HOUSTON, TX — (Marketwired) — 11/07/14 — 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 and nine months ended September 30, 2014. The Company plans to file its Form 10-Q for the quarter ended September 30, 2014 with the Securities and Exchange Commission later today. Highlights of the Company–s financial and operating results for the third quarter include the following:
Magnum Hunter reported an increase in oil and gas revenues of 5.8% to $62.5 million for the three months ended September 30, 2014, compared with $59.1 million for the three months ended September 30, 2013. The increase in oil and gas revenues resulted principally from 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.
The Company reported a net loss of ($136.2) million attributable to common shareholders, or ($0.68) per basic and diluted common share outstanding, for the three months ended September 30, 2014, compared with net loss of ($311.3) million, or ($1.83) per basic and diluted common share outstanding, for the three months ended September 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 September 30, 2014 was ($32.0) million or ($0.16) per basic and diluted common share outstanding (see Non-GAAP Financial Measures and Reconciliations below).
For the three months ended September 30, 2014, Magnum Hunter–s Adjusted Earnings Before Interest, Income Taxes, Depreciation, Amortization and Exploration (“Adjusted EBITDAX”) was $34.1 million, compared with $31.8 million for the three months ended September 30, 2013 (See Non-GAAP Financial Measures and Reconciliations below), an increase of 7.1%. The increase in Adjusted EBITDAX was due primarily to 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 and lower lease operating expenses (“LOE”) per barrel of oil equivalent (“BOE”). This is after completing divestitures so far this year in excess of $200 million in proceeds which represented approximately 12,480 MCFE per day (2,080 BOE per day) of production. The decrease in LOE per BOE was due primarily to lower recurring costs in the Appalachian and Williston Basins and lower non-recurring well work-over expenses in the Williston Basin. General and administrative expenses for the three months ended September 30, 2014 decreased 19.2% to $19.3 million from $23.9 million for the three months ended September 30, 2013, due primarily to (i) lower professional fees and transactional expenses during the quarter and (ii) decreases in expenses related to third-party consultants (See Non-GAAP Financial Measures and Reconciliations below). The Company expects that its future reliance on third-party consultants will continue to decrease each quarter in the foreseeable future.
Oil and gas production increased 49% for the three months ended September 30, 2014 to 1.505 million BOE (“MMBoe”) or an average of 98,166 MCFE per day (“Mcfe/d”) (16,361 BOE per day (“Boe/d”)) (41.0% oil/NGLs), compared with production of 1.010 MMBoe or an average of 10,977 Boe/d for the three months ended September 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 Shale and Utica Shale plays and (ii) further development in the Williston Basin. This is after the loss of approximately 7,140 MCFE per day (1,190 BOE per day) from divestitures during the first six months of 2014.
To-date in 2014, Magnum Hunter has completed a number of asset divestitures resulting in aggregate net proceeds in excess of $200 million, before customary purchase price adjustments. The Company (1) divested its remaining South Texas properties, located in Atascosa County, to New Standard Energy, an Australian public company, for $24.5 million ($15.0 million in cash and $9.5 million in stock of New Standard Energy), (2) monetized its properties in Alberta, Canada for CAD $9.5 million in cash (approximately US $8.7 million), (3) divested its properties in the Tableland Field in Saskatchewan, Canada for CAD $75 million in cash (approximately US $67.5 million), (4) sold its interests in the Vadis field in Lewis County, West Virginia for $0.5 million in cash, (5) divested certain of its non-operated Bakken Shale properties in Divide County, North Dakota for $23.5 million in cash and (6) sold certain additional non-operated Bakken Shale properties in Divide County for $84.8 million in cash. The Company continues to actively focus on divesting certain assets. The Company has made a strategic decision to evaluate the monetization of its remaining Divide County, North Dakota operated and non-operated properties and reallocate 100% of its financial resources to its core operations in West Virginia and Ohio.
Magnum Hunter–s total upstream and midstream capital expenditures, including leasehold acquisitions, were $189.6 million for the three months ended September 30, 2014. Total upstream capital expenditures for the three months ended September 30, 2014 were $84.9 million, consisting of $15.9 million for the Williston Basin and $69.0 million for the Appalachian region. Leasehold acquisition expenditures for the three months ended September 30, 2014 were $16.2 million, primarily for leasehold acreage in Washington, Noble and Monroe Counties, Ohio and Tyler, Ritchie and Wetzel Counties, West Virginia. Total midstream capital expenditures for the period were $88.5 million.
Magnum Hunter believes that its internally generated cash flows, borrowing base availability (and potential future borrowing base increases) under its Senior Revolving Credit Facility, and additional liquidity sources, including but not limited to proceeds from possible asset sales and potential capital markets transactions, will provide it with sufficient liquidity to fund the remainder of its fiscal 2014 capital budget. As of November 4, 2014, the Company had total liquidity of approximately $136.7 million, comprised of approximately $89.0 million of cash and $47.7 million of borrowing availability under its Senior Revolving Credit Facility. To further enhance its liquidity, the Company is actively pursuing sales of additional assets located predominately located in North Dakota.
During the quarter ended September 30, 2014, the Company commenced or participated in the drilling of a total of 10 gross (5.4 net) wells and completed 11 gross (5.5 net) wells. The Company had a 100% success rate on the wells in which it had a working interest that were completed in the third quarter of 2014.
The table below summarizes the Company–s gross drilling activities by area for the third quarter of 2014:
Currently, the Company is running five drilling rigs (three operated rigs and two non-operated rigs). Of these five rigs, four rigs (three operated rigs and one non-operated rig) are drilling wells in the Marcellus Shale and Utica Shale in West Virginia and Ohio, and one non-operated rig is drilling wells in the Williston Basin/Bakken Shale in Divide County, North Dakota.
Marcellus Shale and Utica Shale
During the third quarter of 2014, the Company drilled five gross (3.5 net) wells and completed four gross (four net) wells in the Marcellus Shale and Utica Shale plays. The Company–s net production in the third quarter of 2014 attributable to the operations of Triad Hunter, LLC, a wholly-owned subsidiary of the Company, averaged approximately 11,019 BOE per day (66,112 MCFE per day).
On the WVDNR Pad in Wetzel County, West Virginia, the Company–s WVDNR #1207, #1208 and #1209 wells (~100% working interest) began flowing to sales on April 2, 2014. The wells were shut-in on May 31, 2014 to prepare the WVDNR Pad for drilling four additional down-dip laterals off the same pad site. For the seven-day period prior to shut-in, the WVDNR #1207, #1208 and #1209 wells had an average daily production (net) of approximately 1,575 BOE (9,450 MCFE). The Company–s WVDNR #1410, #1411, #1412 and #1413 wells (~100% working interest) have been drilled and cased with an approximate true vertical depth of 7,500 feet. The lateral lengths for the WVDNR #1410, #1411, #1412 and #1413 wells are 4,493 feet, 4,640 feet, 4,663 feet and 5,850 feet, respectively. The Company anticipates commencing completion operations next week and that all these WVDNR Pad wells will be put online and will be flowing to sales through the Eureka Hunter Pipeline system in December 2014.
On the Stewart Winland Pad in Tyler County, West Virginia, the Company–s first Utica Shale well (the Stewart Winland #1300U) (100% working interest) drilled and completed in the State of West Virginia, and the most southeastern well in the entire play, was drilled to a true vertical depth of 10,825 feet with a 5,289 foot horizontal lateral, and was successfully fraced with 22 stages. The Stewart Winland #1300U tested at a peak rate of 46.5 MMCF of natural gas per day (~7,750 BOE per day) on an adjustable rate choke with 7,810 psi FCP. The Stewart Winland #1300U is currently shut-in pending the receipt of certain air quality permits from the State of West Virginia anticipated in several weeks. The Company has drilled and cased three ~100% owned Marcellus Shale wells on the Stewart Winland Pad, the Stewart Winland #1301M, #1302M and #1303M. The Stewart Winland #1301M was drilled and cased to a true vertical depth of 6,155 feet with a 5,762 foot horizontal lateral, and successfully fraced with 27 stages. The well tested at a peak rate of 17.0 MMCFE of natural gas per day (~23% condensate and ~25% NGL) on an adjustable rate choke. The Stewart Winland #1302M was drilled and cased to a true vertical depth of 6,147 feet with a 5,676 foot horizontal lateral, and successfully fraced with 29 stages. The well tested at a peak rate of 17.1 MMCFE of natural gas per day (~19% condensate and ~26% NGL) on an adjustable rate choke. The Stewart Winland #1303M was drilled and cased to a true vertical depth of 6,149 feet with a 5,762 foot horizontal lateral, and successfully fraced with 29 stages. The well tested at a peak rate of 16.8 MMCFE of natural gas per day (~20% condensate and ~26% NGL) on an adjustable rate choke. These wells were ready for sales as of September 30, 2014. The Company is waiting on certain air quality permits from the State of West Virginia anticipated in several weeks to begin flowing these Marcellus Shale wells to sales.
On the Stalder Pad in Monroe County, Ohio, the Company drilled and completed its first dry gas well, the Stalder #3UH (47% working interest), and placed it on production in February 2014. Initial flow tests peaked at a rate of 32.5MMCF (approximately 5.4MBoe) of natural gas per day on an adjustable rate choke with 4,300 psi FCP. The Stalder #3UH was drilled to a true vertical depth of 10,653 feet with a 5,050 foot horizontal lateral, and successfully fraced with 20 stages. The well is currently shut-in due to the drilling by the Company of three additional Utica Shale wells (#6UH, #7UH and #8UH) on the Stalder Pad. The Stalder #6UH, #7UH and #8UH have been drilled and cased to TD and the Company commenced completion operations this week. The Stalder #6UH was drilled to a true vertical depth of 10,660 and a 5,746 foot lateral with 24 anticipated frac stages. The Stalder #7UH was drilled to a true vertical depth of 10,660 and a 6,053 foot lateral with 25 anticipated frac stages. The Stalder #8UH was drilled to a true vertical depth of 10,660 and a 6,228 foot lateral with 26 anticipated frac stages.
On the Ormet Pad in Monroe County, Ohio, the Company has plans to drill a total of five down-dip Marcellus Shale laterals and four down-dip Utica Shale laterals. In the process of drilling the first of three Utica laterals, the Company encountered a zone of increased pressure and porosity at about 1,200 feet into the lateral section. The Company has run 5 1/2″ casing with a retrievable packer and is in the process of open hole testing the well. The Company–s plan for the remainder of the Utica laterals will be dependent upon the flow test results from this first Ormet #8-15UH well.
Williston Basin
During the third quarter of 2014, the Company participated in the spudding of five gross (1.9 net) wells and the completion of seven gross (1.5 net) wells in Divide County, North Dakota.
The Marauder 2413-1H well was drilled and cased to a measured depth of 18,033 feet (horizontal lateral length of 9,244 feet), fraced with 25 stages and placed on production October 7, 2014. The 24 hour initial production rate was 1,206 BOEPD. Magnum Hunter owns a 17.5% working interest.
The Marauder 2413-3H well was drilled and cased to a measured depth of 18,399 feet (horizontal lateral length of 9,619 feet), fraced with 25 stages and placed on production October 9, 2014. The 24 hour initial production rate was 838 BOEPD. Magnum Hunter owns a 17.5% working interest.
The Stingray 1819-6H well was drilled and cased to a measured depth of 18,794 feet (horizontal lateral length of 9,944 feet), fraced with 25 stages and placed on production October 22, 2014. The 24 hour initial production rate was 1,213 BOEPD. Magnum Hunter owns a 46.3% working interest.
The Charger 0706-8H well was drilled and cased to a measured depth of 18,371 feet (horizontal lateral length of 9,526 feet), fraced with 25 stages and placed on production October 23, 2014. The 24 hour initial production rate was 687 BOEPD. Magnum Hunter owns a 47.7% working interest.
A third party has been engaged to gather and transport oil from certain of our non-operated wells in Divide County to the Colt Hub in Epping, North Dakota 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 December 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. On Samson Resources– Bonneville Pad, all four receipt points on the north lateral and three receipt points on the south lateral are operational. Construction is continuing on the south lateral tie-ins. Construction on the truck terminal started in October 2014. All of the equipment has been ordered and delivery is expected starting in the first week of December 2014. The truck terminal is expected to be operational in January 2015.
Construction of the cross-border gas gathering pipeline from Steppe Resources– Battery in the Tableland Field in Saskatchewan, Canada to Oneok Inc.–s gas gathering system connection in Divide County, North Dakota was completed in early September 2014. Approximately 600 Mcf/d of associated gas from Steppe Resources– wells in the Tableland Field started flowing through the pipeline into Oneok–s gas gathering system in Divide County in September 2014. The associated gas from these wells that flows through the pipeline will be applied towards the Company–s Oneok gas volume commitment.
As of September 30, 2014, the operators of the Company–s properties in Divide County have tied in approximately 202 gross wells into the Oneok, Inc. gas gathering system in Divide County, and production and revenues from the gathering of associated gas from the tied-in wells are growing monthly. Approximately 70% of the wells have been electrified.
Eureka Hunter
In September 2014, the Eureka Hunter Pipeline gas gathering system achieved a peak throughput rate of approximately 325,000 MMBtu per day. During the third quarter of 2014, the Eureka Hunter Pipeline system averaged 223,708 MMBtu per day. During September 2014, Triad Hunter, LLC produced approximately 29% of the volumes that flowed through the Eureka Hunter Pipeline system.
Eureka Hunter Pipeline shippers are currently limited in respect of capacity through the Mobley gas processing facility in West Virginia and downstream on Equitrans. A fourth Mobley plant is expected to come on-line in December 2014, adding 200,000 Mcf of processing, and Equitrans is adding compression to further expand capacity downstream of Mobley. Eureka Hunter Pipeline is also adding additional takeaway capacity at Mobley through the construction of a new residue line to TCO (Colombia Gas). This new residue line will provide a competitive advantage for producers previously limited to one takeaway pipeline at Mobley and its related gas markets.
Eureka Hunter Pipeline plans to add an interconnect into Natrium (Blue Racer Midstream) to eventually increase its Marcellus Shale wet deliveries on the system by over 400 MMcf/d plus. This interconnect is expected to be completed by year-end.
Eureka Hunter Pipeline expects to add significant throughput volumes from a combination of Triad Hunter–s new wells described above and other third parties– production during the remainder 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 gathering of dry gas from the Utica Shale will mark a significant milestone for Eureka Hunter Pipeline 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 Pipeline 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 various stages of construction and completion, utilizing three different construction crews. With the completion of expansion projects currently under construction, the Company expects the Eureka Hunter Pipeline system to have a throughput capacity of approximately 1.5 Bcf/d within the next year.
Eureka Hunter Pipeline 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 gas processing facility. The reduced line pressure also helps all producers move gas more easily into the Eureka Hunter Pipeline system.
Mr. Gary C. Evans, Chairman of the Board and Chief Executive Officer of Magnum Hunter, commented, “Our decision to divest predominately all of our crude oil properties over the past 18 months at an average of over $100,000 a flowing barrel appears to have been a wise decision in the current mid $70 WTI crude oil environment we are experiencing today. Therefore, we are now predominately a natural gas development company. We are bullish on natural gas prices long term and weather will be the predominate determining factor for prices over the next 12 months. With less than two months remaining in the year, we remain confident with our 32,500 BOE (195 MMCFE) exit rate guidance. This tremendous amount of new production will be sustained in calendar year 2015 because our planned drilling next year will be on new pads where shut-ins will not occur. The recent closing with our new strategic partner at Eureka Hunter sets in motion our goal to take the entity public as a new MLP in the first half of next year on this exciting asset that continues to grow in size and throughput due to our own company drilling success, but also due to our customers who continue to add new production in this region. With our recent revolver/term loan closing, we have ensured our liquidity is fixed and available, despite commodity prices.”
This release contains certain financial measures that are non-GAAP measures. Magnum Hunter has 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 net income (loss) as reported net income (loss) attributable to common shareholders, before non-recurring and non-cash items which include (1) exploration expense, (2) impairment of proved oil and gas properties, (3) impairment of other operating assets, (4) non-cash stock compensation expense, (5) non-cash 401k matching expense, (6) non-recurring transaction and other expense, (7) unrealized (gain) loss on investments, (8) interest expense — fees, (9) unrealized (gain) loss on derivatives, (10) (gain) loss on sale of assets, (11) income tax expense (benefit), (12) (gain) loss from sale of discontinued operations and (13) 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) impairment of other operating assets, (6) exploration expense, (7) non-cash stock compensation expense, (8) non-cash 401k matching expense, (9) non-recurring transaction and other expense, (10) unrealized (gain) loss on investments, (11) income tax expense (benefit) and (12) 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 the reconciliations to the closest corresponding GAAP measure should be reviewed carefully.
The U.S. Securities and Exchange Commission, referred 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.
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.
Magnum Hunter is providing a reminder that it makes available on its website (at ) 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 SEC;
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.
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 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.
AVP, Investor Relations
(832) 203-4560