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