Magnum Hunter Resources Reports Second Quarter 2014 Financial and Operating Results

HOUSTON, TX--(Marketwired - Aug 8, 2014) - Magnum Hunter Resources Corporation (NYSE: MHR) (NYSE MKT: MHR.PRC) (NYSE MKT: MHR.PRD) (NYSE MKT: MHR.PRE) (the "Company" or "Magnum Hunter") announced today financial and operating results for the three months ended June 30, 2014. The Company plans to file its Form 10-Q for the quarter ended June 30, 2014 with the Securities and Exchange Commission later today. Second quarter highlights of the Company's financial and operating results include the following:

• Oil and gas revenues for the quarter were $78.2 million, a 58% increase over the prior year second quarter and an 11% increase over the first quarter of 2014
• Midstream and marketing revenues for the quarter were $48.4 million, a 246% increase over the prior year second quarter and a 53% increase over the first quarter of 2014
• Adjusted EBITDAX^(a) for the quarter was $51.4 million, an increase of 103% compared to prior year second quarter and an increase of 32% compared to the first quarter of 2014
• Net Loss and adjusted net loss^(a) for the quarter of ($0.43) and ($0.09), respectively, per diluted share
• Production from continuing operations of 15,923 BOEPD and adjusted production^(b) of 17,822 BOEPD; adjusted production increased 18% over the prior year second quarter
• Throughput volumes on Eureka Hunter Pipeline System reached a record high, averaging 223,573 MMBtu/d during the quarter with a recent peak throughput rate of 268,361 MMBtu/d
• Capacity on Eureka Hunter Pipeline System is anticipated to grow to 1.5 Bcf/d over the next year upon completion of interconnects into Dominion, REX and TETCO
• Acquired approximately 15,228 net leasehold acres (~ $4,347/acre) within the Marcellus and Utica Shale plays
• Closed on the acquisition in July of approximately 1,700 net mineral acres located in Monroe County, Ohio and Wetzel County, West Virginia for $22.7 million
• Strategic decision made to monetize Divide County, North Dakota operated/non-operated properties and reallocate resources to core operations in the Appalachian Basin
• Mid-year 2014 proved reserves increased 11% from year-end 2013 to 79.8 MMBoe and mid-year 2014 3P reserves increased 11% from mid-year 2013 to 132.9 MMBoe

^(a) See Non-GAAP Financial Measures and Reconciliations below

^(b) Adjusted production includes production from continuing operations and 1,899 BOEPD of production from discontinued operations

Financial and Operating Results for the Three Months Ended June 30, 2014

Magnum Hunter reported an increase in oil and gas revenues of 58% to $78.2 million for the three months ended June 30, 2014, compared with $49.6 million for the three months ended June 30, 2013. The increase in oil and gas revenues resulted principally from (i) increases in the Company's oil and natural gas production as a result of its expanded drilling efforts in the Company's core areas of operations in the Marcellus Shale and Utica Shale plays and (ii) higher average realized commodity prices for the period. Midstream and marketing revenues also increased to $48.4 million or 246% for the three months ended June 30, 2014, compared with $14.0 million for the three months ended June 30, 2013. The increase in midstream and marketing revenues was principally due to (i) increased total throughput volumes on the Eureka Hunter Pipeline System and (ii) increased third-party gas marketing volumes.

The Company reported a net loss of ($80.0) million attributable to common shareholders, or ($0.43) per basic and diluted common shares outstanding, for the three months ended June 30, 2014, compared with net income of $151.3 million, or $0.89 per basic and diluted common shares outstanding, for the three months ended June 30, 2013. When adjusted for a combination of certain non-recurring and non-cash items, the Company's adjusted net loss attributable to common shareholders for the three months ended June 30, 2014 was ($16.8) million or ($0.09) per basic and diluted common shares outstanding (see Non-GAAP Financial Measures and Reconciliations below).

For the three months ended June 30, 2014, Magnum Hunter's Adjusted Earnings Before Interest, Income Taxes, Depreciation, Amortization and Exploration ("Adjusted EBITDAX") was $51.4 million, compared with $25.4 million for the three months ended June 30, 2013 (See Non-GAAP Financial Measures and Reconciliations below), an increase of 103%. The increase in Adjusted EBITDAX was due primarily to (i) an overall production increase as a result of the Company's expanded drilling operations in its core areas of operations in the Marcellus Shale and Utica Shale plays, (ii) higher average realized commodity prices during the period and (iii) lower lease operating expenses ("LOE") per barrel of oil equivalent ("BOE"). The decrease in LOE per BOE was primarily due to (i) lower Appalachian Basin third-party gas transportation charges, (ii) lower recurring costs in the Williston Basin as a result of the Company's third-party operators' program to electrify producing well locations and other increased efficiencies at the field level and (iii) lower non-recurring well work-over expenses in the Williston Basin. The Company anticipates LOE in the Williston Basin to continue to decrease as a result of efficiencies at the field level which continue to be implemented. Recurring general and administrative expenses for the three months ended June 30, 2014 increased to $10.4 million from $4.8 million during the three months ended June 30, 2013, primarily due to (i) increased professional fees and transactional expenses during the quarter and (ii) temporary increases in expenses related to third-party consultants (See Non-GAAP Financial Measures and Reconciliations below). The Company fully expects that its future reliance on third-party consultants will decrease substantially as full-time accounting personnel are added.

Oil and gas production increased 49% for the three months ended June 30, 2014 to 1.449 million BOE ("MMBoe") or an average of 15,923 BOE per day ("Boe/d") (44% oil/liquids), compared with production of 970 thousand BOE ("MBoe") or an average of 10,664 Boe/d for the three months ended June 30, 2013. The increase in production was attributable primarily to the Company's (i) expanded drilling program in its core areas of operations in the Marcellus and Utica Shale plays and (ii) further development in the Williston Basin. For the three months ended June 30, 2014, adjusted production, which includes production from continuing operations and production from discontinued operations of 1,899 Boe/d, increased 18% to 17,822 Boe/d^(b) compared with adjusted production of 15,125 Boe/d for the three months ended June 30, 2013.

2014 Significant Divestitures

To-date in 2014, Magnum Hunter has completed several non-core asset divestitures resulting in net proceeds in excess of $100 million, before customary purchase price adjustments. The Company divested its remaining South Texas properties in Atascosa County to New Standard Energy for a purchase price of $24.5 million ($15.0 million in cash and $9.5 million in stock of New Standard Energy), monetized its properties in Alberta, Canada for CAD$9.5 million (approximately US$8.7 million), divested its properties in the Tableland Field in Saskatchewan, Canada for CAD$75 million (approximately US$67.5 million) and sold the Vadis field in West Virginia for $0.5 million. The Company continues to actively focus on divesting certain non-core assets and anticipates additional announcements to that effect in the coming months. The Company has made a strategic decision to monetize its Divide County, North Dakota operated and non-operated properties and reallocate these financial resources to its core operations in the Appalachian Basin.

Mid-Year 2014 Proved and 3P Reserves

On July 14, 2014, the Company announced that total proved reserves at June 30, 2014 were 79.8 MMBoe (38% crude oil and NGLs; 47% proved developed producing), an 11% increase compared with total proved reserves at December 31, 2013. Proved developed reserves at mid-year 2014 totaled 50.6 MMBoe, a 4% increase over year-end 2013. Proved undeveloped reserves at mid-year 2014 increased 12% to 29.2 MMBoe, compared with those at year-end 2013. These increases were primarily due to the execution and continued delineation of the Company's existing leasehold acreage position in the Marcellus and Utica Shales in West Virginia and Ohio.

At year-end 2013, the Company had booked proved reserves of only one Utica Shale well. At June 30, 2014, the Company was successful at booking proved developed non-producing reserves of one additional Utica Shale well and also booked proved undeveloped reserves of two Utica Shale wells for a total of four wells. The Company expects to significantly increase proved reserves in the Utica Shale, where it presently owns over 118,000 net leasehold acres, during the remainder of 2014 as a result of "pad" drilling and further delineation of its leasehold acreage position presently ongoing in this region. At June 30, 2014, the Appalachian Basin (including properties in the Marcellus Shale and Utica Shale in West Virginia and Ohio and properties in Kentucky) accounted for approximately 80% of Magnum Hunter's total proved reserves volumes, the Williston Basin in North Dakota accounted for approximately 19% and other legacy assets accounted for the remaining 1%.

The Company's proved, probable and possible ("3P") reserves at mid-year 2014 totaled 132.9 MMBoe, which represents an 11% increase compared with those at mid-year 2013. The estimates of Magnum Hunter's 3P reserves at both June 30, 2014 and June 30, 2013 were prepared by the Company's independent engineering consultant, Cawley Gillespie & Associates, Inc.

Capital Expenditures and Liquidity

Magnum Hunter's total upstream and midstream capital expenditures, including leasehold acquisitions, were $189.4 million for the three months ended June 30, 2014. Total upstream capital expenditures for the three months ended June 30, 2014 were $77.5 million, consisting of $33.2 million for the Williston Basin and $44.2 million for the Appalachian region. Leasehold acquisition expenditures for the three months ended June 30, 2014, were $59.9 million, primarily in Washington, Noble and Monroe Counties, Ohio and Tyler, Ritchie and Wetzel Counties, West Virginia for an average price of $4,337 per acre. Total midstream capital expenditures for the period were $52.0 million.

Magnum Hunter believes that its internally generated cash flows, borrowing base availability (and future anticipated borrowing base increases) under its Senior Revolving Credit Facility, and additional liquidity sources, including but not limited to proceeds from non-core asset sales and potential capital market financings, will provide it with sufficient liquidity to fund the remainder of its fiscal 2014 capital budget. As of July 31, 2014, the Company had total liquidity of approximately $49.1 million, comprised of approximately $42.1 million of cash and $7.0 million of borrowing availability under its Senior Revolving Credit Facility. To further enhance its liquidity, the Company is actively pursuing additional non-core asset sales, which the Company expects to close throughout the remainder of 2014.

Operations

During the quarter ended June 30, 2014, the Company commenced or participated in the drilling of a total of 18 gross wells, of which 5 were operated by the Company. The Company had a 100% success rate on the 10 wells in which it had a working interest that were completed in the second quarter of 2014.

The table below summarizes the Company's gross drilling activities by area for the second quarter of 2014:

		Second Quarter 2014
		Total Drilled Wells		Completed Wells		Awaiting Frac
Marcellus Shale		3		4		3
Utica Shale		2		0		2
Williston Basin		13		6		6
Total		18		10		11

Currently, the Company is running six drilling rigs (three operated and three non-operated rigs). Of these six rigs, four rigs (three operated and one non-operated rigs) are drilling wells in the Marcellus Shale and Utica Shales in West Virginia and Ohio, and two non-operated rigs are drilling wells in the Williston Basin/Bakken Shale in North Dakota.

Marcellus Shale and Utica Shale

During the second quarter of 2014, the Company completed drilling five gross (2.1 net) wells in the Marcellus Shale and Utica Shale plays. In addition, the Company drilled and cased to the intermediate casing point four gross (3.1 net) wells, three of which are operated. As a result of our development plan, two gross (one net) wells on the Stalder Pad and four gross (four net) wells on the WVDNR Pad are currently shut-in due to additional drilling activities on these pads. The Company's net production in the second quarter of 2014 attributable to Triad Hunter, LLC's operations was approximately 72.8 Mcfe/d, a 76% increase over the prior year quarter.

The Company drilled and cased the Stewart Winland #1300, its first dry gas Utica Shale well in Tyler County, West Virginia to a true vertical depth of 11,050 feet. The Stewart Winland #1300 targeted the Point Pleasant formation, which is approximately 350 feet deeper than the same formation targeted by the Company's first Utica Shale dry gas well, the Stalder #3UH in Monroe County, Ohio. The wireline logging data confirmed the Point Pleasant target formation from the Stewart Winland #1300 pad location contains hydrocarbons and appears to possibly have even more bottom hole pressure than the Stalder #3UH. The Stewart Winland #1300 was drilled and cased with a 5,500 foot horizontal lateral, and was successfully fracture stimulated with 22 stages and is presently resting. Currently, the Company is using a combination of zipper fracing and fracture stimulation on the three 100% working interest Marcellus Shale wells on the same pad. The Company expects to report initial production test rates from these four 100% owned wells sometime in mid-September 2014.

On the Stalder Pad location, the Company recently successfully drilled and cased the intermediate section on the Stalder #8UH and #7UH located in Monroe County, Ohio. A rig is currently drilling the vertical intermediate section of the Stalder #6UH on air, and has approximately 3,125 feet remaining in the vertical. These wells will be drilled to an average vertical depth of 10,650 feet with an anticipated 6,133 foot average horizontal lateral. Following the drilling of the Stalder #6UH, the Company will commence drilling of the curve and lateral section of these wells. The Company's first dry gas Utica Shale well, the Stalder #3UH, and first Marcellus Shale well, the Stalder #2MH, on this pad are currently shut-in to allow for the drilling and development of these three new Utica Shale wells on this pad. The Company expects to report initial production rates from these three new Utica Shale wells in December 2014.

On the Ormet 15 Pad located in Monroe County, Ohio, the Company has commenced drilling four down-dip Utica wells, the Ormet #7-15UH, #8-15UH, #9-15UH and #10-15UH. Alpha Hunter, a wholly-owned subsidiary of the Company, is currently drilling the Ormet 9-15UH well with its TXD 500 robotic drilling rig and is 2,425 feet in the vertical section with 6,800 feet remaining. These Utica Shale wells will be drilled to an average vertical depth of 11,100 feet with a 4,700 foot average horizontal lateral. The Company anticipates fracture stimulation of these four wells in October 2014 and expects to report initial production test rates in December 2014. Due to the recent mineral purchase of ~1,700 net mineral acres including this pad, the Company's net revenue interest has increased to almost 100%. Therefore, the net impact of these four wells to the Company will be significant.

On the WVDNR Pad in Wetzel County, West Virginia, the Company currently has a rig on location and has spud the vertical section of the WVDNR #1412. Following the completion of this well, the Company will begin drilling the WVDNR #1410, #1411 and #1413. The wells will be drilled horizontally with an expected true vertical depth of approximately 7,500 feet. The anticipated lateral lengths for the four wells will be approximately 3,930 feet, 4,630 feet, 5,325 feet and 5,840 feet, respectively. The WVDNR #1207, #1208, and #1209 (~100% working interest) flowed to production on April 2, 2014, and were subsequently shut-in on May 31, 2014 to prepare the pad location for drilling and development of these four additional down-dip laterals off the existing pad. For the seven-day period prior to shut-in, the WVDNR #1207, #1208, and #1209 had an average net daily production of approximately 1,575 Boe/d, or 9,450 Mcfe/d. The Company anticipates all eight wells (~100% working interest) will be online and flowing to sales via the Eureka Hunter Pipeline System in December 2014.

In June 2014, the Company announced the formation of a new joint venture with EdgeMarc Energy ("EdgeMarc") in Washington County, Ohio. The joint venture's Merlin Pad includes approximately 620 leasehold acres (approximately 14% working interest to Triad Hunter and 86% working interest to EdgeMarc) and is located approximately 5.1 miles southeast of Triad Hunter's Farley Pad. EdgeMarc is the operator of this pad and has recently drilled and cased the Merlin #10PPH Utica Shale well, which the parties estimate will have a true vertical depth of 8,050 feet and a lateral length of 7,200 feet. The wire line log interpretation completed on this well was very encouraging.

Williston Basin

During the second quarter of 2014, the Company participated in 13 gross (2.4 net) wells and the completion of six gross (1.3 net) wells in Divide County, North Dakota. Two of the completed wells utilized plug and perforation technology.

A third-party has been engaged to gather and transport oil from certain of the Company's non-operated wells in Divide County, North Dakota to the Colt Hub in Epping, North Dakota in order to eliminate trucking costs and minimize downtime during spring break-up. The Company expects that approximately 51 existing wells and 18 wells scheduled to be drilled under the operator's 2014 drilling program will be connected to the gathering system, which is expected to be fully operational by September 2014. A truck terminal will also be constructed and connected to the gathering system to minimize oil hauling costs from wells not connected to the gathering system. The Bonneville pad was connected to the system in May 2014, and construction has commenced on the north gathering pipeline with construction on the south pipeline scheduled to begin in August 2014.

As of June 30, 2014, the operators of the Company's non-operated properties in Divide County have electrified approximately 113 gross wells and tied in approximately 183 gross wells into the Oneok, Inc. ("Oneok") gas gathering system in Divide County. Production and revenues from the gathering of associated gas from the tied-in wells are growing monthly. Approvals from both the Canadian National Energy Board and the U.S. Federal Energy Regulatory Commission have been obtained for the cross-border Tableland Field, Canada gas gathering project being constructed by the Company and the buyer of its Canadian properties with an expected start date in the next couple of weeks. The completion of the project is expected to generate volumes of approximately 600 Mcf/d to the Company's account, which would be applied to the Company's Oneok gas sales volume commitment.

Eureka Hunter

Eureka Hunter Pipeline, LLC ("Eureka Hunter") recently achieved a peak throughput rate of 268,361 MMBtu/d in July 2014. During the second quarter of 2014, Eureka Hunter's gas gathering pipeline system averaged 223,573 MMBtu/d. During June 2014, Triad Hunter produced approximately 38% of the volumes that flowed through the Eureka Hunter system.

Eureka Hunter shippers are currently limited to capacity through the Mobley gas processing facility in West Virginia and downstream on Equitrans. A fourth Mobley plant is expected to come online in December 2014 adding 200,000 Mcf of processing, and Equitrans is adding compression to further expand capacity downstream of Mobley. Eureka Hunter is also adding additional takeaway capacity at Mobley with a new residue line under construction to TCO (Colombia Gas). This new residue line will provide a competitive advantage for producers previously limited to one take away pipeline and its related gas markets.

Eureka Hunter expects to add significant throughput volumes from a combination of Triad Hunter's new wells mentioned above and other third parties' production during the remainder of 2014. Throughput volumes are anticipated to reach 400,000 MMBtu/d by the end of 2014. Much of the added throughput will be dry gas from the Utica Shale being delivered into various interstate pipeline connections planned in or near Monroe County, Ohio, which include Dominion, REX and TETCO. The initiation of dry gas from the Utica Shale will mark a significant milestone for Eureka Hunter as the system will be flowing dry gas north and will continue to move wet gas from the Marcellus Shale east to Mobley.

Eureka Hunter has plans to add an interconnect into Natrium (Blue Racer Midstream) to increase its Marcellus Shale wet deliveries on the system to 500 Mmcf/d plus, expected to be completed by year-end.

Eureka Hunter continues to construct pipeline on five distinct project fronts, which include the Crescent Line, the REX-TEX, the Ormet Extension, the Stewart Winland, and the Mobley-TCO. These projects are in varying stages of construction utilizing three different construction crews. With the completion of expansion projects currently under construction, the Company expects the Eureka Hunter system will have a throughput capacity of approximately 1.5 Bcf/d by the end of 2014.

Eureka Hunter has recently completed its mainline compression effort and has lowered line pressures by approximately 150-200 psi across the system. This new compression will help to effect steady deliveries into the Mobley facility. The reduced line pressure also helps producers move gas more easily into the Eureka Hunter system as well.

Management Comments

Mr. Gary C. Evans, Chairman of the Board and Chief Executive Officer of Magnum Hunter, commented, "The financial numbers reported today continue to reflect the changes being made in our business model with much greater emphasis being focused on our Appalachian assets. This redirection will continue throughout the year as we are successful at divesting all other properties to focus on our substantial leasehold position in the Marcellus and Utica Shale plays. We spent almost $60 million during the quarter expanding this position by acquiring additional leases in West Virginia and Ohio. We have subsequently spent another $23 million acquiring minerals in Eastern Ohio. We believe these acquisitions of both minerals and leaseholds will prove to be wise decisions for many years to come. Our development efforts in drilling new wells as we extend the Utica play further south are most encouraging. We anticipate announcing our most recent pad drilling results, the Stewart Winland pad located in Tyler County, West Virginia (3 Marcellus and 1 Utica -- 100% owned) by mid-September. Pipeline connection will be ready before the end of August, therefore mitigating any production delays that our neighboring offset operators continue face. Maintaining control of our midstream assets at Eureka Hunter is paying off handsomely with continued increases in throughput volumes and many new interconnects forthcoming. With the expansion efforts currently we currently have ongoing, this system will soon have a throughput capacity of 1.5 Bcf per day. Our Company's production growth this year is significantly back end loaded due to pad drilling, however we remain on track to meet our 2014 exit rate goal of 32,500 Boe per day."

Non-GAAP Financial Measures

This release contains certain financial measures that are non-GAAP measures. We have provided reconciliations within this release of the non-GAAP financial measures to the most directly comparable GAAP financial measures. See "Non- GAAP Financial Measures and Reconciliations" below. 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 release.

Magnum Hunter defines adjusted income (loss) as reported net income (loss) attributable to common shareholders, plus non-recurring and non-cash items which include (1) exploration, (2) impairment of proved oil and gas properties, (3) non-cash stock compensation expense, (4) non-cash 401k matching expense, (5) non-recurring transaction and other expense, (6) unrealized (gain) loss on investments, (7) interest expense -- fees, (8) unrealized (gain) loss on derivatives, (9) (gain) loss on sale of assets, (10) income tax expense (benefit), (11) (gain) loss from sale of discontinued operations and (12) income from discontinued operations.

Magnum Hunter defines Adjusted EBITDAX as net income (loss) from continuing operations before (1) net interest expense, (2) (gain) loss on sale of assets, (3) depletion, depreciation, amortization and accretion, (4) impairment of proved oil and gas properties, (5) exploration, (6) non-cash stock compensation expense, (7) non-cash 401k matching expense, (8) non-recurring transaction and other expense, (9) unrealized (gain) loss on investments, (10) income tax expense (benefit) and (11) unrealized (gain) loss on derivatives. Adjusted EBITDAX is not a measure of net income or cash flows as determined by GAAP.

Magnum Hunter defines recurring cash G&A as total general and administrative expenses before (1) non-cash stock compensation and (2) transaction and other non-recurring expense.

Management believes these non-GAAP financial measures facilitate evaluation of the Company's business on a "normalized" or recurring basis and without giving effect to certain non-cash expenses and other items, thereby providing management, investors and analysts with comparative information for evaluating the Company in relation to other oil and gas companies providing corresponding non-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, and that the reconciliations to the closest corresponding GAAP measure should be reviewed carefully.

Certain Definitions

The U.S. Securities and Exchange Commission, which we refer to as the SEC, requires oil and natural gas companies, in filings made with the SEC, to disclose proved reserves, which are those quantities of oil and natural gas that 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.

Magnum Hunter defines probable reserves as 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.

Magnum Hunter defines possible reserves as 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.

About Magnum Hunter Resources Corporation

Magnum Hunter Resources Corporation and subsidiaries are a Houston, Texas based independent exploration and production company engaged in the acquisition, development and production of crude oil, natural gas and natural gas liquids, primarily in the states of West Virginia, Ohio and North Dakota. The Company is presently active in three of the most prolific unconventional shale resource plays in North America, namely the Marcellus Shale, Utica Shale and Williston Basin/Bakken Shale.

Availability of Information on the Company's Website

Magnum Hunter is providing a reminder that it makes available on its website (at www.magnumhunterresources.com) a variety of information for investors, analysts and the media, including the following:

• annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and any amendments to those reports as soon as reasonably practicable after the material is electronically filed with or furnished to the Securities and Exchange Commission;
• the most recent version of the Company's Investor Presentation slide deck;
• announcements of conference calls, webcasts, investor conferences, speeches and other events at which Company executives may discuss the Company and its business and archives or transcripts of such events;
• press releases regarding annual and quarterly earnings, operational developments, legal developments and other matters; and
• corporate governance information, including the Company's corporate governance guidelines, committee charters, code of conduct and other governance-related matters.

Magnum Hunter's goal is to maintain its website as the authoritative portal through which visitors can easily access current information about the Company. Over time, the Company intends for its website to become a primary channel for public dissemination of important information about the Company. Investors, analysts, media and other interested persons are encouraged to visit the Company's website frequently.

Certain information included on the Company's website constitutes forward-looking statements and is subject to the qualifications under the heading "Forward-Looking Statements" below and in the Company's Investor Presentation slide deck.

Forward-Looking Statements

This press release includes "forward-looking statements." All statements other than statements of historical facts included or incorporated herein may constitute forward-looking statements. Actual results could vary significantly from those expressed or implied in such statements and are subject to a number of risks and uncertainties. Although Magnum Hunter believes that the expectations reflected in the forward-looking statements are reasonable, Magnum Hunter can give no assurance that such expectations will prove to be correct. The forward-looking statements involve risks and uncertainties that affect operations, financial performance, and other factors as discussed in filings made by Magnum Hunter with the Securities and Exchange Commission (SEC). Among the factors that could cause results to differ materially are those risks discussed in the periodic reports filed by Magnum Hunter with the SEC, including Magnum Hunter's Annual Report on Form 10-K for the fiscal year ended December 31, 2013, and its Quarterly Reports on Form 10-Q for the fiscal quarters ended after such fiscal year. You are urged to carefully review and consider the cautionary statements and other disclosures made in those filings, specifically those under the heading "Risk Factors." Forward-looking statements speak only as of the date of the document in which they are contained, and Magnum Hunter does not undertake any duty to update any forward-looking statements except as may be required by law.

MAGNUM HUNTER RESOURCES CORPORATION
UNAUDITED RESULTS OF OPERATIONS
(Continuing Operations)
				Three Months Ended  June 30,						Six Months Ended  June 30,
				2014			2013			2014			2013
Oil and natural gas revenue and production
Revenues (in thousands, U.S. Dollars)
	Oil			$	39,839		$	33,122		$	74,111		$	58,694
	Natural gas				25,453			12,810			49,583			21,263
	NGL				12,898			3,651			24,668			4,267
		Total oil and natural gas sales		$	78,190		$	49,583		$	148,362		$	84,224
Production
	Oil (MBbl)				411			392			824			686
	Natural gas (MMcf)				4,898			2,988			9,205			5,084
	NGL (MBoe)				222			81			422			96
		Total (MBoe)			1,449			970			2,781			1,629
	Boe/d				15,923			10,664			15,363			9,002
Average prices (U.S. Dollars)
	Oil (per Bbl)			$	97.02		$	84.57		$	89.93		$	85.52
	Natural gas (per Mcf)			$	5.20		$	4.29		$	5.39		$	4.18
	NGL (per Boe)			$	58.08		$	45.18		$	58.40		$	44.60
		Total average price (per Boe)		$	53.96		$	51.10		$	53.35		$	51.70
Costs and expenses (per Boe)
	Lease operating expense			$	10.24		$	15.68		$	12.51		$	14.05
	Severance tax and marketing			$	4.57		$	4.14		$	4.39		$	4.20
	Exploration expense			$	6.34		$	3.65		$	8.35		$	20.43
	Impairment of proved oil and natural gas property			$	0.11		$	10.27		$	0.06		$	6.12
	General and administrative expense (1)			$	12.93		$	16.86		$	12.23		$	22.31
	Depletion, depreciation and accretion			$	24.81		$	27.18		$	23.50		$	26.80
Other segments (in thousands)
	Natural gas transportation, gathering, processing and marketing revenues			$	48,363		$	13,974		$	80,012		$	29,870
	Natural gas transportation, gathering, processing and marketing expenses			$	44,754		$	13,414		$	74,753		$	26,845
	Oilfield services revenues			$	5,954		$	3,612		$	11,575		$	7,305
	Oilfield services expenses			$	4,089		$	4,066		$	8,036		$	7,401

MAGNUM HUNTER RESOURCES CORPORATION
UNAUDITED CONSOLIDATED BALANCE SHEETS
(In thousands, except share and per share data)
					June 30,  2014			December 31,  2013
ASSETS
CURRENT ASSETS
	Cash and cash equivalents				$	9,120		$	41,713
	Restricted cash					5,000			5,000
	Accounts receivable:
			Oil and natural gas sales			47,723			25,099
			Joint interests and other, net of allowance for doubtful accounts of $252 at June 30, 2014 and $196 at December 31, 2013			40,160			30,582
	Derivative assets					317			608
	Inventory					3,830			7,158
	Investments					10,771			2,262
	Prepaid expenses and other assets					3,054			2,938
	Assets held for sale					1,638			5,366
		Total current assets				121,613			120,726
PROPERTY, PLANT AND EQUIPMENT
	Oil and natural gas properties, successful efforts method of accounting, net					1,328,701			1,224,659
	Gas transportation, gathering and processing equipment and other, net					369,324			289,420
		Total property, plant and equipment, net				1,698,025			1,514,079
OTHER ASSETS
	Deferred financing costs, net of amortization of $12,195 at June 30, 2014 and $9,735 at December 31, 2013					18,358			20,008
	Derivative assets, long-term					123			25
	Intangible assets, net					5,527			6,530
	Goodwill					30,602			30,602
	Assets held for sale					84,935			162,687
	Other assets					4,174			1,994
		Total assets			$	1,963,357		$	1,856,651

MAGNUM HUNTER RESOURCES CORPORATION
UNAUDITED CONSOLIDATED BALANCE SHEETS
(In thousands, except share and per share data)
				June 30,  2014				December 31, 2013
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES
	Current portion of notes payable			$	5,431			$	3,804
	Accounts payable				128,356				107,837
	Accounts payable to related parties				690				23
	Accrued liabilities				55,636				44,629
	Revenue payable				10,039				6,313
	Derivative liabilities				5,709				1,903
	Liabilities associated with assets held for sale				17,961				12,865
	Other liabilities				2,374				6,491
		Total current liabilities			226,196				183,865
NONCURRENT LIABILITIES
	Long-term debt				839,009				876,106
	Asset retirement obligations				16,568				16,163
	Derivative liabilities, long-term				115,727				76,310
	Other long-term liabilities				2,163				2,279
	Long-term liabilities associated with assets held for sale				11,310				14,523
		Total liabilities			1,210,973				1,169,246
COMMITMENTS AND CONTINGENCIES (Note 16)
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 June 30, 2014 and December 31, 2013, with a liquidation preference of $25.00 per share				100,000				100,000
	Series A Convertible Preferred Units of Eureka Hunter Holdings, LLC (the "Eureka Hunter Holdings Series A Preferred Units"), cumulative distribution rate of 8.0% per annum, 10,592,540 and 9,885,048 issued and outstanding as of June 30, 2014 and December 31, 2013, respectively, with a liquidation preference of $214,776 and $200,620 as of June 30, 2014 and December 31, 2013, respectively				149,379				136,675
					249,379				236,675
SHAREHOLDERS' EQUITY
	Preferred Stock of Magnum Hunter Resources Corporation, 10,000,000 shares 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 issued and outstanding as of June 30, 2014 and December 31, 2013, with a liquidation preference of $50.00 per share			221,244				221,244
		Series E Cumulative Convertible Preferred Stock ("Series E Preferred Stock"), cumulative dividend rate 8.0% per annum, 12,000 authorized, 3,803 issued and 3,722 outstanding as of June 30, 2014 and December 31, 2013, with a liquidation preference of $25,000 per share			95,069				95,069
	Common stock, $0.01 par value per share, 350,000,000 shares authorized, and 200,299,799 and 172,409,023 issued, and 199,384,847 and 171,494,071 outstanding as of June 30, 2014 and December 31, 2013, respectively				2,003				1,724
	Additional paid in capital				924,185				733,753
	Accumulated deficit				(742,830	)			(586,365	)
	Accumulated other comprehensive loss				(983	)			(19,901	)
	Treasury Stock, at cost:
		Series E Preferred Stock, 81 shares as of June 30, 2014 and December 31, 2013			(2,030	)			(2,030	)
		Common stock, 914,952 shares as of June 30, 2014 and December 31, 2013			(1,914	)			(1,914	)
	Total Magnum Hunter Resources Corporation shareholders' equity				494,744				441,580
	Non-controlling interest				8,261				9,150
		Total shareholders' equity			503,005				450,730
		Total liabilities and shareholders' equity		$	1,963,357			$	1,856,651

MAGNUM HUNTER RESOURCES CORPORATION
UNAUDITED CONSOLIDATED STATEMENT OF OPERATIONS
(In thousands, except share and per share data)
				Three Months Ended  June 30,								Six Months Ended  June 30,
				2014				2013				2014				2013
REVENUES AND OTHER
	Oil and natural gas sales			$	78,190			$	49,583			$	148,362			$	84,224
	Natural gas transportation, gathering, processing, and marketing				48,363				13,974				80,012				29,870
	Oilfield services				5,954				3,612				11,575				7,305
	Other revenue				9				739				11				743
		Total revenue			132,516				67,908				239,960				122,142
OPERATING EXPENSES
	Lease operating expenses				14,836				15,213				34,792				22,881
	Severance taxes and marketing				6,627				4,016				12,201				6,848
	Exploration				9,187				3,546				23,216				33,279
	Impairment of proved oil and gas properties				158				9,968				158				9,968
	Natural gas transportation, gathering, processing, and marketing				44,754				13,414				74,753				26,845
	Oilfield services				4,089				4,066				8,036				7,401
	Depletion, depreciation, amortization and accretion				35,953				26,375				65,361				43,663
	Loss (gain) on sale of assets, net				(687	)			1,183				2,772				1,164
	General and administrative				18,738				16,364				34,010				36,341
		Total operating expenses			133,655				94,145				255,299				188,390
OPERATING LOSS					(1,139	)			(26,237	)			(15,339	)			(66,248	)
OTHER INCOME (EXPENSE)
	Interest income				41				81				86				138
	Interest expense				(20,434	)			(18,793	)			(44,283	)			(37,494	)
	Gain (loss) on derivative contracts, net				(42,836	)			6,400				(42,489	)			(1,091	)
	Other expense (income)				264				(465	)			20				(681	)
		Total other expense, net			(62,965	)			(12,777	)			(86,666	)			(39,128	)
LOSS FROM CONTINUING OPERATIONS BEFORE INCOME TAX					(64,104	)			(39,014	)			(102,005	)			(105,376	)
	Income tax benefit				--				39,300				--				44,199
INCOME (LOSS) FROM CONTINUING OPERATIONS, NET OF TAX					(64,104	)			286				(102,005	)			(61,177	)
	Income (loss) from discontinued operations, net of tax				3,889				(7,684	)			7,251				9,079
	Gain (loss) on disposal of discontinued operations, net of tax				(5,212	)			172,452				(32,374	)			172,452
NET INCOME (LOSS)					(65,427	)			165,054				(127,128	)			120,354
	Net loss attributed to non-controlling interests				780				386				889				889
INCOME (LOSS) ATTRIBUTABLE TO MAGNUM HUNTER RESOURCES CORPORATION					(64,647	)			165,440				(126,239	)			121,243
	Dividends on preferred stock				(15,330	)			(14,129	)			(30,226	)			(27,617	)
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS				$	(79,977	)		$	151,311			$	(156,465	)		$	93,626
	Weighted average number of common shares outstanding, basic and diluted				184,479,312				169,690,633				178,346,940				169,657,806
	Loss from continuing operations per share, basic and diluted			$	(0.42	)		$	(0.08	)		$	(0.74	)		$	(0.52	)
	Income (loss) from discontinued operations per share, basic and diluted				(0.01	)			0.97				(0.14	)			1.07
NET INCOME (LOSS) PER COMMON SHARE, BASIC AND DILUTED				$	(0.43	)		$	0.89			$	(0.88	)		$	0.55
AMOUNTS ATTRIBUTABLE TO MAGNUM HUNTER RESOURCES CORPORATION
	Income (loss) from continuing operations, net of tax			$	(63,324	)		$	672			$	(101,116	)		$	(60,288	)
	Income (loss) from discontinued operations, net of tax				(1,323	)			164,768				(25,123	)			181,531
		Net income (loss)		$	(64,647	)		$	165,440			$	(126,239	)		$	121,243

MAGNUM HUNTER RESOURCES CORPORATION
UNAUDITED CONSOLIDATED STATEMENT OF CASH FLOWS
(In thousands, except share and per share data)
					Six Months Ended June 30,
					2014				2013
CASH FLOWS FROM OPERATING ACTIVITIES
	Net income (loss)				$	(127,128	)		$	120,354
	Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
		Depletion, depreciation, amortization and accretion				65,361				73,078
		Exploration				22,489				34,168
		Impairment of proved oil and gas properties				158				16,034
		Impairment of other operating assets				616				263
		Share-based compensation				3,375				8,699
		Cash paid for plugging wells				(27	)			--
		Loss (gain) on sale of assets				35,761				(206,082	)
		Unrealized loss on derivative contracts				37,938				786
		Unrealized loss on investments				403				1,152
		Amortization and write-off of deferred financing costs and discount on Senior Notes included in interest expense				7,740				2,758
		Deferred tax benefit				--				(6,475	)
	Changes in operating assets and liabilities:
			Accounts receivable, net			(15,588	)			7,760
			Inventory			3,475				(459	)
			Prepaid expenses and other current assets			(1,147	)			(802	)
			Accounts payable			(23,817	)			24,099
			Revenue payable			5,204				(1,204	)
			Accrued liabilities			3,934				(261	)
Net cash provided by operating activities						18,747				73,868
CASH FLOWS FROM INVESTING ACTIVITIES
	Capital expenditures and advances					(257,469	)			(277,492	)
	Change in restricted cash					--				1,500
	Change in deposits and other long-term assets					(2,406	)			154
	Proceeds from sales of assets					74,503				380,036
Net cash provided by (used in) investing activities						(185,372	)			104,198
CASH FLOWS FROM FINANCING ACTIVITIES
	Net proceeds from sale of common shares					178,575				--
	Net proceeds from sale of preferred shares					--				10,181
	Equity issuance costs					--				(109	)
	Proceeds from sale of Eureka Hunter Holdings Series A Preferred Units					11,956				19,600
	Proceeds from exercise of warrants and options					8,761				--
	Preferred stock dividend					(23,646	)			(10,424	)
	Repayments of debt					(197,216	)			(327,076	)
	Proceeds from borrowings on debt					161,616				105,991
	Deferred financing costs					(6,042	)			(701	)
	Change in other long-term liabilities					(13	)			(52	)
	Net cash provided by financing activities					133,991				(202,590	)
Effect of changes in exchange rate on cash						41				(357	)
NET DECREASE IN CASH AND CASH EQUIVALENTS						(32,593	)			(24,881	)
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD						41,713				57,623
CASH AND CASH EQUIVALENTS, END OF PERIOD					$	9,120			$	32,742

Non-GAAP Financial Measures and Reconciliations
Adjusted Loss per Common Share Reconciliation			Three Months Ended								Six Months Ended
			June 30,								June 30,
($ in thousands)			2014				2013				2014				2013
Net income (loss) attributable to common shareholders - reported			$	(79,977	)		$	151,311			$	(156,465	)		$	93,626
Non-recurring and non-cash items:
	Exploration expense		$	9,187			$	3,546			$	23,216			$	33,279
	Impairment of proved oil and gas properties		$	158			$	9,968			$	158			$	9,968
	Impairment of other operating assets		$	616			$	-			$	616			$	-
	Non-cash: stock compensation expense		$	2,313			$	2,449			$	3,374			$	8,699
	Non-cash: 401k matching expense		$	298			$	125			$	596			$	250
	Non-recurring transaction and other expense		$	6,073			$	9,161			$	13,163			$	15,051
	Unrealized (gain) loss on investments		$	660			$	546			$	962			$	1,152
	Interest expense - fees		$	2,712			$	1,693			$	6,333			$	2,550
	Unrealized (gain) loss on derivatives		$	40,569			$	(7,661	)		$	37,938			$	786
	(Gain) loss on sale of assets		$	(687	)		$	1,183			$	2,772			$	1,164
	Income tax (benefit)		$	-			$	(39,300	)		$	-			$	(44,199	)
	(Gain) loss from sale of discontinued operations		$	5,212			$	(172,452	)		$	32,374			$	(172,452	)
	Income from discontinued operations		$	(3,889	)		$	7,684			$	(7,251	)		$	(9,079	)
Total non-recurring and non-cash items			$	63,222			$	(183,058	)		$	114,251			$	(152,831	)
Net income (loss) attributable to common shareholders - as adjusted			$	(16,755	)		$	(31,747	)		$	(42,214	)		$	(59,205	)
Net income (loss) attributable to common shareholders - as adjusted			$	(0.09	)		$	(0.19	)		$	(0.24	)		$	(0.35	)
Weighted Average Shares				184,479,312				169,690,633				178,346,940				169,657,806

Adjusted EBITDAX Reconciliation
		Three Months Ended								Six Months Ended
		June 30,								June 30,
($ in thousands)		2014				2013				2014				2013
Net income (loss) from continuing operations		$	(64,104	)		$	286			$	(102,005	)		$	(61,177	)
Net Interest expense		$	20,393			$	18,712			$	44,197			$	37,356
(Gain) loss on sale of assets		$	(687	)		$	1,183			$	2,772			$	1,164
Depletion, depreciation, amortization and accretion		$	35,953			$	26,375			$	65,361			$	43,663
Impairment of proved oil and gas properties		$	158			$	9,968			$	158			$	9,968
Impairment of other operating assets		$	616			$	-			$	616			$	-
Exploration expense		$	9,187			$	3,546			$	23,216			$	33,279
Non-cash stock compensation expense		$	2,313			$	2,449			$	3,374			$	8,699
Non-cash 401k matching expense		$	298			$	125			$	596			$	250
Non-recurring transaction and other expense		$	6,073			$	9,161			$	13,163			$	15,051
Unrealized (gain) loss on investments		$	660			$	546			$	962			$	1,152
Income tax (benefit)		$	-			$	(39,300	)		$	-			$	(44,199	)
Unrealized (gain) loss on derivatives		$	40,569			$	(7,661	)		$	37,938			$	786
Total Adjusted EBITDAX		$	51,429			$	25,390			$	90,348			$	45,992

Recurring Cash G&A Reconciliation
			Three Months Ended						Six Months Ended
			June 30,						June 30,
($ in thousands)			2014			2013			2014			2013
Total G&A			$	18,738			16,364			34,010			36,341
Adjustments:
	Non-cash stock compensation		$	2,313		$	2,449		$	3,374		$	8,699
	Acquisition and other non-recurring expense		$	6,073		$	9,161		$	13,163		$	15,051
Recurring Cash G&A			$	10,352		$	4,754		$	17,473		$	12,591
Recurring Cash G&A Per BOE			$	7.14		$	4.90		$	6.28		$	7.73