than 80% of the value of the proved oil and gas properties of the Company and its restricted subsidiaries. In connection with the Credit Agreement, the Company and its restricted subsidiaries also entered into customary ancillary agreements and arrangements, which among other things, provide that the Revolving Facility is unconditionally guaranteed by such restricted subsidiaries.

Interest Expense

The following table sets forth interest expense for the years ended December 31, 2013 and 2012:



	Years Ended
	December 31,
	2013		2012
	(in thousands)
Interest expense incurred on debt, net of amounts capitalized	$	67,605	$	44,216
Amortization and write-off of deferred financing costs	4,818		7,400
Total Interest Expense	$	72,423	$	51,616

The Company capitalizes interest on expenditures for significant construction projects that last more than six months while activities are in progress to bring the assets to their intended use. Interest of $2.6 million and $4.4 million was capitalized on our Eureka Hunter Gas Gathering System during the years ended 2013 and 2012, respectively. The Company did not capitalize any interest in 2011.

NOTE 9 - SHARE-BASED COMPENSATION

Employees, directors and other persons who contribute to the success of Magnum Hunter are eligible for grants of common stock, common stock options, and stock appreciation rights under the Company's amended and restated Stock Incentive Plan. At December 31, 2013, 27,500,000 shares of the Company's common stock are authorized to be issued under the plan, and 5,360,176 shares have been issued as of December 31, 2013.

The Company recognized share-based compensation expense of $13.6 million, $15.7 million, and $25.1 million for the years ended December 31, 2013, 2012, and 2011 respectively.

A summary of stock option and stock appreciation rights activity for the years ended December 31, 2013, 2012, and 2011 is presented below:



	2013				2012				2011
			Weighted-Average Exercise Price				Weighted-Average Exercise Price				Weighted-Average Exercise Price
	Shares		Weighted-Average Exercise Price		Shares		Weighted-Average Exercise Price		Shares		Weighted-Average Exercise Price
Outstanding at beginning of period	14,846,994		$	6.01	12,566,199		$	5.64	12,779,282		$	2.65
Granted	4,937,575		$	4.11	4,978,750		$	6.00	5,601,792		$	7.74
Exercised	(1,466,025	)	$	3.66	(1,304,050	)	$	1.54	(5,479,250	)	$	0.92
Forfeited or expired	(1,427,125	)	$	5.51	(1,393,905	)	$	7.14	(335,625	)	$	3.40
Outstanding at end of period	16,891,419		$	5.69	14,846,994		$	6.01	12,566,199		$	5.64
Exercisable at end of the year	9,983,743		$	5.96	8,683,622		$	5.97	6,915,471		$	4.97

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A summary of the Company’s non-vested options and stock appreciation rights as of December 31, 2013, 2012, and 2011 is presented below:



Non-vested Options	2013		2012		2011
Non-vested at beginning of period	6,163,372		5,650,782		5,215,532
Granted	4,937,575		4,978,750		5,601,792
Vested	(3,133,700	)	(3,405,434	)	(4,832,417	)
Forfeited	(1,059,771	)	(1,060,726	)	(334,125	)
Non-vested at end of period	6,907,476		6,163,372		5,650,782

Total unrecognized compensation cost related to the non-vested options was $14.1 million, $12.6 million, and $9.2 million as of December 31, 2013, 2012, and 2011, respectively. The cost at December 31, 2013 is expected to be recognized over a weighted-average period of 1.77 years. At December 31, 2013, the aggregate intrinsic value for the outstanding options was $29.7 million; and the weighted average remaining contract life was 5.88 years.

The assumptions used in the fair value method calculations for the years ended December 31, 2013, 2012, and 2011 are disclosed in the following table:



		Year Ended December 31,
		2013	2012	2011
Weighted average fair value per option granted during the period ⁽¹⁾		$2.52	$3.72	$4.28
Assumptions ⁽²⁾ :
Weighted average stock price volatility ⁽³⁾		80.61%	82.64%	64.29%
Weighted average risk free rate of return		0.78%	0.77%	2.04%
Weighted average estimated forfeiture rate ⁽⁴⁾		2.45%	—%	—%
Weighted average expected term		4.65 years	4.51 years	6.36 years

⁽¹⁾	Calculated using the Black-Scholes fair value based method for service and performance based grants and the Lattice Model for market based grants.
⁽²⁾	The Company has not paid cash dividends on its common stock.
⁽³⁾	The volatility assumption was estimated based upon a blended calculation of historical volatility and implied volatility over the life of the awards.
⁽⁴⁾	For the years 2012 and 2011, the Company estimated forfeitures to be zero based on the majority of options being granted to executive officers who are less likely to forfeit shares.

During 2013, the Company granted 182,994 fully vested shares of common stock to the Company’s board members as payment of board and committee meeting fees and chairperson retainers.

A summary of the Company’s non-vested common shares granted under the Stock Incentive Plan as of December 31, 2013, 2012, and 2011 is presented below:



	2013				2012				2011
			Weighted-Average Share Price				Weighted-Average Share Price				Weighted-Average Share Price
Non-vested Shares	Shares		Weighted-Average Share Price		Shares		Weighted-Average Share Price		Shares		Weighted-Average Share Price
Non-vested at beginning of year	65,025		$	6.09	155,049		$	4.43	300,074		$	4.43
Granted	210,494		$	4.66	69,791		$	4.29	40,305		$	5.45
Vested	(248,019	)	$	4.75	(159,815	)	$	4.46	(185,330	)	$	0.47
Non-vested at end of year	27,500		$	7.24	65,025		$	6.09	155,049		$	4.43

Total unrecognized compensation cost related to the above non-vested shares amounted to $0.2 million, $0.4 million, and $0.8 million as of December 31, 2013, 2012, and 2011, respectively. The unrecognized compensation cost at December 31, 2013 is expected to be recognized over a weighted-average period of 2.9 years.

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NOTE 10 - SHAREHOLDERS' EQUITY

Common Stock

During the years ended December 31, 2013, 2012, and 2011, the Company issued :


•	182,994, 84,052, and 121,143 shares, respectively, of the Company’s common stock in connection with share-based compensation which had fully vested to certain senior management and officers of the Company.


•	1,466,025, 1,438,275, and 6,293,107 shares, respectively, of the Company’s common stock upon the exercise of warrants and options for total proceeds of approximately $5.4 million, $2.3 million, and $7.6 million, respectively.

During the year ended December 31, 2011, the Company issued 1,713,598 shares of common stock in open market transactions at an average price of $8.27 per share pursuant to an “At the Market” sales agreement (ATM) the Company had with its sales agent for total proceeds of approximately $13.9 million. Sales of shares of the Company's common stock by its sales agent have been made in privately negotiated transactions or in any method permitted by law deemed to be an “At The Market” offering as defined in Rule 415 promulgated under the Securities Act of 1933, as amended, at negotiated prices, at prices prevailing at the time of sale or at prices related to such prevailing market prices, including sales made directly on an exchange or sales made through a market maker other than on an exchange. The Company's sales agent has made all sales using commercially reasonable efforts consistent with its normal sales and trading practices on mutually agreed upon terms between the Company and its sales agent.

On January 14, 2011, the Company issued 946,314 shares of common stock valued at approximately $7.5 million based on a closing stock price of $7.97 as consideration in the second closing of the PostRock assets acquisition.

On April 13, 2011, the Company issued 6,635,478 shares of common stock valued at approximately $53.0 million based on a closing stock price of $7.99 as consideration in the closing of the acquisition of NGAS. In connection with the NGAS acquisition, the Company issued 350,626 shares of common stock valued at approximately $2.8 million to NGAS employees as change in control payments.

On May 3, 2011, the Company issued 38,131,846 shares of common stock valued at approximately $282.2 million based on a closing stock price of $7.40 as consideration in the closing of the acquisition of NuLoch.

On March 30, 2012, the Company issued 296,859 restricted shares of the Company’s common stock valued at approximately $1.9 million based on a price of $6.41 per share as partial consideration for the acquisition of the assets of Eagle Operating.

On May 16, 2012, the Company issued 35,000,000 shares of the Company’s common stock in an underwritten public offering at a price of $4.50 per share for total proceeds of $157.5 million. The net proceeds of the offering, after deducting underwriting discounts and commissions and offering expenses, were approximately $148.2 million.

During the years ended December 31, 2013, 2012, and 2011 the Company issued 505,835, 3,188,036, and 582,127 shares of the Company’s common stock, respectively, upon exchange of exchangeable shares issued by MHR Exchangeco Corporation in connection with the Company’s acquisition of NuLoch Resources, Inc. in May 2011.

On August 13, 2013 and August 20, 2012, the Company issued an aggregate of 221,170 and 199,055 shares, respectively, of the Company’s common stock as "safe harbor" and discretionary matching contributions to the Magnum Hunter Resources Corporation 401(k) Employee Stock Ownership Plan (the "KSOP" or the "Plan"). The Plan was established effective October 1, 2010 as a defined contribution plan. At the discretion of the Board of Directors, the Company may elect to contribute discretionary contributions to the Plan either as profit sharing contributions or as employee stock ownership plan contributions. It is the intent of the Company to review and make discretionary contributions to the Plan in the future, however, the Company has no further obligation to make future contributions to the Plan as of December 31, 2013, except for statutorily required "safe harbor" matching contributions.

F-41

Unearned Common Stock in Magnum Hunter Resources Corporation 401(k) Employee Stock Ownership Plan

On August 13, 2012, the Company rescinded the loan of 153,300 Magnum Hunter common shares to the Company's KSOP and the common shares were returned to the Company and held in treasury at cost of $3.94 per share. The loan was rescinded to correct a mutual mistake by the parties in connection with the Company’s original acquisition of the shares through open market purchases. The Company has agreed that 153,300 shares of the Company’s common stock will either be (i) offered for sale to the participants in the Plan at a price not to exceed the lesser of $3.94 per share (the basis of these treasury shares) or the fair market value of the shares on the date of the sale, or (ii) contributed to the Plan as one or more discretionary matching contributions. Such sale or contribution shall be made at such time or times as determined by the trustee of the Plan, except to the extent that the Company elects prior to that time to contribute all or a part of such shares as a discretionary matching contribution.

Exchangeable Common Stock

On May 3, 2011, in connection with the acquisition of NuLoch, the Company issued 4,275,998 exchangeable shares of MHR Exchangeco Corporation, which are exchangeable for shares of the Company at a one for one ratio. The shares of MHR Exchangeco Corporation were valued at approximately $31.6 million. Each exchangeable share was exchangeable for one share of the Company's common stock at any time after issuance at the option of the holder and was redeemable at the option of the Company, through Exchangeco, after one year or upon the earlier of certain specified events. During the year ended December 31, 2013, 2012, and 2011, 505,835, 3,188,036, and 582,127, respectively, of the exchangeable shares were exchanged for common shares of the Company. As of December 31, 2013, there were no exchangeable shares outstanding.

Common Stock Warrants

During 2006, the Company issued 871,500 warrants to purchase an equal number of shares of the Company’s common stock at an exercise price of $3.00 per share in conjunction with private placement sales of common stock. The warrants had a term of five years from the date of issuance. The Company also issued 326,812 warrants to purchase an equal number of shares of the Company’s common stock at an exercise price of $3.00 per share along with a cash payment for commission fees.

In association with common stock sales on November 5, 2009, the Company issued 457,982 common stock warrants. Each warrant issued to a purchaser had a term of 3 years and (i) was exercisable for one share of the Company's common stock at any time after the shares of common stock underlying the warrant are registered with the SEC for resale pursuant to an effective registration statement, which was June 12, 2010, (ii) had a cash exercise price of $2.50 per share of the Company's common stock, and (iii) upon notice to the holder of the warrant, was redeemable by the Company for $0.01 per share of the Company's common stock underlying the warrant if (a) the registration statement as filed with the SEC is effective and (b) the average trading price of the Company's common stock as traded and quoted on the NYSE Amex equals or exceeds $3.75 per share for at least 20 days in any period of 30 consecutive days.

On November 16, 2009, the Company issued 1,280,744 common stock warrants. The warrants, which represent the right to acquire an aggregate of up to 1,280,744 common shares, were exercisable at any time on or after May 17, 2010 and had a term of 3 years, at an exercise price of $2.50 per share, which was 145% of the closing price of the Company's common shares on the NYSE Amex on November 11, 2009. These warrants were exercised during the years 2010, 2011, 2012.

On April 13, 2011, at the time of the NGAS acquisition, NGAS had 4,609,038 warrants outstanding which were converted, based on the exchange ratio of 0.0846, to 389,924 warrants exercisable for Magnum Hunter common stock. The warrants had a cash-out option, which remained available to the holder for 30 days from the date of the acquisition, based on fair market value of the warrants at April 13, 2011. The Company paid cash of $1.0 million upon exercise of the cash-out option on the warrants exercisable for 251,536 shares of the Company’s common stock. At December 31, 2013, common stock warrants exercisable for 138,388 shares of the Company’s common stock were outstanding. The warrants consist of 97,780 warrants with an exercise price of $15.13 which expire February 13, 2014 and 40,608 warrants with an exercise price of $19.04 which expire November 17, 2014.

On August 13, 2011, the Company declared a dividend to be paid in the form of one common stock warrant for every ten shares held by holders of record of the Company's common stock and exchangeable shares of MHR Exchangeco Corporation on August 31, 2011. The Company issued 12,875,093 common stock warrants to common stock holders and 378,174 warrants to holders of MHR Exchangeco Corporation exchangeable shares. Each warrant entitled the holder to purchase one share of the Company’s common stock for an initial exercise price of $10.50 and expired on October 14, 2013. The fair market value of the warrants was $6.9 million. The warrants were accounted for in additional paid-in capital rather than as a reduction of retained earnings because the Company has an accumulated deficit position.

F-42

On August 26, 2013, the Company declared a dividend on its outstanding shares of common stock in the form of 17,030,622 warrants to purchase shares of the Company's common stock at $8.50 per share with such warrants having a fair value of $21.6 million as of the declaration date of August 26, 2013. The warrants were issued on October 15, 2013 to shareholders of record on September 16, 2013. Each shareholder of record received one warrant for every ten shares owned as of the record date (with the number of warrants rounded down to the nearest whole number). Each warrant entitles the holder to purchase one share of the Company's common stock at an exercise price of $8.50 per share, subject to certain anti-dilution adjustments, and will expire on April 15, 2016. The warrants will become exercisable on the later of September 1, 2014 or the date that a registration statement has been filed with and declared effective by the SEC with respect to the issuance of the common stock underlying the warrants. The warrants will be subject to redemption at the option of the Company at $0.001 per warrant upon not less than thirty days’ notice to the holders.

During the year ended December 31, 2011, 771,812 of the Company's $3.00 common stock warrants and 42,045 of the Company's $2.50 common stock warrants were exercised for total combined proceeds of approximately $2.4 million, and 15,000 of the Company's $3.00 common stock warrants expired.

During the year ended December 31, 2012, 48 of the Company's $10.50 common stock warrants and 134,177 of the Company's $2.50 common stock warrants were exercised for total combined proceeds of approximately $328,000, and 15,330 of the Company's $10.50 common stock warrants were canceled upon the rescission of the 153,300 Magnum Hunter common shares loaned to the Company's KSOP.

During the year ended December 31, 2013, 13,237,889 of the Company's $10.50 common stock warrants expired.

A summary of warrant activity for the years ended December 31, 2013, 2012, and 2011 is presented below:



	2013				2012				2011
			Weighted -				Weighted -				Weighted -
			Average				Average				Average
	Shares		Exercise Price		Shares		Exercise Price		Shares		Exercise Price
Outstanding at beginning of year	13,376,277		$	10.56	13,525,832		$	10.48	963,034		$	2.91
Granted	17,030,622		$	8.50	—		$	—	13,391,655		$	10.56
Exercised, forfeited, or expired	(13,237,889	)	$	10.50	(149,555	)	$	3.32	(828,857	)	$	2.97
Outstanding at end of year	17,169,010		$	8.56	13,376,277		$	10.56	13,525,832		$	10.48
Exercisable at end of year	17,169,010		$	8.56	13,376,277		$	10.56	13,525,832		$	10.48

At December 31, 2013, the warrants had no aggregate fair value; and the weighted average remaining contract life was 0.8 years.

Series D Preferred Stock

During the year ended December 31, 2011, the Company sold 1,437,558 shares of our 8.0% Series D Cumulative Preferred Stock, par value $0.01 per share and liquidation preference of $50.00 per share, of which 400,000 were sold in an underwritten offering and 1,037,558 were sold under the ATM sales agreement, for net proceeds of $65.0 million. The Series D Preferred Stock cannot be converted into common stock of the Company but may be redeemed by the Company, at the Company’s option, on or after March 14, 2014 for par value or $50.00 per share or in certain circumstances prior to such date as a result of a change in control of the Company. Dividends accrue and are payable monthly on the Series D Preferred Stock at a fixed rate of 8.0% per annum of the $50.00 per share liquidation preference.

During the year ended December 31, 2012, the Company issued an aggregate of 2,771,263 shares of our 8.0% Series D Cumulative Preferred Stock for cumulative net proceeds of approximately $122.5 million, which included various offering expenses of approximately $3.1 million. The 2,771,263 shares of our 8.0% Series D Cumulative Preferred Stock issued during the year ended December 31, 2012 included (i) 1,721,263 shares issued under an ATM sales agreement for net proceeds of approximately $77.9 million, which included approximately $1.5 million of offering and underwriting fees and (ii) 1,050,000 shares issued pursuant to an underwritten public offering on September 7, 2012 at a price of $44.00 per share for net proceeds of approximately $44.6 million, which included approximately $1.6 million of underwriting discounts, commissions and offering expenses.

F-43

During the year ended December 31, 2013, the Company issued under an ATM sales agreement 216,068 shares of its Series D Preferred Stock for net proceeds of approximately $9.6 million, which included sales agent commissions and other issuance costs of approximately $1.2 million.

Series E Preferred Stock

Each share of Series E Preferred Stock, par value $0.01 per share, has a stated liquidation preference of $25,000 and a dividend rate of 8.0% per annum (based on stated liquidation preference), is convertible at the option of the holder into a number of shares of the Company’s common stock equal to the stated liquidation preference (plus accrued and unpaid dividends) divided by a conversion price of $8.50 per share (subject to anti-dilution adjustments in the case of stock dividends, stock splits and combinations of shares), and is redeemable by the Company under certain circumstances. The Series E Preferred Stock is junior to the Company’s 10.25% Series C Cumulative Perpetual Preferred Stock and 8.0% Series D Cumulative Preferred Stock in respect of dividends and distributions upon liquidation. Each Depositary Share is a 1/1000th interest in a share of Series E Preferred Stock. Accordingly, the Depositary Shares have a stated liquidation preference of $25.00 per share and a dividend rate of 8.0% per annum (based on stated liquidation preference), are similarly convertible at the option of the holder into a number of shares of the Company’s common stock equal to the stated liquidation preference (plus accrued and unpaid dividends) divided by a conversion price of $8.50 per share (subject to corresponding anti-dilution adjustments), and are redeemable by the Company under certain circumstances.

In November 2012, the Company issued 2,774,850 Depositary Shares, each representing a 1/1,000th interest in a share of the Company’s 8% Series E Cumulative Convertible Preferred Stock, liquidation preference $25,000 per share, to the shareholders of Virco as partial consideration for the Company’s purchase of 100% of the outstanding stock of Virco. The Company also issued 70,000 Depositary Shares into an escrow account which were returned and held in treasury at cost of $1.8 million upon an indemnification settlement in favor of the Company.

In December 2012, the Company sold in a public offering an aggregate of 1,000,000 Depositary Shares, each representing a 1/1,000th interest in a share of the Company’s 8% Series E Cumulative Convertible Preferred Stock, liquidation preference $25,000 per share. The Depositary Shares were sold to the public at a price of $23.50 per Depositary Share, and the net proceeds to the Company were $22.44 per Depositary Share after deducting underwriting commissions, but before deducting expenses related to the offering.

During the year ended December 31, 2013, the Company issued under an ATM sales agreement an aggregate of 27,906 Depositary Shares, each representing a 1/1,000th interest in a share of the Company’s Series E Preferred Stock. The Depositary Shares were sold to the public at an average price of $24.24 per Depositary Share, and net proceeds to the Company were $590,000 after deducting sales agent commissions and other issuance costs.

Non-controlling Interests

During the year ended December 31, 2012, the Company purchased outstanding non-controlling interest in a subsidiary which the Company did not previously own. The Company acquired the non-controlling interest valued at $497,000 based on fair value at the date of acquisition.

In connection with a Williston Basin acquisition in 2008, the Company entered into equity participation agreements with certain of its lenders pursuant to which the Company agreed to pay to the lenders an aggregate of 12.5% of all distributions paid to the owners of PRC Williston, which equity participation agreements, for accounting purposes, are treated as non-controlling interests in PRC Williston, and consequently, PRC Williston is treated as a majority owned subsidiary of the Company and is consolidated by the Company. The equity participation agreements had a fair value of $3.4 million upon issuance and were accounted for as a non-controlling interest in PRC Williston.

On April 2, 2012, Eureka Hunter Holdings, a majority owned subsidiary, issued 622,641 Class A Common Units representing membership interests in Eureka Hunter Holdings, with a value of $12.5 million, as partial consideration for the assets acquired from TransTex. The value of the units transferred as partial consideration for the acquisition was determined utilizing a discounted future cash flow analysis. The carrying value of the Eureka Hunter Holdings Class A Common Units held by third parties is classified as non-controlling interest.

A summary of non-controlling interests in the Company for the years ended December 31, 2013, 2012, and 2011 is presented below:

F-44



	Year Ended December 31,
	2013			2012			2011
	(in thousands)
Non-controlling interest at beginning of period	$	10,139		$	2,196		$	1,450
Non-controlling interests acquired through acquisition of NGAS	—			—			497
Purchase of outstanding non-controlling interests	—			(497		)	—
Issuance of shares of Eureka Hunter Holdings, LLC Common Units	—			12,453			—
Income (loss) attributable to non-controlling interest	(988		)	(4,013		)	249
Other	(1		)	—			—
Non-controlling interest at end of period	$	9,150		$	10,139		$	2,196

Preferred Dividends Paid

A summary of dividends paid by the Company for the years ended December 31, 2013, 2012, and 2011 is presented below:



	Year Ended December 31,
	2013			2012			2011
	(in thousands)
Dividend on Eureka Hunter Holdings, LLC Series A Preferred Units	$	(14,323	)	$	(8,090	)	$	—
Dividend on Series C Preferred Stock	(10,248		)	(10,248		)	(10,248		)
Dividend on Series D Preferred Stock	(17,655		)	(11,699		)	(3,759		)
Dividend on Series E Preferred Stock	(7,561		)	(894		)	—
Total dividends on Preferred Stock	$	(49,787	)	$	(30,931	)	$	(14,007	)

Accretion of the difference between the carrying value and the redemption value of the Eureka Hunter Holdings, Series A Preferred Units of $6.9 million for the year ended December 31, 2013, $3.8 million for the year ended December 31, 2012, and none for the year ended December 31, 2011, was included in dividends on preferred stock.

NOTE 11 - REDEEMABLE PREFERRED STOCK

Series C Preferred Stock

On December 13, 2009, the Company sold 214,950 shares of its 10.25% Series C Cumulative Perpetual Preferred Stock, par value $0.01 per share and liquidation preference $25.00 per share (the “Series C Preferred Stock”), for net proceeds of $5.1 million. The Series C Preferred Stock cannot be converted into common stock of the Company, but may be redeemed by the Company, at the Company’s option, on or after December 14, 2011 for par value or $25.00 per share. In the event of a change of control of the Company, the Series C Preferred Stock will be redeemable by the holders at $25.00 per share, except in certain circumstances when the acquirer is considered a qualifying public company. The Series C Preferred Stock is recorded as temporary equity because a forced redemption, upon certain circumstances as a result of a change in control of the Company, is outside the Company’s control. Dividends accrue and are payable monthly on the Series C Preferred Stock at a fixed rate of 10.25% per annum of the $25.00 per share liquidation preference.

During the year ended December 31, 2010, the Company sold 2,594,506 shares of the Series C Preferred Stock under its ATM sales agreement for net proceeds of $63.4 million.

During the year ended December 31, 2011, the Company sold 1,190,544 shares of its 10.25% Series C Cumulative Perpetual Preferred Stock under its ATM sales agreement for net proceeds of $29.1 million. The sales during the year ended December 31, 2011 have fully subscribed the authorized 4,000,000 shares of Series C Preferred Stock.

F-45

Eureka Hunter Holdings, LLC Series A Preferred Units

On March 21, 2012, Eureka Hunter Holdings entered into a Series A Convertible Preferred Unit Purchase Agreement (the “Unit Purchase Agreement”) with Magnum Hunter and Ridgeline Midstream Holdings, LLC (“Ridgeline”), an affiliate of ArcLight Capital Partners, LLC. Pursuant to this Unit Purchase Agreement, Ridgeline committed, subject to certain conditions, to purchase up to $200 million of Series A Convertible Preferred Units representing membership interests of Eureka Hunter Holdings (the “Series A Preferred Units”).

During the years ended December 31, 2013 and December 31, 2012, Eureka Hunter Holdings issued 1,800,000 and 7,590,000, Series A Preferred Units, respectively, to Ridgeline for net proceeds of $35.3 million and $148.6 million, respectively, net of transaction costs. The Series A Preferred Units outstanding at December 31, 2013 represented 41.7% of the ownership of Eureka Hunter Holdings on a basis as converted to Class A Common Units of Eureka Hunter Holdings and represent non-controlling interests in the form of redeemable preferred stock of a subsidiary in consolidation of the Company. Eureka Hunter Holdings pays cumulative distributions quarterly on the Series A Preferred Units at a fixed rate of 8% per annum of the initial liquidation preference. The distribution rate is increased to 10% if any distribution is not paid when due. The board of directors of Eureka Hunter Holdings may elect to pay up to 75% of the distributions owed for the period from March 21, 2012 through March 31, 2013 in the form of “paid-in-kind” units and may elect to pay up to 50% of the distributions owed for the period from April 1, 2013 through March 31, 2014 in such units. The Series A Preferred Units can be converted into Class A Common Units of Eureka Hunter Holdings upon demand by Ridgeline at any time or by Eureka Hunter Holdings upon the consummation of a qualified initial public offering, provided that Eureka Hunter Holdings converts no less than 50% of the Series A Preferred Units into Class A Common Units at that time. The conversion rate is 1:1, which may be adjusted from time to time based upon certain anti-dilution and other provisions. Eureka Hunter Holdings can redeem all outstanding Series A Preferred Units at their liquidation preference, which involves a specified IRR hurdle, any time after March 21, 2017. Holders of the Series A Preferred Units can force redemption of all outstanding Series A Preferred Units any time after March 21, 2020, at a redemption rate equal to the higher of the as-converted value and a specified internal investment rate of return calculation. The Series A Preferred Units are recorded as temporary equity because a forced redemption by the holders of the preferred units is outside the control of Eureka Hunter Holdings.

The Company has evaluated the Series A Preferred Units and determined that they should be considered a “debt host” and not an “equity host”. This evaluation is necessary to determine if any embedded features require bifurcation and, therefore, would be required to be accounted for separately as a derivative liability. The Company's analysis followed the “whole instrument approach,” which compares an individual feature against the entire preferred instrument that includes that feature. The Company's analysis was based on a consideration of the economic characteristics and risks of the preferred unit and, more specifically, evaluated all of the stated and implied substantive terms and features of such unit, including (1) whether the preferred unit included redemption features; (2) how and when any redemption features could be exercised; (3) whether the holders of preferred units were entitled to dividends; (4) the voting rights of the preferred unit; and (5) the existence and nature of any conversion rights. As a result of the Company's determination that the preferred unit is a “debt host,” the Company determined that the embedded conversion option, redemption options and other features of the preferred units do require bifurcation and separate accounting as embedded derivatives. The fair value of the embedded features were determined at the issuance dates which were bifurcated from the issuance values of the Series A Preferred Units and presented in long term liabilities. The fair value of this embedded feature was determined to be $75.9 million and $43.5 million in the aggregate at December 31, 2013 and 2012, respectively. See "Note 3 - Fair Value of Financial Instruments".

During the year ended December 31, 2013, the Company paid cash distributions of $5.2 million and accrued distributions of $3.9 million not yet paid, to the holder of the Company's Series A Preferred Units. During such year, distributions in the amount of $8.2 million were paid-in-kind to the holder of the Series A Preferred Units and the Company issued 412,157 Series A Preferred Units as payment. At December 31, 2013, 9,885,048 shares of Series A Preferred Units were outstanding.

F-46

NOTE 12 - INCOME TAXES

The total provision for income taxes applicable to continuing operations consists of the following:



	Year Ended December 31,
	2013			2012			2011
	(in thousands)
Deferred income tax benefit
Federal	$	(63,629	)	$	(15,109	)	$	(1,025	)
State	(6,668		)	(4,203		)	(1,837		)
Total deferred tax benefit	$	(70,297	)	$	(19,312	)	$	(2,862	)
Total income tax benefit	$	(70,297	)	$	(19,312	)	$	(2,862	)

At December 31, 2013, the Company has net operating loss carryforwards ("NOL's") available for U.S. federal income tax purposes of approximately $400 million, which expire in varying amounts during the tax years 2018 through 2033. In addition, the Company has NOL carryforwards related to its Canadian operations of approximately $66.4 million , which expire in varying amounts between years 2015 through 2033. The deferred tax asset recorded for the U.S. NOL does not include $22.4 million of deductions for excess stock-based compensation (tax effected $8.3 million). The Company will recognize the NOL tax assets associated with excess stock-based compensation tax deductions only when all other components of the NOL tax assets have been fully utilized and a cash tax benefit is realized. Upon realization, the excess stock-based compensation deduction will reduce taxes payable and will be credited directly to equity.

At December 31, 2013, the Company was not under examination by any federal or state taxing jurisdiction, nor had the Company been contacted by any examining agency.

The Company has approximately $2.8 million (tax effected $1.1 million) of depletion carryover which has no expiration.

The Company has no unremitted earnings in Canada.

The Company has recorded a valuation allowance of $150.5 million against the net deferred tax assets of the Company at December 31, 2013. The Company is uncertain on a more likely than not basis that the NOL and other deferred tax assets will be utilized in the future. Management evaluated all available positive and negative evidence in making this assessment. The assessment included objectively verifiable information such as historical operating results, future projections of operating results, future reversals of existing taxable temporary differences and anticipated capital expenditures. Management placed a significant amount of weight on the historical results.

The following is a reconciliation of the reported amount of income tax expense (benefit) attributable to continuing operations for the years ended December 31, 2013, 2012, and 2011 to the amount of income tax expense that would result from applying domestic federal statutory tax rates to pretax income:



	Year Ended December 31,
	2013			2012			2011
	(in thousands)
Income tax benefit at statutory U.S. rate	$	(96,022	)	$	(48,639	)	$	(20,887	)
State income taxes (net of federal benefit)	(4,334		)	(2,732		)	(1,194		)
Tax effect of permanent differences	750			(555		)	419
Tax effect of loss attributable to non-controlled interest	346			797			—
Tax benefit recognized as tax expense in discontinued operations	(13,879		)	—			—
Change in valuation allowance	43,232			31,810			18,800
Other	(390		)	7			—
Total continuing operations	(70,297		)	(19,312		)	(2,862		)
Discontinued operations	(3,336		)	(2,283		)	2,166
Total tax benefit	$	(73,633	)	$	(21,595	)	$	(696	)

F-47

Income (loss) before income taxes was as follows:



	Year Ended December 31,
	2013			2012			2011
	(in thousands)
Domestic	$	(274,349	)	$	(138,968	)	$	(59,676	)
Loss from continuing operations	(274,349		)	(138,968		)	(59,676		)
Loss from discontinued operations	(75,838		)	(23,053		)	(17,432		)
Gain on disposal of discontinued operations	53,389			3,706			—
Loss before income tax	$	(296,798	)	$	(158,315	)	$	(77,108	)

Deferred Tax Assets and Liabilities

The tax effects of temporary differences that gave rise to the Company's deferred tax assets and liabilities are presented below:



	Year Ended December 31,
	2013			2012			2011
	(in thousands)
Deferred tax assets:
Net operating loss carry forwards	$	155,507		$	193,310		$	62,923
Share-based compensation	10,156			7,950			10,247
Depletion carryforwards	1,047			997			972
Tax credits	53			53			26,340
US investment in Canada	74,148			—			—
Other	561			532			7,475
Deferred tax liabilities:
Property and equipment	(90,950		)	(206,650		)	(111,015		)
Valuation allowance	(150,522		)	(70,450		)	(92,241		)
Net deferred tax asset (liability)	$	—		$	(74,258	)	$	(95,299	)

As of December 31, 2013 the Company provided for a liability of $3.9 million for unrecognized tax benefits related to various federal tax matters, which were netted against the Company's net operating loss. Settlement of the uncertain tax position is expected to occur in the next 12 months and will have no effect on income tax expense (benefit). The Company has elected to classify interest and penalties related to uncertain income tax positions in income tax expense. Due to available NOLs, as of December 31, 2013, the Company has accrued no amounts for potential payment of interest and penalties.

Following is a reconciliation of the total amounts of unrecognized tax benefits during the years ended December 31, 2013, 2012 and 2011:



	Year Ended December 31,
	2013		2012		2011
	(in thousands)
Unrecognized tax benefits at January 1	$	3,879	$	—	$	—
Change in unrecognized tax benefits taken during a prior period	—		—		—
Change in unrecognized tax benefits taken during the current period (netted against the US net operating loss)	—		3,879		—
Decreases in unrecognized tax benefits from settlements with taxing authorities	—		—		—
Reductions to unrecognized tax benefits from lapse of statutes of limitations	—		—		—
Unrecognized tax benefits at December 31	$	3,879	$	3,879	$	—

F-48

NOTE 13 - MAJOR CUSTOMERS

The Company's share of oil and gas production is sold to various purchasers who must be prequalified under the Company's credit risk policies and procedures. After giving effect to the Eagle Ford Hunter sale, the following purchasers individually accounted for ten percent or more of the Company's consolidated continuing oil and gas revenues in at least one of the three years ended December 31, 2013. The loss of any one significant purchaser could have a material, adverse effect on the ability of the Company to sell its oil and gas production. Although the Company is exposed to a concentration of credit risk, the Company believes that all of its purchasers are credit worthy.

The table below provides the percentages of the Company's consolidated oil, NGL and gas revenues from continuing operations represented by its major purchasers during the periods presented:



	Year Ended December 31,
	2013		2012		2011
Samson Resources Company	36	%	17	%	10	%
Baytex Energy USA LTD	10	%	15	%	3	%
Teneska Marketing Ventures	9	%	14	%	14	%
South Jersey	5	%	14	%	10	%
Plains Marketing, LP	4	%	11	%	16	%
Clearfield Energy	1	%	7	%	16	%
Ergon Oil	3	%	5	%	13	%

F-49

NOTE 14 - SUPPLEMENTAL CASH FLOW INFORMATION

The following summarizes cash paid (received) for interest and income taxes, as well as non-cash investing transactions:



	Year Ended December 31,
	2013			2012		2011
	(in thousands)
Cash paid for interest	$	70,366		$	40,069	$	7,952
Cash paid for taxes	$	1,200		$	—	$	—
Non-cash transactions
Change in accrued capital expenditures - increase (decrease)	$	(65,634	)	$	34,621	$	81,136
Eureka Hunter Holdings, LLC Series A convertible preferred unit dividends paid in kind	$	8,243		$	1,658	$	—
Non-cash additions to asset retirement obligation	$	2,132		$	8,492	$	12,628
Common stock issued for 401k matching contributions	$	1,192		$	874	$	—
Preferred stock issued for acquisitions	$	—		$	64,968	$	—
Eureka Hunter Holdings, LLC Class A common units issued for an acquisition	$	—		$	12,453	$	—
Non-cash consideration received from sale of assets	$	42,300		$	7,120	$	—
Common stock issued for acquisitions	$	—		$	1,902	$	345,537
Debt assumed in acquisitions	$	—		$	—	$	71,895
Exchangeable common stock issued for acquisition of NuLoch Resources	$	—		$	—	$	31,642
Common stock issued for payment of services	$	—		$	—	$	779
Dividends on MHR Exchangeco Corporation's exchangeable common stock in the form of 378,174 warrants with fair market value of $197 thousand	$	—		$	—	$	197

The Company issued dividends on common stock in the form of 17,030,622 warrants and 12,875,093 warrants with fair value of $21.6 million and $6.7 during the years ended December 31, 2013 and 2012, respectively.

F-50

NOTE 15 - OTHER INFORMATION

Quarterly Data (Unaudited)

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



	Quarter Ended
	March 31,			June 30,			September 30,			December 31,			Year Ended
	2013
	(in thousands)
Total revenue	$	54,235		$	67,907		$	73,032		$	85,237		$	280,411
Operating gain (loss) ⁽¹⁾	$	(40,009	)	$	(26,240	)	$	(92,676	)	$	(25,839	)	$	(184,764	)
Income (loss) from continuing operations	$	(61,544	)	$	347		$	(132,598	)	$	(10,257	)	$	(204,052	)
Income (loss) from discontinued operations, net of tax⁽²⁾	$	16,845		$	(7,746	)	$	(80,554	)	$	324		$	(71,131	)
Gain (loss) on disposal of discontinued operations, net of tax⁽³⁾	$	—		$	172,452		$	(84,454	)	$	(35,979	)	$	52,019
Net income (loss) attributable to Magnum Hunter Resources Corporation	$	(44,197	)	$	165,440		$	(296,882	)	$	(46,537	)	$	(222,176	)
Net income (loss) attributable to common shareholders	$	(57,685	)	$	151,311		$	(311,299	)	$	(61,208	)	$	(278,881	)
Basic and diluted income (loss) from continuing operations per common share	$	(0.36	)	$	0.00		$	(0.86	)	$	(0.06	)	$	(1.53	)
Basic and diluted income (loss) per common share	$	(0.34	)	$	0.89		$	(1.83	)	$	(1.11	)	$	(1.64	)

	2012
Total revenue	$	27,945		$	30,598		$	36,381		$	45,432		$	140,356
Operating loss ⁽⁴⁾	$	(15,698	)	$	(15,797	)	$	(8,898	)	$	(67,814	)	$	(108,207	)
Loss from continuing operations	$	(22,533	)	$	(8,638	)	$	(31,313	)	$	(57,172	)	$	(119,656	)
Income (loss) from discontinued operations, net of tax	$	5,723		$	(1,789	)	$	(1,102	)	$	(22,306	)	$	(19,474	)
Gain (loss) on disposal of discontinued operations, net of tax	4,325			(2,101		)	—			185			2,409
Net income (loss) attributable to Magnum Hunter Resources Corporation	$	(12,458	)	$	(12,577	)	$	(32,463	)	$	(75,210	)	$	(132,708	)
Net loss attributable to common shareholders	$	(17,052	)	$	(20,843	)	$	(42,283	)	$	(87,236	)	$	(167,414	)
Basic and diluted loss from continuing operations per common share	$	(0.17	)	$	(0.06	)	$	(0.19	)	$	(0.34	)	$	(0.96	)
Basic and diluted income (loss) per common share	$	(0.13	)	$	(0.15	)	$	(0.25	)	$	(0.54	)	$	(1.07	)

______________

⁽¹⁾

The quarter-ended September 30, 2013, loss from operations was primarily driven by the loss on the sale of certain properties in Burke County, North Dakota of $38.1 million, and exploration expense. Management reviews leasehold acreage on a quarterly basis. During the quarter-ended September 30, 2013, management determined a significant portion of the non-core Williston Basin acreage would not be utilized as the Company planned to focus on assets that will provide a higher rate of return.


⁽²⁾	The quarter-ended September 30, 2013, loss from discontinued operations was primarily driven by impairment expense of $72.5 million, as management determined a significant portion of the non-core acreage would not be utilized.

F-51

⁽³⁾

The quarter-ended June 30, 2013 gain on disposal of discontinued operations was primarily due to the gain on sale of the Company's Eagle Ford Shale assets. The quarter-ended September 30, 2013 loss on disposal of discontinued operations was primarily due to an expense of $64.8 million, net of tax to reflect the net assets of Magnum Hunter Production and Williston Hunter Canada to their fair values as a result of the Company's decision to sell these assets. The quarter-ended December 31, 2013 loss on disposal of discontinued operations was primarily due to an expense of $27.6 million, net of tax, to reflect changes in the estimated fair values of the net assets of Magnum Hunter Production and Williston Hunter Canada which the Company had decided to sell during the quarter ended September 30, 2013. See "Note 2 - Divestitures and Discontinued Operations".


⁽⁴⁾	The quarter-ended December 31, 2012, loss from operations was primarily driven by exploration expense. During the quarter-ended December 31, 2012 management determined that a significant portion of the non-core Williston Basin acreage would not be utilized as the Company planned to focus on assets that will provide a higher rate of return in 2013.

Segment Reporting

U.S. Upstream, Midstream and Oilfield Services represent the operating segments of the Company. As of December 31, 2013 the Canadian Upstream segment, comprised of the WHI Canada operations, was classified as assets held for sale and discontinued operations. The factors used to identify these reportable segments are based on the nature of the operations, nationality, operating strategies and management expertise involved in each. The Upstream segments are organized and operate to explore for and produce crude oil and natural gas within the geographic boundaries of the U.S. and Canada. The Midstream segment markets natural gas and operates a network of pipelines and compression stations that gather natural gas and NGL for transportation to market. The Oilfield Services segment provides drilling services to oil and natural gas exploration and production companies. Midstream and Oilfield Services customers are the Company's subsidiaries and other third-party oil and natural gas companies.

F-52

The following tables set forth operating activities and capital expenditures by segment for the years ended, and segment assets as of December 31, 2013, 2012, and 2011.



	For the Year Ended December 31, 2013 (in thousands)
	U.S. Upstream			Canadian Upstream			Midstream			Oil Field Services			Corporate Unallocated			Intersegment Eliminations			Total
Oil and gas sales	$	197,599		$	—		$	—		$	—		$	—		$	—		$	197,599
Gas transportation, gathering and processing	2			—			69,306			—			—			(8,676		)	60,632
Oil field services	23			—			—			21,525			—			(3,117		)	18,431
Other revenue	3,747			—			—			2			—			—			3,749
Total revenue	201,371			—			69,306			21,527			—			(11,793		)	280,411
Lease operating expenses	62,675			—			—			—			—			(8,714		)	53,961
Severance taxes and marketing	17,721			—			—			—			—			—			17,721
Exploration	97,342			—			—			—			—			—			97,342
Gas transportation, gathering and processing	2			—			52,097			—			—			—			52,099
Oil field services	(10		)	—			—			17,914			—			(3,079		)	14,825
Impairment of proved oil and gas properties	9,968			—			—			—			—			—			9,968
Depreciation, depletion, and accretion	84,526			—			12,318			2,354			—			—			99,198
Loss on sale of assets	44,642			—			8			4			—			—			44,654
General and administrative	14,255			—			8,400			1,338			49,241			2,173			75,407
Total expenses	331,121			—			72,823			21,610			49,241			(9,620		)	465,175
Operating income (loss)	(129,750		)	—			(3,517		)	(83		)	(49,241		)	(2,173		)	(184,764		)
Interest income	219			—			—			—			4,824			(4,823		)	220
Interest expense	(7,208		)	—			(4,351		)	(507		)	(67,420		)	7,063			(72,423		)
Loss on derivative contracts	(185		)	—			(17,742		)	—			(7,347		)	—			(25,274		)
Other	(340		)	—			(265		)	—			8,497			—			7,892
Total other income (expense)	(7,514		)	—			(22,358		)	(507		)	(61,446		)	2,240			(89,585		)
Income (loss) from continuing operations before income tax	(137,264		)	—			(25,875		)	(590		)	(110,687		)	67			(274,349		)
Income tax benefit (expense)	41,308			—			—			—			28,989			—			70,297
Income (loss) from continuing operations	(95,956		)	—			(25,875		)	(590		)	(81,698		)	67			(204,052		)
Income (loss) from discontinued operations	5,293			(76,355		)	—			—						(69		)	(71,131		)
Gain (loss) on disposal of discontinued operations	125,871			(73,852		)	—			—			—			—			52,019
Net income (loss)	35,208			(150,207		)	(25,875		)	(590		)	(81,698		)	(2		)	(223,164		)
Loss (income) attributable to non-controlling interest	—			—			—			—						988			988
Net income (loss) attributable to Magnum Hunter Resources Corporation	$	35,208		$	(150,207	)	$	(25,875	)	$	(590	)	$	(81,698	)	$	986		$	(222,176	)
Dividends on preferred stock	—			—			(21,241		)	—			(35,464		)	—			(56,705		)
Net income (loss) attributable to common shareholders	$	35,208		$	(150,207	)	$	(47,116	)	$	(590	)	$	(117,162	)	$	986		$	(278,881	)
Total segment assets	$	1,373,041		$	68,367		$	296,739		$	44,193		$	77,684		$	(3,373	)	$	1,856,651
Segment capital expenditures	$	489,702		$	31,025		$	87,048		$	22,699		$	1,037		$	—		$	631,511

F-53



	For the Year Ended December 31, 2012 (in thousands)
	U.S. Upstream			Canadian Upstream			Midstream			Oil Field Services			Corporate Unallocated			Intersegment Eliminations			Total
Oil and gas sales	$	114,659		$	—		$	—		$	—		$	—		$	—		$	114,659
Gas transportation, gathering and processing	—			—			15,469			—			—			(2,429		)	13,040
Oil field services	—			—			—			13,552			—			(1,219		)	12,333
Other revenue	99			—			223			—			—			2			324
Total revenue	114,758			—			15,692			13,552			—			(3,646		)	140,356
Lease operating expenses	30,429			—			—			—			—			(3,590		)	26,839
Severance taxes and marketing	7,854			—			—			—			—			—			7,854
Exploration	78,221			—			—			—			—			—			78,221
Gas transportation, gathering and processing	—			—			7,908			—			—			120			8,028
Oil field services	—			—			—			10,420			—			(383		)	10,037
Impairment of proved oil and gas properties	3,772			—			—			—			—			—			3,772
Depreciation, depletion, and accretion	52,332			—			5,963			967			—			468			59,730
Loss (gain) on sale of assets	278			—			(250		)	600			—			—			628
General and administrative	21,789			—			3,798			418			27,137			312			53,454
Total expenses	194,675			—			17,419			12,405			27,137			(3,073		)	248,563
Operating income (loss)	(79,917		)	—			(1,727		)	1,147			(27,137		)	(573		)	(108,207		)
Interest income	197			—			—			—			3,483			(3,481		)	199
Interest expense	(13,053		)	—			(758		)	(327		)	(41,022		)	3,544			(51,616		)
Loss on derivative contracts	129			—			8,692			—			13,418			—			22,239
Other	(882		)	—			(546		)	(155		)	—			—			(1,583		)
Total other income (expense)	(13,609		)	—			7,388			(482		)	(24,121		)	63			(30,761		)
Income (loss) from continuing operations before income tax	(93,526		)	—			5,661			665			(51,258		)	(510		)	(138,968		)
Income tax benefit (expense)	19,312			—			—			—			—			—			19,312
Income (loss) from continuing operations	(74,214		)	—			5,661			665			(51,258		)	(510		)	(119,656		)
Income (loss) from discontinued operations	6,661			(25,021		)	—			230			—			(1,344		)	(19,474		)
Gain on disposal of discontinued operations	2,409			—			—			—			—			—			2,409
Net income (loss)	(65,144		)	(25,021		)	5,661			895			(51,258		)	(1,854		)	(136,721		)
Net income (loss) attributable to non-controlling interest	4,173			—			(160		)	—			—			—			4,013
Net income (loss) attributable to Magnum Hunter Resources Corporation	(60,971		)	(25,021		)	5,501			895			(51,258		)	(1,854		)	(132,708		)
Dividends on preferred stock	—			—			(11,864		)	—			(22,842		)	—			(34,706		)
Net income (loss) attributable to common shareholders	$	(60,971	)	$	(25,021	)	$	(6,363	)	$	895		$	(74,100	)	$	(1,854	)	$	(167,414	)
Total segment assets	$	1,602,022		$	392,918		$	245,207		$	23,810		$	93,612		$	(158,937	)	$	2,198,632
Segment capital expenditures	$	417,431		$	84,536		$	57,010		$	8,828		$	805		$	—		$	568,610

F-54



	For the Year Ended December 31, 2011(in thousands)
	U.S. Upstream			Canadian Upstream		Midstream			Oil Field Services			Corporate Unallocated			Intersegment Eliminations			Total
Oil and gas sales	$	58,726		$	—	$	—		$	—		$	—		$	—		$	58,726
Gas transportation, gathering and processing	—			—		1,978			—			—			(1,484		)	494
Oil field services	—			—		—			9,417			—			(2,268		)	7,149
Other revenue	65			—		12			9			—			—			86
Total revenue	58,791			—		1,990			9,426			—			(3,752		)	66,455
Lease operating expenses	17,194			—		—			—			—			(2,196		)	14,998
Severance taxes and marketing	5,341			—		—			—			—			—			5,341
Exploration	2,605			—		—			—			—			—			2,605
Gas transportation, gathering and processing	—			—		373			—			—			—			373
Oil field services	—			—		—			8,315			—			(1,556		)	6,759
Impairment of proved oil and gas properties	—			—		—			—			—			—			—
Depreciation, depletion, and accretion	20,913			—		1,789			544			—			—			23,246
Loss (gain) on sale of assets	861			—		(500		)	—			—			—			361
General and administrative	2,255			—		850			461			50,794			—			54,360
Total expenses	49,169			—		2,512			9,320			50,794			(3,752		)	108,043
Operating income (loss)	9,622			—		(522		)	106			(50,794		)	—			(41,588		)
Interest income	6			—		—			—			4						10
Interest expense	(2,071		)	—		(1,673		)	(183		)	(9,879		)	2,054			(11,752		)
Gain (loss) on derivative contracts	—			—		—			—			(6,346		)	—			(6,346		)
Other	—			—		—			—			—			—			—
Total other expense	(2,065		)	—		(1,673		)	(183		)	(16,221		)	2,054			(18,088		)
Income (loss) from continuing operations before income tax	7,557			—		(2,195		)	(77		)	(67,015		)	2,054			(59,676		)
Income tax benefit	1,637			697		—			1,042			—			(514		)	2,862
Income (loss) from continuing operations	9,194			697		(2,195		)	965			(67,015		)	1,540			(56,814		)
Income (loss) from discontinued operations	(21,848		)	1,855		—			1,935			—			(1,540		)	(19,598		)
Gain on disposal of discontinued operations	—			—		—			—			—			—			—
Net income (loss)	(12,654		)	2,552		(2,195		)	2,900			(67,015		)	—			(76,412		)
Net loss attributable to non-controlling interest	(249		)	—		—			—			—			—			(249		)
Net income (loss) attributable to Magnum Hunter Resources Corporation	(12,903		)	2,552		(2,195		)	2,900			(67,015		)	—			(76,661		)
Dividends on preferred stock	—			—		—			—			(14,007		)	—			(14,007		)
Net income (loss) attributable to common shareholders	(12,903		)	2,552		(2,195		)	2,900			(81,022		)	—			(90,668		)
Total segment assets	$	797,674		$	349,410	$	83,847		$	17,045		$	47,839		$	(127,055	)	$	1,168,760
Segment capital expenditures	$	202,818		$	18,493	$	54,748		$	6,494		$	9,389		$	—		$	291,942

F-55

Supplemental Oil and Gas Disclosures (Unaudited)

The following table sets forth the costs incurred in oil and gas property acquisition, exploration, and development activities (in thousands):



	For the Year Ended December 31,
	2013		2012		2011
Purchase of non-producing leases	$	149,592	$	414,037	$	397,947
Purchase of producing properties	1,358		159,290		226,634
Exploration costs	11,531		165,789		112,606
Development costs	273,944		262,486		101,151
Asset retirement obligation	2,186		407		5,390
	$	438,611	$	1,002,009	$	843,728

F-56

Oil and Gas Reserve Information

Proved oil and gas reserve quantities are based on estimates prepared by Magnum Hunter’s third party reservoir engineering firms Cawley, Gillespie, & Associates, Inc. in 2013, and Cawley, Gillespie, & Associates, Inc. and AJM Deloitte in 2012 and 2011. There are numerous uncertainties inherent in estimating quantities of proved reserves and projecting future rates of production and timing of development expenditures. The following reserve data only represent estimates and should not be construed as being exact.



Total Proved Reserves	Crude Oil	NGLs	Natural Gas
	(MBbl)	(MBbl)	(MMcf)
Balance December 31, 2010	6,824	—	39,452
Revisions of previous estimates	4,104	2,833	40,494
Purchases of reserves in place	4,870	1,475	43,757
Extensions, discoveries, and other additions	2,317	370	22,399
Sales of reserves in place	(215)	—	(11)
Production	(776)	(93)	(6,854)
Balance December 31, 2011	17,124	4,585	139,237
Revisions of previous estimates	7,936	4,632	25,644
Purchases of reserves in place	10,613	—	12,082
Extensions, discoveries, and other additions	3,305	110	544
Sales of reserves in place	(10)	—	(63)
Production	(2,141)	(202)	(14,824)
Balance December 31, 2012	36,827	9,125	162,620
Revisions of previous estimates	3,766	2,382	100,456
Purchases of reserves in place	—	—	88
Extensions, discoveries and other additions	577	71	1,285
Sales of reserves in place	(14,506)	(698)	(4,185)
Production	(2,329)	(458)	(13,482)
Balance December 31, 2013	24,335	10,422	246,782
Developed reserves, included above:
December 31, 2011	7,719	1,460	90,198
December 31, 2012	16,355	6,262	125,526
December 31, 2013	12,085	6,990	176,585
Proved undeveloped reserves, included above:
December 31, 2011	9,405	3,126	49,039
December 31, 2012	20,472	2,863	37,094
December 31, 2013	12,250	3,432	70,197

The 2011 purchases of reserves in place includes approximately 4,909 MBoe of proved reserves acquired in the May 3, 2011 acquisition of all of the outstanding common shares of NuLoch Resources, Inc. and approximately 8,714 MBoe of proved reserves acquired in the April 13, 2011 acquisition of all of the outstanding common shares of NGAS Resources, Inc. The 2012 purchases of reserves in place includes approximately 2,217 MBoe of proved reserves acquired in the Eagle Operating Assets Acquisition, approximately 8,595 MBoe of proved reserves acquired in the Baytex Energy USA Assets Acquisition, approximately 1,428.9 MBoe acquired in the Virco acquisition and various smaller acquisitions (See “Note 5 – Acquisitions”). The 2013 sales of reserves in place includes approximately 11,459 MBoe of proved reserves included in the sale of Eagle Ford Hunter and approximately 4,308 MBoe of proved reserves in the sale of Certain North Dakota Oil and Natural Gas Properties (See “Note 2 – Divestitures and Discontinued Operations”).

F-57

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Reserves

The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves and the changes in standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves were prepared in accordance with provisions of ASC 932, Extractive Activities - Oil and Gas. Future cash inflows at December 31, 2013, 2012, and 2011 were computed by applying the unweighted, arithmetic average of the closing price on the first day of each month for the 12-month period prior to December 31, 2013, 2012, and 2011 to estimated future production. Future production and development costs are computed by estimating the expenditures to be incurred in developing and producing the proved oil and natural gas reserves at year-end, based on year-end costs and assuming continuation of existing economic conditions.

Future income tax expenses are calculated by applying appropriate year-end tax rates to future pretax net cash flows relating to proved oil and natural gas reserves, less the tax basis of properties involved. Future income tax expenses give effect to permanent differences, tax credits and loss carry forwards relating to the proved oil and natural gas reserves. Future net cash flows are discounted at a rate of 10% annually to derive the standardized measure of discounted future net cash flows. This calculation procedure does not necessarily result in an estimate of the fair market value of the Company's oil and natural gas properties.

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



	Years Ended December 31,
	2013			2012			2011
	(in thousands)
Future cash inflows	$	3,711,260		$	4,248,384		$	2,409,249
Future production costs	(1,423,306		)	(1,520,260		)	(765,048		)
Future development costs	(421,797		)	(603,809		)	(330,007		)
Future income tax expense	(149,367		)	(230,500		)	(253,721		)
Future net cash flows	1,716,790			1,893,815			1,060,473
10% annual discount for estimated timing of cash flows	(872,280		)	(1,046,162		)	(586,077		)
Standardized measure of discounted future net cash flows	$	844,510		$	847,653		$	474,396

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

F-58

Changes in Standardized Measure of Discounted Future Net Cash Flows

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



	Years Ended December 31,
	2013			2012			2011
	(in thousands)
Balance, beginning of period	$	847,653		$	474,396		$	127,959
Net changes in prices and production costs	(7,355		)	13,647			49,498
Changes in estimated future development costs	(261,591		)	(391,318		)	(167,399		)
Sales and transfers of oil and gas produced during the period	(190,151		)	(179,384		)	(71,724		)
Net changes due to extensions, discoveries, and improved recovery	12,829			60,468			110,316
Net changes due to revisions of previous quantity estimates ⁽¹⁾	341,003			290,500			235,163
Previously estimated development costs incurred during the period	283,736			245,168			24,740
Accretion of discount	90,153			85,377			27,029
Purchase of minerals in place	218			217,791			234,336
Sale of minerals in place	(236,885		)	(354		)	(3,726		)
Changes in timing and other ⁽²⁾	(91,088		)	22,436			824
Net change in income taxes	55,988			8,926			(92,620		)
Standardized measure of discounted future net cash flows	$	844,510		$	847,653		$	474,396

______________

⁽¹⁾

The Company's net changes due to revisions of previous quantity estimates primarily reflect upward revisions to recoverable quantities of oil and gas minerals assuming existing prices and technology. For the year ended December 31, 2013, the Company made upward revisions of 3,766 MBbl of oil, 2,382 MBbl of natural gas liquids and 100,456 MMcf of natural gas due to additional information gathered from continued production from the shale areas and increases in estimated ultimate recoveries (EURs). For the year ended December 31, 2012, the Company made upward revisions of 7,936 MBbls of oil, 4,632 MBml of natural gas liquids and 25,644 MMcf of natural gas.


⁽²⁾	The Company's changes in timing and other primarily represent changes in the Company's estimates of when proved reserve quantities will be realized. The reserves as of December 31, 2012, reflect accelerated recovery of minerals due to purchases of minerals in place and capital expenditures incurred to develop properties.

The commodity prices inclusive of adjustments for quality and location used in determining future net revenues related to the standardized measure calculation are as follows:



	2013		2012		2011
Oil (per Bbl)	$	93.13	$	88.37	$	96.19
Natural gas liquids (per Bbl)	$	43.79	$	53.94	$	44.25
Gas (per Mcf)	$	4.14	$	3.08	$	4.11

F-59

NOTE 16 - RELATED PARTY TRANSACTIONS

The following table sets forth the related party balances as of December 31, 2013 and 2012:



	As of December 31,
	2013		2012
	(in thousands)
Green Hunter ⁽¹⁾
Accounts receivable - net	$	23	$	—
Derivative assets ⁽²⁾	$	79	$	264
Investments ⁽²⁾	$	2,262	$	3,009
Notes receivable ⁽²⁾	$	1,768	$	2,173
Prepaid expenses	$	9	$	—

The following table sets forth the related party transaction activities for the years ended December 31, 2013, 2012 and 2011:



		Years Ended
		December 31,
		2013		2012		2011
		(in thousands)
GreenHunter
	Salt water disposal expense ⁽¹⁾	$	3,033	$	2,400	$	—
	Equipment rental expense ⁽¹⁾	$	282	$	1,000	$	1,300
	Office space rental expense ⁽¹⁾	$	13	—		—
	Professional services income ⁽¹⁾	$	—	$	—	$	162
	Interest income from note receivable⁽²⁾	$	205	$	191	$	—
	Dividends received from Series C shares	$	220	$	—	$	—
	Loss on investments ⁽²⁾	$	730	1,333		$	—
Pilatus Hunter, LLC
	Airplane rental expense ⁽³⁾	$	166	$	174	$	463
Executive of the Company
	Corporate apartment rental expense ⁽⁴⁾	$	—	$	23	$	36

_________________________________

⁽¹⁾

GreenHunter is an entity of which Gary C. Evans, Magnum Hunter's Chairman and CEO, is the Chairman, a major shareholder and former interim CEO; of which David Krueger, the Company's former Chief Accounting Officer and Senior Vice President, is the former Chief Financial Officer; and of which Ronald D. Ormand, the Company’s former Chief Financial Officer and Executive Vice President, is a former director. Eagle Ford Hunter received, and Triad Hunter and Viking International Resources, Inc. ("Virco"), 100% owned subsidiaries of the Company, receive services related to salt water disposal and rental equipment from GreenHunter and its affiliated companies, White Top Oilfield Construction, LLC and Black Water Services, LLC. The Company believes that such services were and are provided at competitive market rates and were and are comparable to, or more attractive than, rates that could be obtained from unaffiliated third party suppliers of such services.

⁽²⁾

On February 17, 2012, the Company sold its 100% owned subsidiary, Hunter Disposal, to GreenHunter Water, LLC ("GreenHunter Water"), a 100% owned subsidiary of GreenHunter. The Company recognized an embedded derivative asset resulting from the conversion option under the convertible promissory note it received as partial consideration for the sale. The Company has recorded interest income at the rate of 10% on the note receivable from GreenHunter. Also as a result of this transaction, the Company has an equity method investment in GreenHunter that is included in derivatives and other long term assets and an available for sale investment in GreenHunter included in investments.


⁽³⁾	The Company rented an airplane for business use for certain members of Company management at various times from Pilatus Hunter, LLC, an entity 100% owned by Mr. Evans. Airplane rental expenses are recorded in general and administrative expense.


⁽⁴⁾	During the years ended December 31, 2011 and 2012, the Company paid rent under a lease for a Houston, Texas corporate apartment from an executive of the Company, which apartment was used by other Company employees when in Houston for Company business. The lease terminated in May 2012.

F-60

In connection with the sale of Hunter Disposal, Triad Hunter entered into agreements with Hunter Disposal and GreenHunter Water for wastewater hauling and disposal capacity in Kentucky, Ohio, and West Virginia and a five-year tank rental agreement with GreenHunter Water. See "Note 2 - Divestitures and Discontinued Operations".

Mr. Evans, the Company's Chairman and Chief Executive Officer, was a 4.0% limited partner in TransTex Gas Services, LP ("TransTex Gas"). This limited partnership received total consideration of 622,641 Class A Common Units of Eureka Hunter Holdings and cash of $46.0 million upon the Company's acquisition of certain of its assets. This includes units issued in accordance with the agreement of Eureka Hunter Holdings and TransTex Gas to provide the limited partners of TransTex Gas the opportunity to purchase additional Class A Common Units of Eureka Hunter Holdings in lieu of a portion of the cash distribution they would otherwise receive. Certain limited partners purchased such units, including Mr. Evans, who purchased 27,641 Class A Common Units of Eureka Hunter Holdings for $553,000 which was the same purchase price equivalent offered to all TransTex investors.

On February 17, 2012, the Company sold its wholly-owned subsidiary, Hunter Disposal, LLC, to GreenHunter Water, LLC, a wholly-owned subsidiary of GreenHunter Resources, Inc. The terms and conditions of the equity purchase agreement between the parties were approved by an independent special committee of the Board of the Company. Total consideration for the sale was approximately $9.3 million comprised of $2.2 million in cash, 1,846,722 shares of GreenHunter Resources, Inc. restricted common stock valued at $2.6 million based on a closing price of $1.79 per share, discounted for restrictions, 88,000 shares of GreenHunter Resources, Inc. 10% Series C Cumulative Preferred Stock with a fair value of $1.9 million, and a $2.2 million convertible promissory note which is convertible at the option of the Company into 880,000 shares of GreenHunter Resources, Inc. common stock based on the conversion price of $2.50 per share. The Company recognized a gain of on the sale of $2.4 million, in gain on disposal of discontinued operations, net of tax. The Company has recognized an embedded derivative asset resulting from the conversion option on the convertible promissory note with fair market value of $79,000 at December 31, 2013 and $264,000 at December 31, 2012. See "Note 3 - Fair Value of Financial Instruments". The cash proceeds from the sale were adjusted downward to $783,000 for changes in working capital and certain fees to reflect the effective date of the sale of December 31, 2012. The Company has recorded interest income as a result of the note receivable from GreenHunter Resources, Inc., in the amount of $204,760 for the year ended December 31, 2013. As a result of this transaction, the Company has an investment in GreenHunter Resources, Inc. that is included in derivatives and other long term assets and recorded under the equity method. The loss related to this investment was $0.7 million for the year ended December 31, 2013. In connection with the sale, Triad Hunter entered into agreements with Hunter Disposal, LLC and GreenHunter Water, LLC for wastewater hauling and disposal capacity in Kentucky, Ohio, and West Virginia and a five-year tank rental agreement with GreenHunter Water, LLC.

NOTE 17 - COMMITMENTS AND CONTINGENCIES

Legal Proceedings

On April 23, 2013, Anthony Rosian, individually and on behalf of all other persons similarly situated, filed a class action complaint in the United States District Court, Southern District of New York, against the Company and certain of its officers, two of whom also serve as directors. On April 24, 2013, Horace Carvalho, individually and on behalf of all other persons similarly situated, filed a similar class action complaint in the United States District Court, Southern District of Texas, against the Company and certain of its officers, two of whom also serve as directors. Several substantially similar putative class actions have been filed in the Southern District of New York and in the Southern District of Texas. All such cases are collectively referred to as the Securities Cases. The cases filed in the Southern District of Texas have since been dismissed, but the cases in the Southern District of New York have been consolidated and remain ongoing. The plaintiffs in the Securities Cases have filed a consolidated amended complaint alleging that the Company made certain false or misleading statements in its filings with the SEC, including statements related to the Company's internal and financial controls, the calculation of non-cash share-based compensation expense, the late filing of the Company's 2012 Form 10-K, the dismissal of Magnum Hunter's previous independent registered accounting firm, the Company’s characterization of the auditors’ position with respect to the dismissal, and other matters identified in the Company's April 16, 2013 Form 8-K, as amended. The consolidated amended complaint asserts claims under Sections 10(b) and 20 of the Securities Exchange Act based on alleged false statements made regarding these issues throughout the alleged class period, as well as claims under Sections 11, 12, and 15 of the Securities Act based on alleged false statements and omissions regarding the Company’s internal controls made in connection with the 35,000,000-share secondary offering that Magnum Hunter completed on May 14, 2012. The consolidated amended complaint demands that the defendants pay unspecified damages to the class action plaintiffs, including damages allegedly caused by the decline in the Company's stock price between February 22, 2013 and April 22, 2013. The Company and the individual defendants intend to vigorously defend the Securities Cases. It is possible that additional investor lawsuits could be filed over these events.

On May 10, 2013, Steven Handshu filed a shareholder derivative suit in the 151st Judicial District Court of Harris County, Texas on behalf of the Company against the Company's directors and senior officers (the “Handshu Action”). On June 6, 2013, Zachariah

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Hanft filed another shareholder derivative suit in the Southern District of New York on behalf of the Company against the Company's directors and senior officers (the “Hanft Action”). On June 18, 2013, Mark Respler filed another shareholder derivative suit in the District of Delaware on behalf of the Company against the Company's directors and senior officers (the “Respler Action”). On June 27, 2013, Timothy Bassett filed another shareholder derivative suit in the Southern District of Texas on behalf of the Company against the Company's directors and senior officers. On September 16, 2013, Joseph Vitellone was substituted as plaintiff in the action filed by Mr. Bassett (the “Vitellone Action”). These suits are collectively referred to as the Derivative Cases. The Derivative Cases assert that the individual defendants unjustly enriched themselves and breached their fiduciary duties to the Company by publishing allegedly false and misleading statements to the Company's investors regarding the Company's business and financial position and results, and allegedly failing to maintain adequate internal controls. The complaints demand that the defendants pay unspecified damages to the Company, including damages allegedly sustained by the Company as a result of the alleged breaches of fiduciary duties by the defendants, as well as disgorgement of profits and benefits obtained by the defendants, and reasonable attorneys', accountants' and experts' fees and costs to the plaintiff. On December 13, 2013, the Handshu Action was dismissed for want of prosecution. On December 20, 2013, the United States District Court for the Southern District of Texas granted the Company’s motion to dismiss the Vitellone Action and entered a final judgment dismissing the case in its entirety. The court held that the plaintiff failed to allege particularized facts that would excuse them from making pre-suit demand on the Company’s Board of Directors as required by Delaware law. On January 21, 2014, the Hanft Action was dismissed with prejudice after the plaintiff in that action filed a voluntary motion for dismissal. On February 18, 2014, the District of Delaware granted the Company’s motion to dismiss the Respler Action on collateral estoppel grounds and closed the case. Accordingly, no shareholder derivative cases are currently pending against the Company’s officers and directors. It is possible, however, that additional shareholder derivative suits could be filed over these events

In addition, the Company has received several demand letters from shareholders seeking books and records relating to the allegations in the Securities Cases and the Derivative Cases under Section 220 of the Delaware General Corporation Law. On September 17, 2013, Anthony Scavo, who is one of the shareholders that made a demand, filed a books and records action in the Delaware Court of Chancery pursuant to Section 220 of the Delaware General Corporation Law (the “Scavo Action”). The Scavo Action seeks various books and records relating to the claims in the Securities Cases and the Derivative Cases, as well as costs and attorneys’ fees. The Company has filed an answer in the Scavo Action. It is possible that additional similar actions may be filed and that similar shareholder demands could be made.

The Company also received an April 26, 2013 letter from the SEC stating that the SEC's Division of Enforcement was conducting an inquiry regarding the Company's internal controls, change in outside auditors and public statements to investors and asking the Company to preserve documents relating to these matters. The Company is complying with this request. On December 30, 2013, the Company received a document subpoena relating to the issues identified in the April 26, 2013 letter. The Company is producing documents in response to the subpoena.

Any potential liability from these claims cannot currently be estimated.

Twin Hickory Matter

On April 11, 2013, a flash fire occurred at Eureka Hunter Pipeline’s Twin Hickory site located in Tyler County, West Virginia. The incident occurred during a pigging operation at a natural gas receiving station. Two employees of third-party contractors received fatal injuries. Another employee of a third-party contractor was injured. In mid-February 2014, the estate of one of the deceased third-party contractor employees sued Eureka Hunter Pipeline and certain other parties in Karen S. Phipps v. Eureka Hunter Pipeline, LLC et al., Civil Action No. 14-C-41, in the Circuit Court of Ohio County, West Virginia. The plaintiff alleges that Eureka Hunter Pipeline and the other defendants engaged in certain negligent and reckless conduct which resulted in the wrongful death of the third-party contractor employee. The plaintiff has demanded judgment for an unspecified amount of compensatory, general and punitive damages. A pre-suit settlement demand has also been received from another potential claimant. Investigation regarding the incident is ongoing. It is not possible to predict at this juncture the extent to which, if at all, Eureka Hunter Pipeline or any related entities will incur liability or damages because of this incident. However, we believe our insurance coverage will be sufficient to cover any losses or liabilities we may incur as a result of this incident.

Agreement to Purchase Utica Shale Acreage

On August 12, 2013, Triad Hunter entered into an asset purchase agreement, with MNW. MNW is an Ohio limited liability company that represents an informal association of various land owners, lessees and sub-lessees of mineral acreage who own or have rights in mineral acreage located in Monroe, Noble and/or Washington Counties, Ohio. Pursuant to the purchase agreement, Triad Hunter has agreed to acquire from MNW up to 32,000 net mineral acres, including currently leased and subleased acreage, located in such counties, over the next 10 months or possibly longer, subject to certain conditions. On October 7, 2013, Triad Hunter purchased 1,156.14 net leasehold acres for $4.9 million from MNW. On October 31, 2013, Triad Hunter purchased an additional 2,050.40 net

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leasehold acres for $8.7 million from MNW. On December 17, 2013, Triad Hunter purchased an additional 2,837.64 net leasehold acres for $10.9 million from MNW.

Payable on Sale of Partnership

On September 26, 2008, the Company sold its 5.33% limited partner interest in Hall-Houston Exploration II, L.P. pursuant to a Partnership Interest Purchase Agreement dated September 26, 2008, as amended on September 29, 2008. The interest was purchased by a non-affiliated partnership for a cash consideration of $8.0 million and the purchaser’s assumption of the first $1.4 million of capital calls subsequent to September 26, 2008. The Company agreed to reimburse the purchaser for up to $754,255 of capital calls in excess of the first $1.4 million. The Company’s net gain on the sale of the asset is subject to future upward adjustment to the extent that some or all of the $754,255 is not called. The liability as of December 31, 2013 and 2012 was $640,695.

Operational Contingencies

The exploration, development and production of oil and gas assets, the operations of oil and natural gas gathering systems, and the performance of oil field services are subject to various federal, state, local and foreign laws and regulations designed to protect the environment. Compliance with these regulations is part of the Company's day-to-day operating procedures. Infrequently, accidental discharge of such materials as oil, natural gas or drilling fluids can occur and such accidents can require material expenditures to correct. The Company maintains various levels and types of insurance which it believes to be appropriate to limit its financial exposure. The Company is unaware of any material capital expenditures required for environmental control during the year ending December 31, 2014.

Operating Leases

As of December 31, 2013, office space rentals with terms of 12 months or greater include office spaces in Houston, Texas, at a monthly cost of $33,000, office spaces in Grapevine, Texas, with monthly payments of approximately $4,800, and Williston Hunter subsidiaries office spaces in Denver, Colorado that have monthly payments of $5,800.

Future minimum lease commitments under noncancellable operating leases at December 31, 2013, are as follows (in thousands):



2014	$	504
2015	$	457
2016	$	239
2017	$	121
2018	$	127
Thereafter	$	53

Drilling Rig Purchase

On May 7, 2013, the Company, through its wholly-owned subsidiary, Alpha Hunter Drilling, LLC, completed the purchase of a new drilling rig intended for use in the Utica and Marcellus Shale formations located in southeastern Ohio and western West Virginia. Costs to acquire and install the rig and components were $15.3 million as of December 31, 2013 .

Gas Gathering and Processing Agreements

On December 14, 2011, the Company entered into a 120 -month gas transportation contract. The contract became effective on August 1, 2012. The Company's remaining liability under the contract was approximately $21.9 million as of December 31, 2013. On June 27, 2012, Eureka Hunter Pipeline entered into 36-month gas compression contract. The contract became effective on October 1, 2012. The Company's remaining liability under the contract was $3.2 million as of December 31, 2013. With the Virco Acquisition, Triad Hunter assumed a 120-month gas transportation contract. The Company's remaining liability under the contract was $3.5 million as of December 31, 2013.

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Future minimum gathering, processing, and transportation commitments at December 31, 2013, are as follows (in thousands):



2014	$	4,332
2015	$	4,319
2016	$	3,373
2017	$	2,958
2018	$	2,947
Thereafter	$	10,722

Eureka Hunter Holdings Operating Agreement

Pursuant to the Eureka Hunter Holdings operating agreement, the number and composition of the board of directors of Eureka Hunter Holdings may change over time based on Ridgeline’s percentage ownership interest in Eureka Hunter Holdings (after taking into account any additional purchases of preferred units) or the failure of Eureka Hunter Holdings to satisfy certain performance goals by the third anniversary of the closing of the initial Ridgeline investment (or as of any anniversary after such date) or under certain other circumstances. The board of directors of Eureka Hunter Holdings is currently composed of a majority of members appointed by Magnum Hunter. Subject to the rights described above, the board of directors of Eureka Hunter Holdings may in the future be composed of an equal number of directors appointed by Magnum Hunter and Ridgeline or, in certain cases, of a majority of directors appointed by Ridgeline.

If a change of control of Magnum Hunter occurs at any time prior to a qualified public offering (as defined in the Eureka Hunter Holdings operating agreement) of Eureka Hunter Holdings, Ridgeline will have the right under the terms of the operating agreement to purchase sufficient additional preferred units in Eureka Hunter Holdings so that it holds up to 51.0% of the equity ownership of Eureka Hunter Holdings.

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NOTE 18 - CONDENSED CONSOLIDATED GUARANTOR FINANCIAL STATEMENTS

Debt Securities Under Universal Shelf Registration Statement

Certain of the Company’s 100% owned subsidiaries, Shale Hunter, LLC, Triad Hunter, LLC, NGAS Hunter, LLC, Magnum Hunter Production, Inc., Williston Hunter, Inc., Williston Hunter ND, LLC, and Bakken Hunter, LLC (collectively, “Guarantor Subsidiaries”), have fully and unconditionally guaranteed the obligations of the Company under any debt securities that it may issue under a universal shelf registration statement on Form S-3, on a joint and several basis.

These condensed consolidating guarantor financial statements have been retrospectively revised to reflect Eagle Ford Hunter as a non-guarantor as the subsidiary was no longer a guarantor upon the closing of the sale on April 24, 2013. See "Note 2 - Divestitures and Discontinued Operations".

Condensed consolidating financial information for Magnum Hunter Resources Corporation, the Guarantor Subsidiaries and the other subsidiaries of the Company (the “Non Guarantor Subsidiaries”) as of December 31, 2013 and 2012 and for the years ended December 31, 2013, 2012, and 2011, was as follows:

Magnum Hunter Resources Corporation and Subsidiaries

Condensed Consolidating Balance Sheets

(in thousands)



	As of December 31, 2013
	Magnum Hunter Resources Corporation		Guarantor Subsidiaries		Non Guarantor Subsidiaries		Eliminations			Magnum Hunter Resources Corporation Consolidated
ASSETS
Current assets	$	53,161	$	28,825	$	42,112	$	(3,372	)	$	120,726
Intercompany accounts receivable	965,138		—		—		(965,138		)	—
Property and equipment (using successful efforts accounting)	7,214		1,124,637		382,228		—			1,514,079
Investment in subsidiaries	372,236		102,314		—		(474,550		)	—
Other assets	17,308		100,327		104,211		—			221,846
Total Assets	$	1,415,057	$	1,356,103	$	528,551	$	(1,443,060	)	$	1,856,651
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities	$	54,826	$	86,115	$	46,334	$	(3,410	)	$	183,865
Intercompany accounts payable	—		896,242		68,861		(965,103		)	—
Long-term liabilities	818,651		23,115		143,615		—			985,381
Redeemable preferred stock	100,000		—		136,675		—			236,675
Shareholders' equity	441,580		350,631		133,066		(474,547		)	450,730
Total Liabilities and Shareholders' Equity	$	1,415,057	$	1,356,103	$	528,551	$	(1,443,060	)	$	1,856,651

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Magnum Hunter Resources Corporation and Subsidiaries

Condensed Consolidating Balance Sheets

(in thousands)



	As of December 31, 2012
	Magnum Hunter Resources Corporation		Guarantor Subsidiaries		Non Guarantor Subsidiaries		Eliminations			Magnum Hunter Resources Corporation Consolidated
ASSETS
Current assets	$	63,167	$	48,320	$	124,041	$	(31,209	)	$	204,319
Intercompany accounts receivable	803,834		—		—		(803,834		)	—
Property and equipment (using successful efforts accounting)	9,596		1,148,714		766,103		—			1,924,413
Investment in subsidiaries	763,856		101,342		102,354		(967,552		)	—
Other assets	20,849		5,341		43,710		—			69,900
Total Assets	$	1,661,302	$	1,303,717	$	1,036,208	$	(1,802,595	)	$	2,198,632
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities	$	28,503	$	109,536	$	135,994	$	(30,377	)	$	243,656
Intercompany accounts payable	—		611,932		191,902		(803,834		)	—
Long-term liabilities	831,286		83,192		127,968		—			1,042,446
Redeemable preferred stock	100,000		—		100,878		—			200,878
Shareholders' equity	701,513		499,057		479,466		(968,384		)	711,652
Total Liabilities and Shareholders' Equity	$	1,661,302	$	1,303,717	$	1,036,208	$	(1,802,595	)	$	2,198,632

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Magnum Hunter Resources Corporation and Subsidiaries

Condensed Consolidating Statements of Operations

(in thousands)



	For the Year Ended December 31, 2013
	Magnum Hunter Resources Corporation			Guarantor Subsidiaries			Non Guarantor Subsidiaries ⁽¹⁾			⁽¹⁾ Eliminations			Magnum Hunter Resources Corporation Consolidated
Revenues	$	2,629		$	187,095		$	95,286		$	(4,599	)	$	280,411
Expenses	112,754			326,355			125,786			(10,135		)	554,760
Loss from continuing operations before equity in net income of subsidiaries	(110,125		)	(139,260		)	(30,500		)	5,536			(274,349		)
Equity in net income of subsidiaries	(298,775		)	(424		)	—			299,199			—
Loss from continuing operations before income tax	(408,900		)	(139,684		)	(30,500		)	304,735			(274,349		)
Income tax benefit	28,989			41,315			(7		)	—			70,297
Loss from continuing operations	(379,911		)	(98,369		)	(30,507		)	304,735			(204,052		)
Income from discontinued operations, net of tax	(7,813		)	13,101			(78,025		)	1,606			(71,131		)
Gain on disposal of discontinued operations, net of tax	144,378			(18,507		)	(66,707		)	(7,145		)	52,019
Net income (loss)	(243,346		)	(103,775		)	(175,239		)	299,196			(223,164		)
Net loss attributable to non-controlling interest	—			—			—			988			988
Net loss attributable to Magnum Hunter Resources Corporation	(243,346		)	(103,775		)	(175,239		)	300,184			(222,176		)
Dividends on preferred stock	(35,464		)	—			(21,241		)	—			(56,705		)
Net income (loss) attributable to common shareholders	$	(278,810	)	$	(103,775	)	$	(196,480	)	$	300,184		$	(278,881	)



	For the Year Ended December 31, 2012
	Magnum Hunter Resources Corporation			Guarantor Subsidiaries			Non Guarantor Subsidiaries ⁽¹⁾			⁽¹⁾ Eliminations			Magnum Hunter Resources Corporation Consolidated
Revenues	$	729		$	103,605		$	32,054		$	3,968		$	140,356
Expenses	54,047			159,603			49,597			16,077			279,324
Loss from continuing operations before equity in net income of subsidiaries	(53,318		)	(55,998		)	(17,543		)	(12,109		)	(138,968		)
Equity in net income of subsidiaries	(97,191		)	458			(23,362		)	120,095			—
Loss from continuing operations before income tax	(150,509		)	(55,540		)	(40,905		)	107,986			(138,968		)
Income tax benefit	5,937			13,375			—			—			19,312
Loss from continuing operations	(144,572		)	(42,165		)	(40,905		)	107,986			(119,656		)
Income from discontinued operations, net of tax	—			(11,036		)	(18,695		)	10,257			(19,474		)
Gain on disposal of discontinued operations, net of tax	—			2,409			—			—			2,409
Net income (loss)	(144,572		)	(50,792		)	(59,600		)	118,243			(136,721		)
Net income attributable to non-controlling interest	—			—			—			4,013			4,013
Net loss attributable to Magnum Hunter Resources Corporation	(144,572		)	(50,792		)	(59,600		)	122,256			(132,708		)
Dividends on preferred stock	(22,842		)	—			(11,864		)	—			(34,706		)
Net income (loss) attributable to common shareholders	$	(167,414	)	$	(50,792	)	$	(71,464	)	$	122,256		$	(167,414	)

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Magnum Hunter Resources Corporation and Subsidiaries

Condensed Consolidating Statements of Operations

(in thousands)



	For the Year Ended December 31, 2011
	Magnum Hunter Resources Corporation			Guarantor Subsidiaries			Non Guarantor Subsidiaries ⁽¹⁾			⁽¹⁾Eliminations			Magnum Hunter Resources Corporation Consolidated
Revenues	$	1,071		$	45,119		$	15,329		$	4,936		$	66,455
Expenses	68,772			39,226			16,949			1,184			126,131
Loss from continuing operations before equity in net income of subsidiaries	(67,701		)	5,893			(1,620		)	3,752			(59,676		)
Equity in net income of subsidiaries	(5,208		)	(2,196		)	(939		)	8,343			—
Loss from continuing operations before income tax	(72,909		)	3,697			(2,559		)	12,095			(59,676		)
Income tax benefit	—			3,727			(351		)	(514		)	2,862
Loss from continuing operations	(72,909		)	7,424			(2,910		)	11,581			(56,814		)
Income from discontinued operations, net of tax	—			(30,374		)	14,014			(3,238		)	(19,598		)
Gain on disposal of discontinued operations, net of tax	—			—			—			—			—
Net income (loss)	(72,909		)	(22,950		)	11,104			8,343			(76,412		)
Net income attributable to non-controlling interest	—			—			—			(249		)	(249		)
Net loss attributable to Magnum Hunter Resources Corporation	(72,909		)	(22,950		)	11,104			8,094			(76,661		)
Dividends on preferred stock	(14,007		)	—			—			—			(14,007		)
Net income (loss) attributable to common shareholders	$	(86,916	)	$	(22,950	)	$	11,104		$	8,094		$	(90,668	)

^{_______________________}

⁽¹⁾ PRC Williston, LLC has been presented as a discontinued operation on a stand alone basis. Elimination entries have been recorded to eliminate discontinued operations treatment on a consolidated basis.

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Magnum Hunter Resources Corporation and Subsidiaries

Condensed Consolidating Statements of Comprehensive Income (Loss)

(in thousands)



	For the Year Ended December 31, 2013
	Magnum Hunter Resources Corporation			Guarantor Subsidiaries			Non Guarantor Subsidiaries			Eliminations		Magnum Hunter Resources Corporation Consolidated
Net income (loss)	$	(243,346	)	$	(103,775	)	$	(175,239	)	$	299,196	$	(223,164	)
Foreign currency translation loss	—			—			(10,928		)	—		(10,928		)
Unrealized gain (loss) on available for sale securities	8,262			(84		)	—			—		8,178
Amounts reclassified from accumulated other comprehensive income upon sale of available for sale securities	(8,262		)	—			—			—		(8,262		)
Comprehensive income (loss)	(243,346		)	(103,859		)	(186,167		)	299,196		(234,176		)
Comprehensive income loss attributable to non-controlling interest	—			—			—			988		988
Comprehensive income (loss) attributable to Magnum Hunter Resources Corporation	$	(243,346	)	$	(103,859	)	$	(186,167	)	$	300,184	$	(233,188	)



	For the Year Ended December 31, 2012
	Magnum Hunter Resources Corporation			Guarantor Subsidiaries			Non Guarantor Subsidiaries			Eliminations		Magnum Hunter Resources Corporation Consolidated
Net income (loss)	$	(144,572	)	$	(50,792	)	$	(59,600	)	$	118,243	$	(136,721	)
Foreign currency translation loss	—			—			3,883			—		3,883
Unrealized gain (loss) on available for sale securities	—			(309		)	—			—		(309		)
Comprehensive income (loss)	(144,572		)	(51,101		)	(55,717		)	118,243		(133,147		)
Comprehensive (income) loss attributable to non-controlling interest	—			—			—			4,013		4,013
Comprehensive income (loss) attributable to Magnum Hunter Resources Corporation	$	(144,572	)	$	(51,101	)	$	(55,717	)	$	122,256	$	(129,134	)



	For the Year Ended December 31, 2011
	Magnum Hunter Resources Corporation			Guarantor Subsidiaries			Non Guarantor Subsidiaries			Eliminations			Magnum Hunter Resources Corporation Consolidated
Net income (loss)	$	(72,909	)	$	(22,950	)	$	11,104		$	8,343		$	(76,412	)
Foreign currency translation loss	—			—			(12,477		)	—			(12,477		)
Unrealized gain (loss) on available for sale securities	—			14			—			—			14
Comprehensive income (loss)	(72,909		)	(22,936		)	(1,373		)	8,343			(88,875		)
Comprehensive (income) loss attributable to non-controlling interest	—			—			—			(249		)	(249		)
Comprehensive income (loss) attributable to Magnum Hunter Resources Corporation	$	(72,909	)	$	(22,936	)	$	(1,373	)	$	8,094		$	(89,124	)

F-69

Magnum Hunter Resources Corporation and Subsidiaries

Condensed Consolidating Statements of Cash Flows

(in thousands)



	For the Year Ended December 31, 2013
	Magnum Hunter Resources Corporation			Guarantor Subsidiaries			Non Guarantor Subsidiaries			Eliminations		Magnum Hunter Resources Corporation Consolidated
Cash flow from operating activities	$	(371,351	)	$	376,129		$	106,933		$	—	$	111,711
Cash flow from investing activities	422,303			(387,660		)	(162,503		)	—		(127,860		)
Cash flow from financing activities	(29,929		)	(946		)	31,531			—		656
Effect of exchange rate changes on cash	—			—			(417		)	—		(417		)
Net increase (decrease) in cash	21,023			(12,477		)	(24,456		)	—		(15,910		)
Cash at beginning of period	26,872			(4,462		)	35,213			—		57,623
Cash at end of period	$	47,895		$	(16,939	)	$	10,757		$	—	$	41,713



	For the Year Ended December 31, 2012
	Magnum Hunter Resources Corporation			Guarantor Subsidiaries			Non Guarantor Subsidiaries			Eliminations		Magnum Hunter Resources Corporation Consolidated
Cash flow from operating activities	$	(458,921	)	$	275,914		$	241,018		$	—	$	58,011
Cash flow from investing activities	(364,045		)	(277,965		)	(367,197		)	—		(1,009,207		)
Cash flow from financing activities	831,080			(1,966		)	167,328			—		996,442
Effect of exchange rate changes on cash	—			—			(2,474		)	—		(2,474		)
Net increase (decrease) in cash	8,114			(4,017		)	38,675			—		42,772
Cash at beginning of period	18,758			(445		)	(3,462		)	—		14,851
Cash at end of period	$	26,872		$	(4,462	)	$	35,213		$	—	$	57,623



	For the Year Ended December 31, 2011
	Magnum Hunter Resources Corporation			Guarantor Subsidiaries			Non Guarantor Subsidiaries			Eliminations		Magnum Hunter Resources Corporation Consolidated
Cash flow from operating activities	$	(203,251	)	$	136,974		$	100,115		$	—	$	33,838
Cash flow from investing activities	(90,464		)	(136,489		)	(134,762		)	—		(361,715		)
Cash flow from financing activities	310,917			(310		)	31,586			—		342,193
Effect of exchange rate changes on cash	—			—			(19		)	—		(19		)
Net increase (decrease) in cash	17,202			175			(3,080		)	—		14,297
Cash at beginning of period	1,556			(620		)	(382		)	—		554
Cash at end of period	$	18,758		$	(445	)	$	(3,462	)	$	—	$	14,851

F-70

Senior Notes

Certain of the Company’s subsidiaries, including Alpha Hunter Drilling, LLC, Bakken Hunter, LLC, Shale Hunter, LLC, Hunter Aviation, LLC, Hunter Real Estate, LLC, Magnum Hunter Marketing, LLC, Magnum Hunter Production, Inc., Magnum Hunter Resources, GP, LLC, Magnum Hunter Resources, LP, NGAS Gathering, LLC, NGAS Hunter, LLC, PRC Williston, LLC, Triad Hunter, LLC, Williston Hunter, Inc., Williston Hunter ND, LLC, and Viking International Resources, Co., Inc. (collectively, "Guarantor Subsidiaries"), jointly and severally guarantee on a senior unsecured basis, the obligations of the Company under all the Senior Notes issued under the indenture entered into by the Company on May 16, 2012, as supplemented.

These condensed consolidating guarantor financial statements have been revised to reflect Eagle Ford Hunter as a non-guarantor as the subsidiary was no longer a guarantor upon the closing of the sale on April 24,2013. See "Note 2 - Divestitures and Discontinued Operations".

Condensed consolidating financial information for Magnum Hunter Resources Corporation , the Guarantor Subsidiaries and the other subsidiaries of the Company (the "Non Guarantor Subsidiaries") as of December 31, 2013 and 2012 and for the years ended December 31, 2013, 2012, and 2011 was as follows:

Magnum Hunter Resources Corporation and Subsidiaries

Condensed Consolidating Balance Sheets

(in thousands)



	As of December 31, 2013
	Magnum Hunter Resources Corporation		PRC Williston, LLC			100% Owned Guarantor Subsidiaries		Non Guarantor Subsidiaries			Eliminations			Magnum Hunter Resources Corporation Consolidated
ASSETS
Current assets	$	53,161	$	6,013		$	43,841	$	21,083		$	(3,372	)	$	120,726
Intercompany accounts receivable	965,138		—			—		—			(965,138		)	—
Property and equipment (using successful efforts accounting)	7,214		—			1,272,027		234,838			—			1,514,079
Investment in subsidiaries	372,236		—			102,314		—			(474,550		)	—
Other assets	17,308		—			100,894		103,644			—			221,846
Total Assets	$	1,415,057	$	6,013		$	1,519,076	$	359,565		$	(1,443,060	)	$	1,856,651

LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities	$	54,826	$	2,035		$	97,520	$	32,894		$	(3,410	)	$	183,865
Intercompany accounts payable	—		45,661			921,237		(1,795		)	(965,103		)	—
Long-term liabilities	818,651		—			39,067		127,663			—			985,381
Redeemable preferred stock	100,000		—			—		136,675			—			236,675
Shareholders' equity (deficit)	441,580		(41,683		)	461,252		64,128			(474,547		)	450,730
Total Liabilities and Shareholders' Equity	$	1,415,057	$	6,013		$	1,519,076	$	359,565		$	(1,443,060	)	$	1,856,651

F-71

Magnum Hunter Resources Corporation and Subsidiaries

Condensed Consolidating Balance Sheets

(in thousands)



	As of December 31, 2012
	Magnum Hunter Resources Corporation		PRC Williston, LLC			100% Owned Guarantor Subsidiaries		Non Guarantor Subsidiaries		Eliminations			Magnum Hunter Resources Corporation Consolidated
ASSETS
Current assets	$	63,167	$	703		$	60,552	$	111,126	$	(31,229	)	$	204,319
Intercompany accounts receivable	803,834		—			—		—		(803,834		)	—
Property and equipment (using successful efforts accounting)	9,596		18,257			1,276,467		620,093		—			1,924,413
Investment in subsidiaries	763,856		—			101,341		102,354		(967,551		)	—
Other assets	20,849		—			5,451		43,600		—			69,900
Total Assets	$	1,661,302	$	18,960		$	1,443,811	$	877,173	$	(1,802,614	)	$	2,198,632

LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities	$	28,503	$	2,291		$	117,511	$	125,727	$	(30,376	)	$	243,656
Intercompany accounts payable	—		58,966			508,254		236,636		(803,856		)	—
Long-term liabilities	831,286		1,274			97,271		112,615		—			1,042,446
Redeemable preferred stock	100,000		—			—		100,878		—			200,878
Shareholders' equity (deficit)	701,513		(43,571		)	720,775		301,317		(968,382		)	711,652
Total Liabilities and Shareholders' Equity	$	1,661,302	$	18,960		$	1,443,811	$	877,173	$	(1,802,614	)	$	2,198,632

F-72

Magnum Hunter Resources Corporation and Subsidiaries

Condensed Consolidating Statements of Operations

(in thousands)



	For the Year Ended December 31, 2013
	Magnum Hunter Resources Corporation			PRC Williston, LLC ⁽¹⁾			100% Owned Guarantor Subsidiaries			Non Guarantor Subsidiaries			⁽¹⁾ Eliminations			Magnum Hunter Resources Corporation Consolidated
Revenues	$	2,629		$	—		$	254,209		$	28,172		$	(4,599	)	$	280,411
Expenses	112,754			3,583			394,328			54,231			(10,136		)	554,760
Loss from continuing operations before equity in net income of subsidiaries	(110,125		)	(3,583		)	(140,119		)	(26,059		)	5,537			(274,349		)
Equity in net income of subsidiaries	(298,775		)	—			(424		)	—			299,199			—
Loss from continuing operations before income tax	(408,900		)	(3,583		)	(140,543		)	(26,059		)	304,736			(274,349		)
Income tax benefit	28,989			—			41,305			3			—			70,297
Loss from continuing operations	(379,911		)	(3,583		)	(99,238		)	(26,056		)	304,736			(204,052		)
Income from discontinued operations, net of tax	(7,813		)	(1,674		)	13,085			(76,335		)	1,606			(71,131		)
Gain on disposal of discontinued operations, net of tax	144,378			7,145			(18,507		)	(73,852		)	(7,145		)	52,019
Net income (loss)	(243,346		)	1,888			(104,660		)	(176,243		)	299,197			(223,164		)
Net loss attributable to non-controlling interest	—			—			—			—			988			988
Net loss attributable to Magnum Hunter Resources Corporation	(243,346		)	1,888			(104,660		)	(176,243		)	300,185			(222,176		)
Dividends on preferred stock	(35,464		)	—			—			(21,241		)	—			(56,705		)
Net income (loss) attributable to common shareholders	$	(278,810	)	$	1,888		$	(104,660	)	$	(197,484	)	$	300,185		$	(278,881	)



	For the Year Ended December 31, 2012
	Magnum Hunter Resources Corporation			PRC Williston, LLC ⁽¹⁾			100% Owned Guarantor Subsidiaries			Non Guarantor Subsidiaries			⁽¹⁾ Eliminations			Magnum Hunter Resources Corporation Consolidated
Revenues	$	729		$	—		$	122,703		$	12,955		$	3,969		$	140,356
Expenses	54,047			3,289			177,489			9,929			34,570			279,324
Loss from continuing operations before equity in net income of subsidiaries	(53,318		)	(3,289		)	(54,786		)	3,026			(30,601		)	(138,968		)
Equity in net income of subsidiaries	(97,191		)	—			458			(23,362		)	120,095			—
Loss from continuing operations before income tax	(150,509		)	(3,289		)	(54,328		)	(20,336		)	89,494			(138,968		)
Income tax benefit	5,937			—			13,375						—			19,312
Loss from continuing operations	(144,572		)	(3,289		)	(40,953		)	(20,336		)	89,494			(119,656		)
Income from discontinued operations, net of tax	—			(11,602		)	(11,056		)	(8,418		)	11,602			(19,474		)
Gain on disposal of discontinued operations, net of tax	—			—			2,409			—			—			2,409
Net income (loss)	(144,572		)	(14,891		)	(49,600		)	(28,754		)	101,096			(136,721		)
Net income attributable to non-controlling interest	—			—			—			—			4,013			4,013
Net loss attributable to Magnum Hunter Resources Corporation	(144,572		)	(14,891		)	(49,600		)	(28,754		)	105,109			(132,708		)
Dividends on preferred stock	(22,842		)	—			—			(11,864		)	—			(34,706		)
Net income (loss) attributable to common shareholders	$	(167,414	)	$	(14,891	)	$	(49,600	)	$	(40,618	)	$	105,109		$	(167,414	)

F-73

Magnum Hunter Resources Corporation and Subsidiaries

Condensed Consolidating Statements of Operations

(in thousands)



	For the Year Ended December 31, 2011
	Magnum Hunter Resources Corporation			PRC Williston, LLC ⁽¹⁾			100% Owned Guarantor Subsidiaries			Non Guarantor Subsidiaries			⁽¹⁾ Eliminations			Magnum Hunter Resources Corporation Consolidated
Revenues	$	1,071		$	—		$	54,545		$	5,903		$	4,936		$	66,455
Expenses	68,772			4,715			48,788			7,677			(3,821		)	126,131
Loss from continuing operations before equity in net income of subsidiaries	(67,701		)	(4,715		)	5,757			(1,774		)	8,757			(59,676		)
Equity in net income of subsidiaries	(6,906		)	—			(2,196		)	(939		)	10,041			—
Loss from continuing operations before income tax	(74,607		)	(4,715		)	3,561			(2,713		)	18,798			(59,676		)
Income tax benefit	—			—			3,733			(357		)	(514		)	2,862
Loss from continuing operations	(74,607		)	(4,715		)	7,294			(3,070		)	18,284			(56,814		)
Income from discontinued operations, net of tax	—			1,698			(30,364		)	12,306			(3,238		)	(19,598		)
Gain on disposal of discontinued operations, net of tax	—			—			—			—			—			—
Net income (loss)	(74,607		)	(3,017		)	(23,070		)	9,236			15,046			(76,412		)
Net income attributable to non-controlling interest	—			—			—			—			(249		)	(249		)
Net loss attributable to Magnum Hunter Resources Corporation	(74,607		)	(3,017		)	(23,070		)	9,236			14,797			(76,661		)
Dividends on preferred stock	(14,007		)	—			—			—			—			(14,007		)
Net income (loss) attributable to common shareholders	$	(88,614	)	$	(3,017	)	$	(23,070	)	$	9,236		$	14,797		$	(90,668	)

_________________

F-74

Magnum Hunter Resources Corporation and Subsidiaries

Condensed Consolidating Statements of Comprehensive Income (Loss)

(in thousands)



	For the Year Ended December 31, 2013
	Magnum Hunter Resources Corporation			PRC Williston, LLC		100% Owned Guarantor Subsidiaries			Non Guarantor Subsidiaries			Eliminations		Magnum Hunter Resources Corporation Consolidated
Net income (loss)	$	(243,346	)	$	1,888	$	(104,660	)	$	(176,243	)	$	299,197	$	(223,164	)
Foreign currency translation loss	—			—		—			(10,928		)	—		(10,928		)
Unrealized gain (loss) on available for sale securities	8,262			—		(84		)	—			—		8,178
Amounts reclassified from accumulated other comprehensive income upon sale of available for sale securities	(8,262		)	—		—			—			—		(8,262		)
Comprehensive income (loss)	(243,346		)	1,888		(104,744		)	(187,171		)	299,197		(234,176		)
Comprehensive (income) loss attributable to non-controlling interest	—			—		—			—			988		988
Comprehensive income (loss) attributable to Magnum Hunter Resources Corporation	$	(243,346	)	$	1,888	$	(104,744	)	$	(187,171	)	$	300,185	$	(233,188	)



	For the Year Ended December 31, 2012
	Magnum Hunter Resources Corporation			PRC Williston, LLC			100% Owned Guarantor Subsidiaries			Non Guarantor Subsidiaries			Eliminations		Magnum Hunter Resources Corporation Consolidated
Net income (loss)	$	(144,572	)	$	(14,891	)	$	(49,600	)	$	(28,754	)	$	101,096	$	(136,721	)
Foreign currency translation loss	—			—			—			3,883			—		3,883
Unrealized gain (loss) on available for sale securities	—			—			(309		)	—			—		(309		)
Comprehensive income (loss)	(144,572		)	(14,891		)	(49,909		)	(24,871		)	101,096		(133,147		)
Comprehensive (income) loss attributable to non-controlling interest	—			—			—			—			4,013		4,013
Comprehensive income (loss) attributable to Magnum Hunter Resources Corporation	$	(144,572	)	$	(14,891	)	$	(49,909	)	$	(24,871	)	$	105,109	$	(129,134	)



	For the Year Ended December 31, 2011
	Magnum Hunter Resources Corporation			PRC Williston, LLC			100% Owned Guarantor Subsidiaries			Non Guarantor Subsidiaries			Eliminations			Magnum Hunter Resources Corporation Consolidated
Net income (loss)	$	(74,607	)	$	(3,017	)	$	(23,070	)	$	9,236		$	15,046		$	(76,412	)
Foreign currency translation loss	—			—			—			(12,477		)	—			(12,477		)
Unrealized gain (loss) on available for sale securities	—			—			14			—			—			14
Comprehensive income (loss)	(74,607		)	(3,017		)	(23,056		)	(3,241		)	15,046			(88,875		)
Comprehensive (income) loss attributable to non-controlling interest	—			—			—			—			(249		)	(249		)
Comprehensive income (loss) attributable to Magnum Hunter Resources Corporation	$	(74,607	)	$	(3,017	)	$	(23,056	)	$	(3,241	)	$	14,797		$	(89,124	)

F-75

Magnum Hunter Resources Corporation and Subsidiaries

Condensed Consolidating Statements of Cash Flows

(in thousands)



	For the Year Ended December 31, 2013
	Magnum Hunter Resources Corporation			PRC Williston, LLC			100% Owned Guarantor Subsidiaries			Non Guarantor Subsidiaries			Eliminations			Magnum Hunter Resources Corporation Consolidated
Cash flow from operating activities	$	(371,351	)	$	(1,932	)	$	397,213		$	101,085		$	(13,304	)	$	111,711
Cash flow from investing activities	422,303			15,236			(411,473		)	(153,926		)	—			(127,860		)
Cash flow from financing activities	(29,929		)	(13,304		)	796			29,789			13,304			656
Effect of exchange rate changes on cash	—			—			—			(417		)	—			(417		)
Net increase (decrease) in cash	21,023			—			(13,464		)	(23,469		)	—			(15,910		)
Cash at beginning of period	26,872			—			(4,187		)	34,938			—			57,623
Cash at end of period	$	47,895		$	—		$	(17,651	)	$	11,469		$	—		$	41,713



	For the Year Ended December 31, 2012
	Magnum Hunter Resources Corporation			PRC Williston, LLC			Guarantor Subsidiaries			Non Guarantor Subsidiaries			Eliminations			Magnum Hunter Resources Corporation Consolidated
Cash flow from operating activities	$	(458,921	)	$	1,256		$	281,782		$	235,104		$	(1,210	)	$	58,011
Cash flow from investing activities	(364,045		)	(49		)	(287,204		)	(357,912		)	3			(1,009,207		)
Cash flow from financing activities	831,080			(1,207		)	1,781			163,581			1,207			996,442
Effect of exchange rate changes on cash	—			—			—			(2,474		)	—			(2,474		)
Net increase (decrease) in cash	8,114			—			(3,641		)	38,299			—			42,772
Cash at beginning of period	18,758			—			(546		)	(3,361		)	—			14,851
Cash at end of period	$	26,872		$	—		$	(4,187	)	$	34,938		$	—		$	57,623

F-76

Magnum Hunter Resources Corporation and Subsidiaries

Condensed Consolidating Statements of Cash Flows

(in thousands)



	For the Year Ended December 31, 2011
	Magnum Hunter Resources Corporation			PRC Williston, LLC			100% Owned Guarantor Subsidiaries			Non Guarantor Subsidiaries			Eliminations			Magnum Hunter Resources Corporation Consolidated
Cash flow from operating activities	$	(203,251	)	$	(1,738	)	$	138,855		$	98,048		$	1,924		$	33,838
Cash flow from investing activities	(90,464		)	(175		)	(141,954		)	(129,111		)	(11		)	(361,715		)
Cash flow from financing activities	310,917			1,913			3,206			28,070			(1,913		)	342,193
Effect of exchange rate changes on cash	—			—			—			(19		)	—			(19		)
Net increase (decrease) in cash	17,202			—			107			(3,012		)	—			14,297
Cash at beginning of period	1,556			—			(653		)	(349		)	—			554
Cash at end of period	$	18,758		$	—		$	(546	)	$	(3,361	)	$	—		$	14,851

NOTE 19 - SUBSEQUENT EVENTS

Master Loan and Security Agreement

On January 21, 2014, Alpha Hunter Drilling, LLC entered into a Master Loan and Security Agreement with CIT Finance to borrow $5.6 million at an interest rate of 7.94% over a term of forty-eight months. The note is collateralized by field equipment, and the Company is a guarantor on the note.

Derivative Contracts

We entered into commodity derivative contracts subsequent to December 31, 2013, through the date of this report. Our objective for holding these commodity derivatives is to protect the operating revenues and cash flows related to a portion of our future natural gas and crude oil sales from the risk of significant declines in commodity prices, which helps insure our ability to fund our capital expenditure budget. We have not designated any of these commodity derivatives as hedges under ASC 815.

The table below is a summary of our commodity derivatives entered into subsequent to December 31, 2013 through the date of this report:



			Weighted Avg
Natural Gas	Period	MMBTU/day	Price per MMBTU
Swaps	Jan 2014 - Dec 2014	21,000	$4.27
	Jan 2015 - Dec 2015	20,000	$4.18

Ceilings purchased (call)	Jan 2014 - Dec 2014	6,000	$5.50

Common Stock Granted to Employees, Management and Board Members

On January 8, 2014, the Company granted 1,312,575 restricted shares of common stock to officers, executives, and employees of the Company. The shares vest over a 3-year period with 33% of the options vesting one year from the date of the grant. The Company also granted 123,798 restricted shares to the directors of the Company which vest 100% one year from the date of the grant.

Issuance of Series A Preferred Units of Eureka Hunter Holdings

Eureka Hunter Holdings has issued 97,492 Series A Preferred units with a redemption value of $1.9 million for dividends paid in kind subsequent to December 31, 2013.

F-77

Settlement Agreement with Seminole Energy Services

On January 10, 2014, the company and certain of its subsidiaries entered into an Omnibus Settlement Agreement and Release dated January 9, 2014 with Seminole Energy Services, LLC and certain of its affiliates (collectively, "Seminole"). In connection with and pursuant to the terms of the Settlement Agreement, the Company and Seminole have agreed to release and discharge each other from all claims and causes of action alleged in, arising from or related to certain legal proceedings and terminate, amend and enter into certain new, related agreements effective immediately prior to year-end on December 31, 2013 (the "New Agreements").

By entering into the New Agreements, the Company and Seminole have restructured their existing agreements. The Company obtained a reduction in gas gathering rates it will pay for natural gas gathered on the Stone Mountain Gathering System that the Company owns or controls. The Company and Seminole collectively agreed to construct an enhancement of the Rogersville Plant designed to recover less ethane and more propane from the natural gas processed at the Rogersville Plant and reduce and extend the Company's contractual horizontal well drilling obligations owed to Seminole. The Company and Seminole have also agreed to modify the natural gas processing rates the Company will pay for processing at the Rogersville Plant, the Company's allocation of natural gas liquids ("NGL") recovered from gas processed and the costs of blend stock necessary to blend with the NGL produced from the Rogersville Plant, and certain deductions to the NGL purchase price the Company will pay Seminole for the Company's NGL produced from the Rogersville Plant. Seminole sold to the Company Seminole's 50% interest in a natural gas gathering trunk line and treatment facility located in southwestern Muhlenberg County, Kentucky, which had previously been owned equally by Seminole and the Company.

As a result of the restructuring effected by the Settlement Agreement, the Company expects to realize operational savings, certain components of which savings would occur over time, depending on the implementation timing or completion of certain of the benefits provided to the Company.

Sale of Certain other Eagle Ford Shale Assets

On January 28, 2014, the Company and certain of its affiliates closed on the sale of certain of its oil and gas properties and related assets in the Eagle Ford Shale in South Texas to New Standard Energy Texas LLC (“NSE Texas”), a subsidiary of New Standard Energy Limited (“NSE”), an Australian Securities Exchange-listed Australian company.

The divested properties and assets consisted primarily of leasehold acreage in Atascosa County, Texas and working interests in five horizontal wells, four of which wells were operated by the Company (the “Eagle Ford Assets”). The effective date of the sale was December 1, 2013. As consideration for the Eagle Ford Assets, the Company received aggregate purchase price consideration of $15 million in cash (before taking into account customary purchase price adjustments) and 65,650,000 ordinary shares of NSE valued, for purposes of the calculation of the purchase price, at approximately $9.5 million. This represents approximately 17% of the total shares outstanding of NSE.

In connection with the closing of the sale, Shale Hunter, LLC, a subsidiary of the Company (“Shale Hunter”), and NSE Texas entered into a Transition Services Agreement (the “TSA”). The TSA provides that, during a specified transition period, Shale Hunter will provide NSE Texas with certain transitional services relating to the Eagle Ford Assets for a fee.

Upon and as a result of the closing of the sale of the Eagle Ford Assets on January 28, 2014, the borrowing base under the Company’s asset-based, senior secured revolving credit facility maturing April 13, 2016 was automatically reduced by $10 million to $232.5 million as of the closing pursuant to the terms of the Company’s Third Amended and Restated Credit Agreement, dated as of December 13, 2013, by and among the Company, as borrower, certain of its subsidiaries, as guarantors, Bank of Montreal, as administrative agent, the lenders party thereto and the agents party thereto.

F-78

PART III

Item 11. EXECUTIVE COMPENSATION

Director Compensation

Our Compensation Committee reviews, not less frequently than bi-annually, and recommends to our Board for approval, fees and other compensation and benefits for our non-employee directors. Also, our Compensation Committee frequently consults with Longnecker and Associates, or Longnecker, an independent compensation consultant, on the competitiveness of our executive compensation. Longnecker's most recent formal peer group review for the Compensation Committee on overall director compensation was performed in December 2013. Longnecker assists our Compensation Committee in evaluating the appropriateness of our non-employee directors' compensation program, including the mix of meeting fees and annual chairperson retainers, to ensure that the program compensates our non-employee directors for the level of responsibility the Board has assumed in today's corporate governance environment and to remain competitive relative to companies in our peer group.

The Company's non-employee directors' compensation program remained fundamentally unchanged in 2013. Fees for attending meetings of the Board and its committees were set at $1,500 per Board meeting and $1,000 per committee meeting (including standing and special committees). In 2013, all of our non-employee directors received a $45,000 annual retainer in addition to the fees described above. The chair of each committee also received an additional $10,000 annual retainer, and the lead independent director received an additional $15,000 annual retainer. Meeting fees and retainers are paid on a quarterly basis. Non-employee directors were also granted options as reflected in the table below.

Beginning in January, 2014, the $45,000 annual retainer described above was increased to $50,000, the $15,000 additional annual retainer for the lead independent director was increased to $30,000, and the annual retainer for the chair of the audit committee was increased from $10,000 to $15,000. Options have not been granted to non-employee directors in 2014. Instead, in January 2014, each non-employee director received restricted stock valued at approximately $150,000 on the date of grant. Subject to continued service as a director, the full restricted stock award vests one year from the date of grant or, if earlier, upon the death of the recipient or a change in control of the Company.

Each non-employee director may elect to receive his compensation, including meeting fees, committee chairperson fees and annual retainer, in cash or in shares of our common stock, or a combination thereof. Each director's election will remain in effect until a new election is made, and new elections may be made on an annual basis. As of the date of the filing of this amendment to our annual report on Form 10-K/A, all of our non-employee directors have elected to receive compensation in shares of common stock, with the exception of Mr. Duckworth, who has elected to receive 60% of his compensation in stock and 40% in cash.

The number of shares paid in lieu of cash compensation is based on the volume weighted average price of our common stock for the calendar quarter in which the meetings were held or the chairperson fee or annual retainer was accrued. Non-employee directors are also eligible to receive annual grants of shares of Magnum Hunter common stock, which may be restricted stock, under our Stock Incentive Plan.

The following table presents compensation earned by each non-employee member of our Board for 2013. Compensation information for Mr. Evans, a current director, and Mr. Ormand, a former director, is contained in the Summary Compensation Table below. Messrs. Evans and Ormand did not receive any compensation in their capacities as directors of the Company.

2013 Director Compensation Table



Name	Fees Paid in Cash		Option Awards ^{(1) (2)}		Fees Paid in Stock ⁽¹⁾		All Other Compensation ⁽³⁾		Total
J. Raleigh Bailes, Sr.	$	—	$	158,634	$	121,868	$	—	$	280,502
Brad Bynum ⁽⁴⁾	$	—	$	158,634	$	77,562	$	—	$	236,196
Victor G. Carrillo	$	—	$	158,634	$	116,692	$	—	$	275,326
Rocky L. Duckworth ⁽⁵⁾	$	7,603	$	—	$	11,842	$	—	$	19,445
Stephen C. Hurley	$	—	$	158,634	$	168,417	$	—	$	327,051
Joe L. McClaugherty	$	—	$	158,634	$	184,728	$	—	$	343,362
Steven A. Pfeifer ⁽⁴⁾	$	—	$	158,634	$	61,222	$	—	$	219,856
Jeff Swanson	$	—	$	158,634	$	112,670	$	—	$	271,304

________________________________

⁽¹⁾

Represents the aggregate grant date fair value, in accordance with Accounting Standards Codification 718, "Stock Compensation", referred to in this annual report as ASC 718 (except no assumptions for forfeitures were included), with respect to (a) shares of common stock (under the Fees Paid in Stock column), and (b) stock options (under the Option Awards column). See "Note 9 - Share-Based Compensation" in the notes to our consolidated financial statements included in our annual report on Form 10-K for information regarding the assumptions made in determining these values.

As of December 31, 2013, Messrs. Bailes, Carrillo, Duckworth, Hurley, McClaugherty, and Swanson did not hold any shares of unvested restricted stock. As of December 31, 2013, the aggregate number of outstanding option awards held by our current non-employee directors was: 175,000 for Mr. Bailes, 175,000 for Mr. Carrillo, none for Mr. Duckworth, 136,000 for Mr. Hurley, 140,000 for Mr. McClaugherty, and 175,000 for Mr. Swanson.


⁽²⁾	On January 17, 2013, Messrs. Bailes, Carrillo, Hurley, McClaugherty, and Swanson were each granted an option to purchase up to 60,000 shares of our common stock at an exercise price of $4.16 per share with a ten-year expiration date.


⁽³⁾	We reimburse the reasonable travel and accommodation expenses of directors to attend meetings and other corporate functions. In 2013, the incremental cost to the Company to provide these perquisites was less than $10,000 per director.


⁽⁴⁾	Messrs. Bynum and Pfeifer resigned from the Board on July 23, 2013.


⁽⁵⁾	Mr. Duckworth was elected to the Board on October 7, 2013.

Executive Compensation Discussion and Analysis

This compensation discussion and analysis provides information regarding our executive compensation program in 2013 for the following executive officers and former executive officer of the Company, collectively referred to as our Named Executive Officers, or NEOs:


•	Gary C. Evans, Chairman and Chief Executive Officer


•	Joseph C. Daches, Senior Vice President and Chief Financial Officer


•	Ronald D. Ormand, former Executive Vice President, Chief Financial Officer and Secretary


•	James W. Denny III, Executive Vice President and President, Appalachian Division


•	H.C. "Kip" Ferguson, Executive Vice President - Exploration


•	R. Glenn Dawson, Executive Vice President and President, Williston Basin Division

2011 Stockholder Advisory Vote on Executive Compensation

At our 2011 annual meeting of stockholders, we held our first advisory vote on executive compensation. Over 85% of the votes cast were in favor of the compensation of the NEOs. The Compensation Committee considered this favorable outcome and believed it conveyed our stockholders' support of the Compensation Committee's decisions and the existing executive compensation programs. The Compensation Committee continues to look for ways to attract and retain top executive talent whose interests are aligned with those of the Company's stockholders. At the 2014 annual meeting of stockholders, we will again hold an advisory vote to approve executive compensation, as a vote every three years was supported by the common stockholders in 2011 in accordance with the Company's recommendation. The Compensation Committee will continue to consider the results from the 2011 vote and future advisory votes, including the advisory vote at the 2014 annual meeting, on executive compensation.

Our Compensation Philosophy

The objective of the Company's executive compensation program is to enable us to recruit and retain highly qualified managerial talent by providing competitive levels of compensation in an increasingly competitive market for executive talent. We also seek to motivate our executives to achieve individual and business performance objectives by varying their compensation in accordance with the success of our business.

We believe compensation programs can drive the behavior of employees covered by the programs, and accordingly we seek to design our executive compensation program to align compensation with current and desired corporate performance and stockholder interests. Actual compensation in a given year will vary based on the Company's performance and on subjective appraisals of individual performance. In other words, actual compensation generally will reflect the Company's financial and operational performance.

We maintain competitive benefit programs for our employees, including our NEOs, with the objective of retaining their services. Our benefits reflect competitive practices at the time the benefit programs were implemented and, in some cases, reflect our desire to maintain similar benefits treatment for all employees in similar positions. To the extent possible, we structure these programs to deliver benefits in a manner that is tax efficient to both the recipient and the Company.

We seek to provide compensation that is competitive with the companies we believe are our peers and other likely competitors for executive talent. Competitive compensation is normally sufficient to attract executive talent to the Company. Competitive compensation also makes it less likely that executive talent will be lured away by higher compensation to perform a similar role with a similarly-sized competitor. We also believe that a significant portion of compensation for executives should be "at risk," meaning that the executives will receive a significant portion of their total compensation only to the extent the Company and the executive accomplish goals established by our Compensation Committee.

We frequently consult with Longnecker on the competitiveness of our executive compensation. In February 2013, Longnecker performed a formal peer group review on the compensation of our senior executives. That review looked at the following companies in our peer group:



Approach Resources Inc.	Gulfport Energy Corporation	Resolute Energy Corporation
Carrizo Oil & Gas, Inc.	Halcon Resources Corporation	Rex Energy Corporation
Comstock Resources, Inc.	Kodiak Oil & Gas Corp.	Rosetta Resources Inc.
EXCO Resources, Inc.	Northern Oil & Gas, Inc.	Swift Energy Company
Forest Oil Corporation	Oasis Petroleum Inc.
Goodrich Petroleum Corporation	PDC Energy, Inc.

We generally have targeted direct cash compensation (salary and bonus) at or around the 50th percentile of our peer group and long-term incentive compensation at or around the 75th percentile of our peer group, for a total compensation package that falls between the 50th and 75th percentiles of our peer group. We believe this approach best serves our objectives described above.

Base Salary

Base salary is the foundation of total compensation. Base salary recognizes the job being performed and the value of that job in the competitive market. Base salary must be sufficient to attract and retain the talent necessary for our continued success and provides an element of compensation that is not at risk in order to avoid fluctuations in compensation that could distract the executives from the performance of their responsibilities.

Adjustments to base salary primarily reflect either changes or responses to changes in market data or increased experience and individual contribution of the employee. Working with Longnecker, we noted in 2010 that our base salaries were, in many cases, significantly below market. We have instituted salary increases each year to ensure that our overall compensation remains competitive, but continue to place more emphasis on incentive compensation because of its link to the creation of stockholder value.

Short-Term Incentives

For 2012 and prior years, our short-term incentive compensation program provided our executive officers the opportunity to receive a cash bonus of up to 50% of base salary based on specified performance metrics and an additional merit bonus at the discretion of the Compensation Committee. For 2013, the Compensation Committee suspended the metrics-based component of our short-term incentive program that was utilized in prior years in favor of full discretion for the Compensation Committee in awarding bonuses. In light of the change in the Company's independent auditor in 2013 and related late filing of the Company's 2012 Form 10-K, the Compensation Committee determined that 2013 bonuses for senior management should be considered on a case-by-case basis. Importantly, the award of a bonus should not be seen as "locked in" because of the achievement of a performance metric if the bonus is not deserved given overall performance. However, the Compensation Committee determined that the performance metrics adopted for 2012 would be considered as part of its analysis of the discretionary award of bonuses.

For 2012, the performance metrics were tied to increases in average daily production, increases in total proved reserves, reductions in lifting costs, reductions in recurring cash general and administrative expenses and, in the case of the Chief Executive Officer, the Company’s stock price.

Our Compensation Committee awarded short-term incentives in the form of cash bonuses to certain employees, including our NEOs, in March, 2014, based on individual and Company performance in 2013. The Compensation Committee considered each NEO's contributions to the Company's financial and operational performance objectives, including the performance metrics described above. For each NEO, the Compensation Committee considered that:


•	the Company’s average daily production for the fourth quarter of 2013 increased by approximately 44% from the fourth quarter of 2012;


•	the Company’s total proved reserves at December 31, 2013 increased by approximately 23% from December 31, 2012, adjusted for the disposition of certain assets during 2013;


•	the Company’s lease operating expenses per Boe, or LOE/Boe, for the year ended December 31, 2013 increased by approximately 59% from the year ended December 31, 2012 and the increase related primarily to increased volume produced, increased percentage of production as NGL in the Appalachian Basis and higher Appalachian Basis gas transportation charges; and


•	the Company’s recurring cash general and administrative expenses per Boe for the fourth quarter of 2013 decreased by approximately 34% from the fourth quarter of 2012, but recurring cash general and administrative expenses per Boe for the year ended December 31, 2013 increased by approximately 11% from the year ended December 31, 2012.

For Mr. Evans, the Compensation Committee also considered the increase in the Company’s stock price during 2013, as well as his ultimate responsibility, as Chief Executive Officer, for the overall performance of the Company.

The cash bonus for Mr. Daches included a sign-on bonus of $150,000 paid when he joined the Company. The cash bonus for Mr. Ormand was a one-time separation payment.

For 2014, the Compensation Committee intends to reinstitute a metrics-based component to the short-term incentive program following review of the program with the Company's compensation consultant.

Long-Term Incentives

Our Stock Incentive Plan, in which each of our executive officers, including each of our NEOs, and certain other employees participate, is designed to reward participants for sustained improvements in the Company's financial performance and increases in the value of our common stock over an extended period. Long-term incentives are a key component of the Company's overall compensation structure.

The Compensation Committee authorizes grants throughout the year depending upon the Company's activities during that time period. Grants can be made from a variety of award types authorized under our Stock Incentive Plan.

Currently, the vesting criteria for most awards is service based to ensure that our equity compensation awards have the effect of retaining our employees. In light of the Company's performance, the competitive environment and the skill of our employees, the Compensation Committee anticipates that future awards will primarily be in shares of restricted stock.

The number of stock options awarded to our NEOs during 2013 was not based on individual or Company performance. Rather, the awards were determined by the Compensation Committee to target the 75th percentile in long-term incentive compensation of our peer group. This is consistent with our approach described above of using long-term incentives more aggressively than direct cash compensation in comparison to our peers and using equity awards for retention purposes.

Change in Control Payments

In 2011, the Company approved a change in control program that provides the Company's executives with certain specified severance payments following a change in control of the Company, provided that the severance occurs either without cause or by the executive for good reason within 24 months following the change in control. The definition of what constitutes a change in control tracks the language of the Company's Stock Incentive Plan.

Immediately prior to a change in control, all outstanding equity awards will vest and any performance targets will be deemed to have been met at 100%. This occurs without regard to whether a termination of employment occurs.

For the 24 months following a change in control, an executive who is terminated without cause or who terminates employment for good reason will be entitled to the severance payments. Generally, senior executives, including the NEOs, would receive a severance payment equal to two times base salary plus two times targeted bonus and 24 months of continued medical coverage. The "targeted bonus" is defined as the highest of (1) the maximum bonus opportunity established by the Compensation Committee for the executive or, if the Compensation Committee has not established the executive's bonus opportunity for the year in which the executive's termination occurs, 100% of the executive's base salary, (2) the maximum bonus opportunity established by the Compensation Committee for the executive for the immediately preceding year or (3) the maximum bonus opportunity established by the Compensation Committee for the executive immediately prior to the change in control.

As a condition to receiving severance payments, an executive must sign a release and waiver of claims that includes non-disparagement and confidentiality provisions. In most circumstances, the executive will, by statute, have 21 days to consider the release and seven days following execution of the release where the executive can revoke it. The executive will receive health coverage during this consideration period even if the executive does not ultimately execute the release.

Severance benefits paid to an executive will be reduced to the extent necessary to avoid the imposition of any excise tax associated with parachute payments.

In developing the change in control program, the Compensation Committee engaged the services of Longnecker as compensation consultants. As part of their analysis, Longnecker used the following peer group of companies for benchmarking purposes:



Oasis Petroleum Inc.	Comstock Resources, Inc.	Penn Virginia Corporation
Swift Energy Company	Kodiak Oil & Gas Corp.	GeoResources, Inc.
Stone Energy Corporation	Northern Oil & Gas, Inc.	Rex Energy Corporation
Carrizo Oil & Gas, Inc.	Resolute Energy Corporation	Endeavour International Corporation
Gulfport Energy Corporation	Goodrich Petroleum Corporation	GMX Resources, Inc.

Risk Assessment

As part of its oversight of the Company's executive and non-executive compensation programs, the Compensation Committee considers the impact of the Company's compensation programs, and the incentives created by the compensation awards that it administers, on the Company's risk profile. In addition, the Company reviews all of its compensation policies and procedures, including the incentives that they create and factors that may reduce the likelihood of excessive risk taking, to determine whether they present a significant risk to the Company. Based on this review, the Company has concluded that its compensation policies and procedures are not reasonably likely to have a material adverse effect on the Company. As a result of this analysis, the Compensation Committee identified the following risk mitigating factors:


•	use of long-term incentive compensation;


•	vesting periods for equity compensation awards that encourage executives and other key employees to focus on sustained stock price appreciation and to provide a long-term retention incentive for our key employees;


•	the Compensation Committee's discretionary authority to adjust annual incentive awards, which helps mitigate any business risks associated with such awards;


•	the Company's internal controls over financial reporting and other financial, operational and compliance policies and practices currently in place;


•	base salaries consistent with executives' responsibilities so that they are not motivated to take excessive risks to achieve a reasonable level of financial security; and


•	design of long-term compensation to reward executives and other key employees for driving sustainable and/or profitable growth for stockholders.

As a result of the above assessment, the Compensation Committee determined that the Company's policies and procedures largely achieve a proper balance between competitive compensation and prudent business risk.

Executive Compensation Tables

The following tables include compensation information for our NEOs for the last three years. For a discussion of 2013 NEO compensation, please read the Executive Compensation Discussion and Analysis above.

The 2013 Summary Compensation Table below sets forth compensation information for our NEOs relating to 2013, 2012 and 2011. Pursuant to SEC rules, the 2013 Summary Compensation Table is required to include for a particular fiscal year only those restricted stock awards, stock appreciation rights and options to purchase common stock granted during that year, rather than awards granted after year-end, even if awarded for services in that year. SEC rules require disclosure of variable cash compensation to be included in the year earned, even if payment is made after year-end. Generally, we pay any cash variable compensation for a particular year after the Compensation Committee has had an opportunity to review the Company's and each individual's performance for that year. As a result, cash variable compensation reported in the "Bonus" column was paid in the year following the year in which it is reported in the table.

2013 Summary Compensation Table



Name and Principal Position	Year	Salary ⁽¹⁾		Bonus ⁽²⁾		Stock Awards ⁽³⁾		Option Awards ⁽³⁾		All Other Compensation ⁽⁴⁾		Total
Gary C. Evans Chairman and CEO	2013	$	490,000	$	500,000	$	—	$	1,982,925	$	186,701	$	3,159,626
	2012	$	465,000	$	500,000	$	—	$	2,943,232	$	90,507	$	3,998,739
	2011	$	415,000	$	650,000	$	—	$	3,181,100	$	73,129	$	4,319,229
Ronald D. Ormand ⁽⁵⁾ Executive V.P., CFO, and Secretary	2013	$	236,923	$	137,500	$	—	$	660,975	$	17,419	$	1,052,817
	2012	$	275,000	$	50,000	$	—	$	981,077	$	28,057	$	1,334,134
	2011	$	250,000	$	240,625	$	—	$	1,223,500	$	36,966	$	1,751,091
Joseph C. Daches ⁽⁶⁾ Senior V.P. and CFO	2013	$	126,923	$	350,000	$	—	$	1,184,560	$	16,504	$	1,677,987
James W. Denny, III Executive V.P. and President, Appalachian Division	2013	$	295,000	$	300,000	$	—	$	660,975	$	88,479	$	1,344,454
	2012	$	275,000	$	275,000	$	—	$	981,077	$	61,454	$	1,592,531
	2011	$	250,000	$	240,625	$	—	$	1,223,500	$	68,981	$	1,783,106
H.C. "Kip" Ferguson Executive V.P. - Exploration	2013	$	275,000	$	200,000	$	—	$	660,975	$	29,234	$	1,165,209
	2012	$	275,000	$	500,000	$	—	$	981,077	$	27,199	$	1,783,276
	2011	$	250,000	$	240,625	$	—	$	1,223,500	$	36,324	$	1,750,449
R. Glenn Dawson ⁽⁷⁾ Executive V.P. and President, Williston Basin Division	2013	$	277,103	$	201,001	$	—	$	660,975	$	14,674	$	1,153,753
	2012	$	274,342	$	192,697	$	—	$	981,077	$	13,668	$	1,461,784

________________________________


⁽¹⁾	The amounts reflected in this column show each NEO's annualized salary for the majority of the year. For 2013, the amounts shown were effective March 1, 2013. For 2012, the amounts shown were effective April 16, 2012. For 2011, the amounts shown were effective March 1, 2011.

⁽²⁾

For a discussion of the 2013 executive bonuses, refer to Short-Term Incentives above. The bonus reflected for Mr. Daches includes a sign-on bonus of $150,000 paid when he joined the Company. The bonus for Mr. Ormand was a one-time separation payment. Cash variable compensation for 2012 performance was determined in July 2013; thus, the 2012 amounts in the "Bonus" column have been updated accordingly.

⁽³⁾

Represents the aggregate grant date fair value in accordance with Accounting Standards Codification 718, "Stock Compensation" (except no assumptions for forfeitures were included). For a discussion of the assumptions made in the valuation of stock and option awards, please refer to "Note 9 - Share-Based Compensation" in the notes to our consolidated financial statements included in our annual report on Form 10-K.


⁽⁴⁾	Amounts in this column are detailed in the following All Other Compensation Table.


⁽⁵⁾	Mr. Ormand was succeeded in his role as Chief Financial Officer of the Company by Joseph C. Daches, effective July 22, 2013, and resigned from his position as Executive Vice President - Finance and Head of Capital Markets and as an employee of the Company, effective October 31, 2013. Mr. Ormand's annualized salary for 2013 was $275,000.


⁽⁶⁾	Mr. Daches joined the Company on July 22, 2013, with an annualized base salary of $300,000. The amount shown reflects the amount paid to Mr. Daches from his hire date through the last payroll period in 2013.

⁽⁷⁾

Mr. Dawson's 2013 annualized salary was $285,000 CAD. The amount shown is converted to U.S. dollars using the nominal noon exchange rate on March 1, 2013, the effective date of his 2013 annual salary, as published by the Bank of Canada. Mr. Dawson's 2013 bonus was $225,000 CAD. The amount shown is converted to U.S. dollars using the nominal noon exchange rate on March 21, 2014, the date his 2013 bonus was paid, as published by the Bank of Canada. Mr. Dawson's 2012 annualized salary was $275,000 CAD. The amount shown is converted to U.S. dollars using the nominal noon exchange rate on April 16, 2012, the effective date of his 2012 annual salary, as published by the Bank of Canada. Mr. Dawson's 2012 bonus was $200,000 CAD. The amount shown is converted to U.S. dollars using the nominal noon exchange rate on August 16, 2013, the date his 2012 bonus was paid, as published by the Bank of Canada.

All Other Compensation Table

The charts and narrative below describe the benefits and perquisites for 2013 contained in the "All Other Compensation" column of the 2013 Summary Compensation Table.



	401(k) Matching Contribution ⁽¹⁾		Health, Dental, Vision, and Executive Illness Premiums		Life Insurance Premiums		Disability Insurance Premiums		Other
Mr. Evans	$	8,925	$	12,365	$	1,080	$	7,823	$	156,508	^{(4), (5)}
Mr. Ormand ⁽²⁾	$	—	$	10,139	$	900	$	6,380	$	—
Mr. Daches	$	8,925	$	11,020	$	367	$	1,789	$	—
Mr. Denny	$	8,925	$	9,461	$	729	$	5,766	$	63,598	⁽⁵⁾
Mr. Ferguson	$	8,925	$	12,442	$	1,080	$	6,787	$	—
Mr. Dawson ⁽³⁾	$	—	$	4,503	$	2,192	$	7,979	$	—

________________________________

⁽¹⁾

The Company's "safe harbor" matching contributions to its 401(k) plan for 2013 have not yet been made. When made, the Company expects that the contribution will be made in shares of the Company's common stock. Once dollar amounts for the Company's contributions are determined, the Company uses the closing price of the common stock the day prior to making its contribution to convert the dollar amounts to shares on a unitized basis. The amount of this contribution will change if the Company chooses to make a discretionary matching contribution for 2013.


⁽²⁾	Mr. Ormand was succeeded in his role as Chief Financial Officer of the Company by Joseph C. Daches, effective July 22, 2013, and resigned from his position as Executive Vice President - Finance and Head of Capital Markets and as an employee of the Company, effective October 31, 2013.


⁽³⁾	Certain amounts paid for the benefit of Mr. Dawson were paid in Canadian dollars throughout the course of the year while other amounts were paid in U.S. dollars. For simplification purposes, all amounts paid in Canadian dollars have been aggregated and converted to U.S. dollars using the nominal noon exchange rate for December 31, 2013, as published by the Bank of Canada.


⁽⁴⁾	We provide Mr. Evans with memberships to certain private country and city clubs to facilitate business meetings and initiate and strengthen business relationships. Mr. Evans uses one country club for business and non-business purposes. The cost of membership in that club is included in this total.

⁽⁵⁾

Because of extensive business travel requirements, we make corporate apartments available to Messrs. Evans and Denny and other employees. In 2013, Mr. Evans did not maintain a residence near the Company's Houston offices and the Company incurred an incremental cost of $86,914 associated with Mr. Evans' use of a Houston apartment along with other executives who also reside at the same premises. In 2013, Mr. Denny used corporate apartments near the Company's operations in Marietta, Ohio, and Lexington, Kentucky, with incremental costs to the Company of $38,731 and $24,867 respectively. We also provide vehicles at various locations. The amount shown for Mr. Evans includes the incremental cost of Mr. Evans' use of Company vehicles. We did not attribute any incremental cost to Mr. Denny's use of Company vehicles because the vehicles driven by Mr. Denny in 2013 had fully depreciated prior to 2012 and because of his limited personal use of those vehicles.

2013 Grants of Plan-Based Awards

The following table sets forth plan-based awards made in 2013. Each of our NEOs was granted options to purchase shares of the Company's common stock. All grants featured 25% immediate vesting and 25% additional vesting on the first three anniversaries of the grant date.



	Grant Date	Number of Securities Underlying Options	Exercise Price of Option Awards	Grant Date Fair Value of Option Awards
Mr. Evans	1/17/2013	750,000	$4.16	$	1,982,925
Mr. Ormand ⁽¹⁾	1/17/2013	250,000	$4.16	$	660,975
Mr. Daches	7/26/2013	400,000	$3.82	$	1,184,560
Mr. Denny	1/17/2013	250,000	$4.16	$	660,975
Mr. Ferguson	1/17/2013	250,000	$4.16	$	660,975
Mr. Dawson	1/17/2013	250,000	$4.16	$	660,975

________________________________


⁽¹⁾	Mr. Ormand was succeeded in his role as Chief Financial Officer of the Company by Joseph C. Daches, effective July 22, 2013, and resigned from his position as Executive Vice President - Finance and Head of Capital Markets and as an employee of the Company, effective October 31, 2013.

2013 Outstanding Equity Awards at Year-End

The following table identifies the outstanding equity-based awards held by the NEOs as of December 31, 2013. For all unvested awards, continued employment through the vesting date is required.



	Option and Stock Appreciation Right Awards						Stock Awards
	Award Year	Number of Securities Underlying Unexercised Options/SARs (Exercisable)	Number of Securities Underlying Unexercised Options/SARs (Unexercisable)	Equity Incentive Plan Awards: Number of Securities Underlying Unexercised Unearned SARs	Option Exercise Price/ SAR Base Price	Option Expiration Date	Number of Shares of Stock That Have Not Vested	Market Value of Shares of Stock That Have Not Vested
Mr. Evans	2013	187,500	562,500 ⁽²⁾	—	$4.16	1/17/2023	—	—
	2012	375,000	275,000 ⁽²⁾	—	$6.08	4/13/2022	—	—
	2011	601,250	—	—	$7.95	5/2/2021	—	—
	2010	500,000	—	2,208,332 ⁽³⁾	$6.09	11/29/2015	—	—
Mr. Ormand ⁽¹⁾	2011	231,250	—	—	$7.95	5/2/2021	—	—
Mr. Daches	2013	—	300,000 ⁽²⁾	—	$3.82	7/26/2023	—	—
Mr. Denny	2013	62,500	187,500 ⁽²⁾	—	$4.16	1/17/2023	—	—
	2012	125,000	125,500 ⁽²⁾	—	$6.08	4/13/2022	—	—
	2011	231,250	—	—	$7.95	5/2/2021	—	—
	2009	12,500	—	—	$1.17	9/30/2014	—	—
	2009	250,000	—	—	$1.69	10/23/2014	—	—
Mr. Ferguson	2013	62,500	187,500 ⁽²⁾	—	$4.16	1/17/2023	—	—
	2012	125,000	125,500 ⁽²⁾	—	$6.08	4/13/2022	—	—
	2011	231,250	—	—	$7.95	5/2/2021	—	—
	2010	270,000	—	—	$2.25	2/11/2020	—	—
	2009	100,000		—	$1.17	9/30/2014	—	—
Mr. Dawson	2013	62,500	187,500 ⁽²⁾	—	$4.16	1/17/2023	—	—
	2012	125,000	125,500 ⁽²⁾	—	$6.08	4/13/2022	—	—
	2011	675,000	—	—	$7.58	5/3/2021	—	—

________________________________


⁽¹⁾	Mr. Ormand was succeeded in his role as Chief Financial Officer of the Company by Joseph C. Daches, effective July 22, 2013, and resigned from his position as Executive Vice President - Finance and Head of Capital Markets and as an employee of the Company, effective October 31, 2013.


⁽²⁾	All 2013 and 2012 grants featured 25% immediate vesting and 25% additional vesting on the first three anniversaries of the grant dates, which were January 17, 2013 and April 13, 2012, respectively.

⁽³⁾

We awarded Mr. Evans stock appreciation rights on 3,083,332 shares of the Company's common stock, with vesting subject to specific stock price performance measures and certain specific reserve growth performance achievements over the five-year period following the grant date. If the performance measures are achieved, the stock appreciation rights become exercisable in three annual tranches based on the anniversary of the grant date. As of December 31, 2013, stock appreciation rights on 500,000 shares were vested and exercisable.

2013 Option Exercises and Stock Vested

The following table summarizes the options that our NEOs exercised in 2013. For stock awards that vested in 2013, the value that the NEO realized on the date the restrictions on the award lapsed is provided.



	Option Awards			Stock Awards
	Number of Shares Acquired on Exercise	Value Realized on Exercise		Number of Shares With Lapse of Restrictions	Value Realized on Lapse of Restrictions
Mr. Evans	—	$	—	65,025	$	468,830
Mr. Ormand ⁽¹⁾	187,500	$	1,239,375	—	$	—
Mr. Daches	100,000	$	546,000	—	$	—
Mr. Denny	—	$	—	—	$	—
Mr. Ferguson	—	$	—	—	$	—
Mr. Dawson	—	$	—	—	$	—

________________________________


⁽¹⁾	Mr. Ormand was succeeded in his role as Chief Financial Officer of the Company by Joseph C. Daches, effective July 22, 2013, and resigned from his position as Executive Vice President - Finance and Head of Capital Markets and as an employee of the Company, effective October 31, 2013.

Potential Payments Upon Termination or Change in Control

The following table identifies the payments that may be made to our NEOs following a change in control of the Company. For a detailed discussion of these payments, please see the Compensation Discussion and Analysis above. These calculations assume a change in control of the Company on December 31, 2013, and a closing stock price on that date of $7.31.



	Cash ⁽¹⁾			Equity ⁽²⁾		Perquisites / Benefits ⁽³⁾		Total
Mr. Evans	$	1,960,000	⁽⁴⁾	$	6,589,165	$	26,952	$	8,576,117
Mr. Daches	$	1,200,000	⁽⁵⁾	$	1,047,000	$	26,952	$	2,273,952
Mr. Denny	$	1,180,000	⁽⁶⁾	$	2,576,750	$	20,562	$	3,777,312
Mr. Ferguson	$	1,100,000	⁽⁷⁾	$	3,075,200	$	26,952	$	4,202,152
Mr. Dawson	$	1,108,412	⁽⁸⁾	$	1,095,000	$	8,850	$	2,212,262

________________________________


⁽¹⁾	Cash compensation is subject to each NEO's severance from employment without cause or by the NEO with good reason within 24 months following a change in control.


⁽²⁾	The 2013 Outstanding Equity Awards at Year-End table details the unvested awards that would have been subject to accelerated vesting on December 31, 2013. All outstanding equity awards are immediately vested upon a change in control.


⁽³⁾	The benefits identified in the third column consist of 24 months of continued Company contributions towards the cost of coverage for medical, dental and vision plans. The amounts were calculated by taking each NEO's actual coverage elections for 2014 and assuming that the cost of coverage would not change in 2015. Accordingly, these amounts are only estimates.


⁽⁴⁾	This consists of 2x base salary of $490,000 plus 2x targeted bonus with the bonus set at 100% of base salary.


⁽⁵⁾	This consists of 2x base salary of $300,000 plus 2x targeted bonus with the bonus set at 100% of base salary.


⁽⁶⁾	This consists of 2x base salary of $295,000 plus 2x targeted bonus with the bonus set at 100% of base salary.


⁽⁷⁾	This consists of 2x base salary of $275,000 plus 2x targeted bonus with the bonus set at 100% of base salary.


⁽⁸⁾	This consists of 2x base salary of $277,103 plus 2x targeted bonus with the bonus set at 100% of base salary.

Report of Our Compensation Committee

Our Compensation Committee reviewed the Executive Compensation Discussion and Analysis, or CD&A, as prepared by management of the Company, and discussed the CD&A with the Company's management. Based on the Committee's review and discussions, the Committee recommended to the Board that the CD&A be included in this annual report.

The Compensation Committee

Joe L. McClaugherty, Chair

Stephen C. Hurley

Jeff Swanson

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.



MAGNUM HUNTER RESOURCES CORPORATION

By:	/s/ GARY C. EVANS
	Gary C. Evans
	Chairman of the Board and Chief Executive Officer

Date: July 17, 2014



INDEX TO EXHIBITS

Exhibit Number		Description

2.1		Asset Purchase Agreement between the Registrant and Triad Energy Corporation, dated October 28, 2009 (incorporated by reference from the Registrant’s current report on Form 8-K filed on October 29, 2009).+

2.2		Arrangement Agreement between the Registrant and NGAS Resources, Inc., dated December 23, 2010 (incorporated by reference from the Registrant’s current report on Form 8-K filed on December 30, 2010).+

2.3		Arrangement Agreement between the Registrant and NuLoch Resources Inc., dated January 19, 2011 (incorporated by reference from the Registrant’s current report on Form 8-K filed on January 25, 2011).+

2.3.1		Plan of Arrangement under Section 193 of the Business Corporations Act (Alberta) with respect to the Acquisition of NuLoch Resources Inc. by the Registrant (incorporated by reference from the Registrant’s registration statement on Form S-4 filed on April 8, 2011).+

2.4		Asset Purchase Agreement, dated March 21, 2012, by and among Eureka Hunter Holdings, LLC, TransTex Gas Services LP, and Eureka Hunter Acquisition Sub LLC (incorporated by reference from the Registrant’s current report on Form 10-Q filed on May 3, 2012).+

2.4.1		First Amendment to Asset Purchase Agreement, dated April 2, 2012, by and between Eureka Hunter Holdings, LLC, TransTex Gas Services, LP, and Eureka Hunter Acquisition Sub LLC (incorporated by reference from the Registrant’s quarterly report on Form 10-Q filed on May 3, 2012).

2.5		Purchase and Sale Agreement, dated as of April 17, 2012, by and between Baytex Energy USA Ltd. and Bakken Hunter, LLC (incorporated by reference from the Registrant’s current report on Form 8-K filed on April 24, 2012).+

2.5.1		First Amendment to Purchase and Sale Agreement, dated May 17, 2012, by and between Baytex Energy USA Ltd. and Bakken Hunter, LLC (incorporated by reference from the Registrant’s current report on Form 8-K filed on May 23, 2012).

2.5.2		Second Amendment to Purchase and Sale Agreement, dated May 22, 2012, by and between Baytex Energy USA Ltd. and Bakken Hunter, LLC (incorporated by reference from the Registrant’s current report on Form 8-K filed on May 23, 2012).

2.6		Stock Purchase Agreement, dated as of October 24, 2012, by and among Triad Hunter, LLC, Viking International Resources Co., Inc., all of the stockholders of Viking International Resources Co., Inc., and solely for the purposes set forth therein, the Registrant (incorporated by reference from the Registrant’s current report on Form 8-K filed on October 30, 2012).+

2.7		Purchase and Sale Agreement, dated as of November 21, 2012, between Samson Resources Company and Bakken Hunter, LLC (incorporated by reference from the Registrant’s current report on Form 8-K filed on November 28, 2012).+

2.8		Stock Purchase Agreement, dated as of April 2, 2013, between the Registrant, Penn Virginia Oil & Gas Corporation, and Penn Virginia Corporation (incorporated by reference from the Registrant's current report on Form 8-K filed on April 8, 2013).+

2.9		Asset Purchase Agreement, dated as of August 12, 2013, between Triad Hunter, LLC and MNW Energy, LLC (incorporated by reference from the Registrant's quarterly report on Form 10-Q filed on November 8, 2013).+

2.10		Purchase and Sale Agreement, dated as of September 2, 2013, between Williston Hunter, Inc. and Oasis Petroleum of North America LLC (incorporated by reference from the Registrant's current report on Form 8-K filed on September 4, 2013).+

2.11		Purchase and Sale Agreement, dated as of November 19, 2013, by and among PRC Williston, LLC, Williston Hunter ND, LLC and Enduro Operating LLC (incorporated by reference from the Registrant's current report on Form 8-K filed on November 22, 2013).+



2.12		Purchase and Sale Agreement, dated January 21, 2013, among Shale Hunter, LLC, Magnum Hunter Resources Corporation, Magnum Hunter Production, Inc. and Energy Hunter Partners 2012-A Drilling & Production Fund, Ltd., New Standard Energy Texas LLC and New Standard Energy Limited (incorporated by reference from the Registrant's current report on Form 8-K filed on January 23, 2014).+

2.12.1		Transition Services Agreement, dated January 28, 2014, between Shale Hunter, LLC and New Standard Energy Texas LLC (incorporated by reference from the Registrant's current report on Form 8-K filed on January 30, 2014).+

3.1		Restated Certificate of Incorporation of the Registrant, filed February 13, 2002 (incorporated by reference from the Registrant’s registration statement on Form SB-2 filed on March 21, 2006).

3.1.1		Certificate of Amendment of Certificate of Incorporation of the Registrant, filed May 8, 2003 (incorporated by reference from the Registrant’s registration statement on Form SB-2 filed on March 21, 2006).

3.1.2		Certificate of Amendment of Certificate of Incorporation of the Registrant, filed June 6, 2005 (incorporated by reference from the Registrant’s registration statement on Form SB-2 filed on March 21, 2006).

3.1.3		Certificate of Amendment of Certificate of Incorporation of the Registrant, filed July 18, 2007 (incorporated by reference from the Registrant’s quarterly report on Form 10-QSB filed on August 14, 2007).

3.1.4		Certificate of Ownership and Merger Merging Magnum Hunter Resources Corporation with and into Petro Resources Corporation, filed July 13, 2009 (incorporated by reference from the Registrant’s current report on Form 8-K filed on July 14, 2009).

3.1.5		Certificate of Amendment of Certificate of Incorporation of the Registrant, filed November 3, 2010 (incorporated by reference from the Registrant’s current report on Form 8-K filed on November 2, 2010).

3.1.6		Certificate of Amendment of Certificate of Incorporation of the Registrant, filed May 9, 2011 (incorporated by reference from the Registrant’s quarterly report on Form 10-Q filed on March 31, 2011).

3.1.7		Certificate of Amendment of Certificate of Incorporation of the Registrant, filed June 29, 2011 (incorporated by reference from the Registrants registration statement on Form S-4 filed on January 14, 2013).

3.1.8		Certificate of Amendment of Certificate of Incorporation of the Registrant, filed January 25, 2013 (incorporated by reference from Amendment No. 1 to the Registrant’s registration statement on Form S-4 filed on February 5, 2013).

3.2		Amended and Restated Bylaws of the Registrant, dated March 15, 2001 as amended on April 14, 2006, and May 26, 2011 (incorporated by reference from the Registrant's quarterly report on Form 10-Q filed on August 9, 2011).

4.1		Form of certificate for common stock (incorporated by reference from the Registrant’s annual report on Form 10-K filed on February 18, 2011).

4.2		Certificate of Designation of Rights and Preferences of 10.25% Series C Cumulative Perpetual Preferred Stock, dated December 10, 2009 (incorporated by reference from the Registrant’s registration statement on Form 8-A filed on December 10, 2009).

4.2.1		Certificate of Amendment of Certificate of Designation of Rights and Preferences of 10.25% Series C Cumulative Perpetual Preferred Stock, dated August 2, 2010 (incorporated by reference from the Registrant’s quarterly report on Form 10-Q filed on August 12, 2010).

4.2.2		Certificate of Amendment of Certificate of Designation of Rights and Preferences of 10.25% Series C Cumulative Perpetual Preferred Stock, dated September 8, 2010 (incorporated by reference from the Registrant’s current report on Form 8-K filed on September 15, 2010).

4.3		Certificate of Designation of Rights and Preferences of 8.0% Series D Cumulative Preferred Stock, dated March 16, 2011 (incorporated by reference from the Registrant’s current report on Form 8-K filed on March 17, 2011).

4.4		Indenture, dated May 16, 2012, by and among the Registrant, the Guarantors named therein, Wilmington Trust, National Association and Citibank, N.A., as Paying Agent, Registrar and Authenticating Agent (incorporated by reference from the Registrant’s current report on Form 8-K filed on May 16, 2012).




4.4.1		First Supplemental Indenture, dated October 18, 2012, by and among the Registrant, the Guarantors named therein, Wilmington Trust, National Association, as Trustee, and Citibank, N.A., as Paying Agent, Registrar and Authenticating Agent (incorporated by reference from the Registrant's registration statement on Form S-4 filed on January 14, 2013).

4.4.2		Second Supplemental Indenture, dated December 13, 2012, by and among the Registrant, the Guarantors named therein, Wilmington Trust, National Association, as Trustee, and Citibank, N.A., as Paying Agent, Registrar and Authenticating Agent (incorporated by reference from the Registrant's registration statement on Form S-4 filed on January 14, 2013).

4.4.3		Third Supplemental Indenture, dated April 24, 2013, by and among the Registrant, the Guarantors named therein, Wilmington Trust, National Association, as Trustee, and Citibank, N.A., as Paying Agent, Registrar and Authenticating Agent (incorporated by reference from the Registrant’s annual report on Form 10-K filed on June 14, 2013).

4.4.4		Fourth Supplemental Indenture, dated July 23, 2013, by and among Shale Hunter, LLC, Wilmington Trust, National Association, as Trustee, and Citibank, N.A., as Paying Agent, Registrar and Authenticating Agent (incorporated by reference from the Registrant’s quarterly report on Form 10-Q filed on August 9, 2013).

4.5		Certificate of Designations of Rights and Preferences of the 8.0% Series E Cumulative Convertible Preferred Stock of the Registrant, dated November 2, 2012 (incorporated by reference from the Registrant’s current report on Form 8-K filed on November 8, 2012).

4.6		Deposit Agreement, dated as of November 2, 2012, by and among the Registrant, American Stock Transfer & Trust Company, as Depositary, and the holders from time to time of the depositary receipts described therein (incorporated by reference from the Registrant’s current report on Form 8-K filed on November 8, 2012).

10.1		Amended and Restated Stock Incentive Plan of Registrant (incorporated by reference from the Registrant’s current report on Form 8-K filed on December 3, 2010).*

10.1.1		First Amendment to Amended and Restated Stock Incentive Plan (incorporated by reference from the Registrant’s proxy statement on Annex C of Schedule 14A filed on April 1, 2011).*

10.1.2		Second Amendment to the Magnum Hunter Resources Corporation Amended and Restated Stock Incentive Plan (incorporated by reference from the Registrant’s registration statement on Form S-8 filed on February 14, 2013).

10.1.3		Third Amendment to the Magnum Hunter Resources Corporation Amended and Restated Stock Incentive Plan (incorporated by reference from the Registrant’s current report on Form 8-K filed on January 23, 2013).*

10.2		Form of Stock Option Agreement under the Registrant’s Amended and Restated Stock Incentive Plan (incorporated by reference from the Registrant’s annual report on Form 10-K filed on February 18, 2011).*

10.3		Form of Restricted Stock Award Agreement under the Registrant’s Amended and Restated Stock Incentive Plan (incorporated by reference from the Registrant’s current report on Form 8-K filed on December 3, 2010).*

10.4		Form of Stock Appreciation Right Agreement under the Registrant’s Amended and Restated Stock Incentive Plan (incorporated by reference from the Registrant’s current report on Form 8-K filed on December 3, 2010).*

10.5		Form of Executive Change of Control Retention Agreements (incorporated by reference from the Registrant’s annual report on Form 10-K filed on February 29, 2012).*

10.5.1		Amendment to Form of Executive Change of Control Retention Agreements (incorporated by reference from the Registrant’s annual report on Form 10-K filed on February 29, 2012).*

10.6		Form of Support Agreement between the Registrant and certain NGAS Resources, Inc. shareholders, dated December 23, 2010 (incorporated by reference from the Registrant’s current report on Form 8-K filed on December 30, 2010).

10.7		Omnibus Agreement between the Registrant, NGAS Resources, Inc., NGAS Production Co., NGAS Gathering, LLC, Seminole Energy Services, L.L.C., Seminole Gas Company, L.L.C. and NGAS Gathering II, LLC, dated March 10, 2011 (incorporated by reference from the Registrant’s current report on Form 8-K filed on March 16, 2011).@




10.8		First Lien Credit Agreement by and among Eureka Hunter Pipeline, LLC, the lenders party thereto and SunTrust Bank (incorporated by reference from the Registrant’s current report on Form 8-K filed on August 22, 2011).

10.8.1		First Amendment to First Lien Credit Agreement, dated May 2, 2012, by and among Eureka Hunter Pipeline, LLC, SunTrust Bank, as Administrative Agent, and the lenders party thereto (incorporated by reference from the Registrant’s current report on Form 8-K filed on May 8, 2012).

10.8.2		Consent to First Lien Credit Agreement, dated March 18, 2013 and effective as of March 17, 2013, by and among Eureka Hunter Pipeline, LLC, SunTrust Bank, as Administrative Agent, and the lenders party thereto (incorporated by reference from the Registrant's current report on Form 8-K filed on March 22, 2013).

10.8.3		Consent to First Lien Credit Agreement, dated May 15, 2013, by and among Eureka Hunter Pipeline, LLC, SunTrust Bank, as Administrative Agent, and the lenders party thereto (incorporated by reference from the Registrant's current report on Form 8-K filed on May 21, 2013).

10.9		Second Lien Term Loan Agreement by and among Eureka Hunter Pipeline, LLC, the lenders party thereto and PennantPark Investment Corporation (incorporated by reference from the Registrant’s current report on Form 8-K filed on August 22, 2011).+

10.9.1		First Amendment to Second Lien Term Loan Agreement, dated September 20, 2011, by and among Eureka Hunter Pipeline, LLC, PennantPark Investment Corporation and the other lenders party thereto (incorporated by reference from the Registrant’s current report on Form 8-K filed on May 8, 2012).

10.9.2		Limited Waiver to Second Lien Term Loan Agreement, dated May 2, 2012, by and among Eureka Hunter Pipeline, LLC, U.S. Bank National Association, as Collateral Agent, PennantPark Investment Corporation and the other lenders party thereto (incorporated by reference from the Registrant’s current report on Form 8-K filed on May 8, 2012).

10.9.3		Second Amendment to Second Lien Term Loan Agreement by and among Eureka Hunter Pipeline, LLC, PennantPark Investment Corporation and the other lenders party thereto (incorporated by reference from Registrant’s current report on Form 8-K filed on May 8, 2012).

10.9.4		Limited Waiver and Third Amendment to Second Lien Term Loan Agreement, dated June 29, 2012, by and among Eureka Hunter Pipeline, LLC, PennantPark Investment Corporation and the other lenders party thereto (incorporated by reference from Registrant’s current report on Form 8-K filed on July 6, 2012).

10.9.5		Consent to Second Lien Term Loan Agreement, dated March 18, 2013 and effective as of March 17, 2013, by and among Eureka Hunter Pipeline, LLC, PennantPark Investment Corporation and the other lenders party thereto (incorporated by reference from the Registrant's current report on Form 8-K filed on March 22, 2013).

10.9.6		Consent and Fourth Amendment to Second Lien Term Loan Agreement, dated May 15, 2013, by and among Eureka Hunter Pipeline, LLC, PennantPark Investment Corporation and the other lenders party thereto (incorporated by reference from the Registrant's current report on Form 8-K filed on May 21, 2013).

10.10		Amended and Restated Limited Liability Company Agreement of Eureka Hunter Holdings, LLC, dated March 21, 2012, between the Registrant and ArcLight Capital Partners, LLC. (incorporated by reference from the Registrant’s quarterly report on Form 10-Q filed on May 3, 2012). +

10.10.1		First Amendment to Amended and Restated Limited Liability Company Agreement of Eureka Hunter Holdings, LLC, dated April 2, 2012, by and between the Registrant, Ridgeline Midstream Holdings, LLC, and TransTex Gas Services LP (incorporated by reference from the Registrant’s quarterly report on Form 10-Q filed on May 3, 2012).

10.10.2		Second Amendment to Amended and Restated Limited Liability Company Agreement of Eureka Hunter Holdings, LLC, dated March 7, 2013 by and between the Registrant, Ridgeline Midstream Holdings, LLC, and TransTex Gas Services LP (incorporated by reference from the Registrant’s current report on Form 8-K filed on March 13, 2013, 2013).
10.11		Series A Convertible Preferred Unit Purchase Agreement, dated March 21, 2012, by and among Eureka Hunter Holdings, LLC, the Registrant, and Ridgeline Midstream Holdings, LLC (incorporated by reference from the Registrant’s quarterly report on Form 10-Q filed on May 3, 2012). +



10.12		Form of Indemnification Agreement for Directors (incorporated by reference from the Registrant's current report on Form 8-K filed on June 7, 2013).*

10.13		Form of Indemnification Agreement for Officers (incorporated by reference from the Registrant's current report on Form 8-K filed on June 7, 2013).*

10.14		Third Amended and Restated Credit Agreement, dated as of December 13, 2013, among the Registrant and Bank of Montreal, as Administrative Agent, and the lenders party thereto (incorporated by reference from the Registrant's current report on Form 8-K filed on December 18, 2013).

10.15		Omnibus Settlement Agreement and Release, dated as of January 9, 2014, by and among Magnum Hunter Resources Corporation, a Delaware corporation, Magnum Hunter Production, Inc., a Kentucky corporation, formerly known as NGAS Production Co., which in turn was formerly known as Daugherty Petroleum, Inc., Eureka Hunter Pipeline, LLC, a Delaware limited liability company, Seminole Energy Services, L.L.C., an Oklahoma limited liability company, Seminole Gas Company, L.L.C., an Oklahoma limited liability company, Seminole Murphy Liquids Terminal, L.L.C., a Tennessee limited liability company, NGAS Gathering II, LLC, a Kentucky limited liability company, and NGAS Gathering, LLC, a Kentucky limited liability company (incorporated by reference from the Registrant's current report on Form 8-K filed on January 14, 2014).

10.16		Letter Agreement, dated October 31, 2013, between the Registrant and Ronald D. Ormand (previously filed with the Registrant’s Form 10-K/A filed on March 31, 2014).

12.1		Computation of Ratio of Earnings to Fixed Charges (previously filed with the Registrant’s annual report on Form 10-K filed on February 25, 2014).

21.1		List of Subsidiaries (previously filed with the Registrant’s annual report on Form 10-K filed on February 25, 2014).

23.1		Consent of BDO USA, LLP.#

23.2		Consent of Hein & Associates LLP.#

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 and Chief Financial Officer provided pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.#

99.1		Independent Engineer Reserve Report for the year ended December 31, 2013 prepared by Cawley Gillespie & Associates, Inc.#

101.INS^		XBRL Instance Document.

101.SCH^		XBRL Taxonomy Extension Schema Document.

101.CAL^		XBRL Taxonomy Extension Calculation Linkbase Document.

101.LAB^		XBRL Taxonomy Extension Label Linkbase Document.

101.PRE^		XBRL Taxonomy Extension Presentation Linkbase Document.

101.DEF^		XBRL Taxonomy Extension Definition Presentation Linkbase Document.



*		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

^		These exhibits are furnished herewith. In accordance with Rule 406T of Regulation S-T, these exhibits are not deemed to be filed or part of a registration statement or prospectus for purposes of Section 11 or 12 of the Securities Act of 1933, as amended, are not deemed to be filed for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, and otherwise are not subject to liability under these sections.

Magnum Hunter Resources Inactive 10-K/A2013 FY Annual report (amended)