HOUSTON, TX — (Marketwire) — 10/13/11 — Magnum Hunter Resources Corporation (NYSE: MHR) (NYSE Amex: MHR-PrC) (NYSE Amex: MHR-PrD) (the “Company” or “Magnum Hunter”) provided a drilling, operational, and production update today on the activities of its wholly-owned subsidiary, Triad Hunter LLC (“Triad Hunter”), in the Appalachian Region. This includes the liquids-rich window of the Marcellus Shale unconventional resource play located across approximately 58,048 net acres predominately in Northwestern West Virginia and Southeastern Ohio. This update also includes the Huron Shale and Weir Oil Sands formations of the Company–s Kentucky operations. Significant highlights for the third quarter of 2011 include:
The WVDNR #1102, located in Wetzel County, West Virginia, was drilled to a measured depth of 12,517 feet (horizontal lateral length of 4,950 feet) and is a 100% working interest owned well by Triad Hunter. The well was fraced with 16 stages. The WVDNR# 1102 is currently testing into a sales pipeline at an initial flowing production rate of 10.0 MMcfe per day (9.9 MMcf per day of natural gas, 30 Bbls of natural gas liquids per day and 215 Bbls of water per day) on an adjustable choke with 1,655 psi FCP.
The WVDNR #1103, located in Wetzel County, West Virginia, was drilled to a measured depth of 12,335 feet (horizontal lateral length of 4,875 feet) and is a 100% working interest well owned by Triad Hunter. The well was fraced with 16 stages. The WVDNR #1103 tested at an initial flowing production rate of 10.5 MMcfe per day (10.4 MMcf per day of natural gas, 20 Bbls of natural gas liquids per day and 100 Bbl–s of water per day) on an adjustable choke with 1,790 psi FCP.
The WVDNR #1104, located in Wetzel County, West Virginia, was drilled to a measured depth of 11,864 feet (horizontal lateral length of 4,100 feet) and is a 100% working interest well owned by Triad Hunter. The well was fraced with 16 stages. The WVDNR #1104 tested at an initial flowing production rate of 10.4 MMcfe per day (9.56 MMcf per day of natural gas, 74 Bbls of natural gas liquids per day and 300 Bbls of water per day) on an adjustable choke with 1,450 psi FCP.
All of these Marcellus wells were tested and are currently producing on a capacity constrained basis due to volume limitations of the existing midstream infrastructure. The Company expects these constraints to be completely alleviated on or before October 31 upon the completion of new pipeline construction and installation of additional production capacity.
The capital budget for the Appalachian Division for full fiscal year 2011 remains at approximately $70 million (27.5% of the total capex budget) to drill 37 gross wells (22 net wells). This includes approximately $65 million for 17 gross wells (15.5 net) targeting the liquids-rich Marcellus Shale play of Northwestern West Virginia and Southeastern Ohio. Approximately $5 million is scheduled to be spent principally for the drilling 20 gross wells (6.5 net wells) targeting the Huron Shale and Weir Oil Sands located in Kentucky. Magnum Hunter currently estimates the Appalachian Division will achieve a year-end 2011 production exit rate of approximately 6,000 Boe per day and is currently producing in excess of 5,000 Boe per day.
Since completing its first Marcellus Shale well in December 2010, through September 2011, our Company has drilled and completed 11.0 gross wells (9.5 net wells) in the Marcellus Shale. Triad Hunter has an additional 5 gross wells (5.0 net wells) planned to be drilled and completed before year-end 2011. Therefore, the Company anticipates having a total of 16 gross Marcellus Shale wells (14.5 net wells) on line and flowing to sales on or before December 31, 2011.
In addition to the Company–s Marcellus drilling program, 7 gross wells (7 net wells) have been drilled in Kentucky principally to maintain our large acreage position of approximately 300,000 mineral acres. These wells are comprised of four Weir Oil wells, two in the Arch Field and two in the Amvest Field, and three Lower Huron Shale wells, two in the Fonde Field, and one in the Amvest Field. The Company anticipates employing two drillings rigs for the remainder of the year to drill and complete a minimum of 17 gross wells in Kentucky.
Mr. Jim Denny, President of Triad Hunter, LLC, commented, “During the third quarter of fiscal year 2011, the Appalachian Division drilled, completed and tested three very successful liquids-rich Marcellus Shale wells on our Northwestern West Virginia lease acreage. As we have experienced in other operating divisions within Magnum Hunter, the more history and experience we gain in our regional development, we are obtaining better production results. A combination of longer laterals, more frac stages, and certain modifications to downhole equipment has led to consistent new well completions ranging from 5.0 – 10.0 MMcfepd per well in the Marcellus Shale. Our existing mineral lease acreage position appears to be some of the best in the entire Marcellus Shale. When one compares internal rates of return on capital deployed, our high Btu equivalent in our natural gas stream provides economics not seen elsewhere. Coupled with our 100% owned Eureka Hunter Pipeline and its recent October 5, 2011 announcement of its processing initiative with MarkWest Liberty Midstream & Resources LLC, we anticipated a pricing uplift of $1.00 – $1.25 per Mcfe sold for Triad Hunter–s equity natural gas production. Additionally, we expect to book new reserves related to these liquids at year-end. We have plenty of running room for many years to come with 290 net drilling locations currently identified across our 58,048 net leasehold acreage position. Our Company–s in-house reservoir engineers have identified net resource potential of 309 Million Boe over our entire Appalachian acreage position.”
Magnum Hunter Resources Corporation and subsidiaries are a Houston, Texas based independent exploration and production company engaged in the acquisition, development and production of oil and natural gas, primarily in the states of West Virginia, Kentucky, Ohio, Texas, and North Dakota and in Saskatchewan, Canada. The Company is presently active in three of the most prolific shale resource plays in North America, namely the Marcellus Shale, Eagle Ford Shale and Williston Basin/Bakken Shale.
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Resource Potential. “Resource Potential” includes volumes attributable both to “possible reserves,” a reserve classification used in both the United States and Canada, and to “contingent resources,” a Canadian classification. The estimated net resource potential of 309 MMBOE attributable to the Company–s entire Appalachian acreage position as of June 30, 2011 consisted of an estimated 265 MMBOE of possible reserves(1) and 44 MMBOE of the Company–s best estimate of contingent resources.(2)
(1) Magnum Hunter–s estimated proved, probable and possible reserves attributable to its entire Appalachian acreage position as of June 30, 2011 consisted of the following:
(2) For definitions of “Contingent Resources” and “best estimate,” see “Contingent Resources” and “Contingent Resources – Uncertainty Categories” below.
Reserves. The U.S. Securities and Exchange Commission (“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. The SEC defines (i) “probable reserves” as 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 and (ii) “possible reserves” as those additional reserves that are less certain to be recovered than probable reserves. Under Canadian rules, “possible reserves” are those reserves that are less certain to be recovered than probable reserves. Under such Canadian rules there is at least a 10% probability that the quantities actually recovered will equal or exceed the sum of proved plus probable plus possible reserves.
Contingent Resources. “Contingent resources” are defined in the Canadian Oil and Gas Evaluation Handbook as “those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies. Contingencies may include factors such as economic, legal, environmental, political and regulatory matters or a lack of markets. It is also appropriate to classify as contingent resources the estimated discovered recoverable quantities associated with a project in the early evaluation stage.”
The term “contingent resources” is a broader description of potentially recoverable volumes than proved, probable and possible reserves, as defined by the SEC regulations. Estimates of contingent resources are by their nature more speculative than estimates of proved reserves and accordingly are subject to substantially greater risk of actually being realized by the Company. The estimate of contingent resources contained herein is as of June 30, 2011. We believe our estimates of contingent resources are reasonable, but such estimates have not been reviewed by independent engineers. Estimates of contingent resources may change significantly as development provides additional data, and actual quantities that are ultimately recovered may differ substantially from prior estimates. There is no certainty that it will be commercially viable for Magnum Hunter to produce any portion of its contingent resources or that Magnum Hunter will produce any portion of the volumes currently classified as contingent resources. The primary contingencies which currently prevent the classification of Magnum Hunter–s disclosed contingent resources as reserves consist of current uncertainties around the specific scope and timing of project development, commercial recovery being dependent on technology under development, the absence of a reasonable assessment of future economics meeting defined investment and operating criteria, other economic criteria, the uncertainty regarding marketing plans for production from the subject areas, improved estimation of project costs, capital costs required to render production economic, applicable regulatory considerations, pricing and supply costs. There are a number of inherent risks and contingencies associated with the development of these resources, including commodity price fluctuations, project costs, receipt of regulatory approvals and those other risks and contingencies described above and under “Risk Factors” in the our Form 10-K/A dated March 15, 2011, a copy of which is filed with the SEC and is available at .
Contingent Resources – Uncertainty Categories. Under the applicable Canadian rules, contingent resources are estimated using a “low estimate,” “best estimate,” or “high estimate.” These terms are defined as follows:
“Low Estimate”: This is considered to be a conservative estimate of the quantity that will actually be recovered. It is likely that the actual remaining quantities recovered will exceed the low estimate. If probabilistic methods are used, there should be at least a 90 percent probability (P90) that the quantities actually recovered will equal or exceed the low estimate.
“Best Estimate”: This is considered to be the best estimate of the quantity that will actually be recovered. It is equally likely that the actual remaining quantities recovered will be greater or less than the best estimate. If probabilistic methods are used, there should be at least a 50 percent probability (P50) that the quantities actually recovered will equal or exceed the best estimate.
“High Estimate”: This is considered to be an optimistic estimate of the quantity that will actually be recovered. It is unlikely that the actual remaining quantities recovered will exceed the high estimate. If probabilistic methods are used, there should be at least a 10 percent probability (P10) that the quantities actually recovered will equal or exceed the high estimate.
United States/Canadian Distinctions for Reporting Reserves. Any references to reserves in this press release have been determined in accordance with the guidelines of the SEC and the United States Financial Accounting Standards Board (“U.S. Rules”) and not in accordance with Canadian National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities (“NI 51-101”). The practice of preparing production and reserve quantities data under NI 51-101 differs from the U.S. Rules. The primary differences between the two reporting requirements include: (i) NI 51-101 requires disclosure of proved and probable reserves; the U.S. Rules require disclosure of only proved reserves; (ii) NI 51-101 requires the use of forecast prices in the estimation of reserves; the U.S. Rules require the use of 12-month average prices which are held constant; (iii) NI 51-101 requires disclosure of reserves on a gross (before royalties) and net (after royalties) basis; the U.S. Rules require disclosure on a net (after royalties) basis; (iv) the Canadian standards require disclosure of production on a gross (before royalties) basis; the U.S. Rules require disclosure of production on a net (after royalties) basis; and (v) NI 51-101 requires that reserves and other data be reported on a more granular product type basis than required by U.S. Rules.
Conversion Ratio for BOE Calculations. In computing BOEs (barrels of oil equivalent), gas was converted to oil in the ratio of 6 Mcf of gas to 1 bbl of oil. BOEs may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 Mcf to 1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Furthermore, the use of an energy equivalent 6:1 conversion factor might lead to an overstatement of the value of such reserves when the value ratio is currently closer to 20:1 particularly for companies whose reserves are mainly gas. As of June 30, 2011 approximately 49% of Magnum Hunter–s reserves and contingent resources from all properties was attributable to oil or natural gas liquids using the above 6 Mcf to 1 bbl energy equivalency conversion method.
The statements and information contained in this press release that are not statements of historical fact, including all estimates and assumptions contained herein, are “forward looking statements” as defined in Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. These forward looking statements include, among others, statements, estimates and assumptions relating to our business and growth strategies, our oil and gas reserve estimates, our ability to successfully and economically explore for and develop oil and gas resources, our exploration and development prospects, future inventories, projects and programs, expectations relating to availability and costs of drilling rigs and field services, anticipated trends in our business or industry, our future results of operations, our liquidity and ability to finance our exploration and development activities, market conditions in the oil and gas industry and the impact of environmental and other governmental regulation. Forward-looking statements generally can be identified by the use of forward-looking terminology such as “may”, “will”, “could”, “should”, “expect”, “intend”, “estimate”, “anticipate”, “believe”, “project”, “pursue”, “plan” or “continue” or the negative thereof or variations thereon or similar terminology. These forward-looking statements are subject to numerous assumptions, risks, and uncertainties. Factors that may cause our actual results, performance, or achievements to be materially different from those anticipated in forward-looking statements include, among other, the following: adverse economic conditions in the United States and globally; difficult and adverse conditions in the domestic and global capital and credit markets; changes in domestic and global demand for oil and natural gas; volatility in the prices we receive for our oil and natural gas; the effects of government regulation, permitting, and other legal requirements; future developments with respect to the quality of our properties, including, among other things, the existence of reserves in economic quantities; uncertainties about the estimates of our oil and natural gas reserves; our ability to increase our production and oil and natural gas income through exploration and development; our ability to successfully apply horizontal drilling techniques and tertiary recovery methods; the number of well locations to be drilled, the cost to drill, and the time frame within which they will be drilled; drilling and operating risks; the availability of equipment, such as drilling rigs and transportation pipelines; changes in our drilling plans and related budgets; and the adequacy of our capital resources and liquidity including, but not limited to, access to additional borrowing capacity. Because forward-looking statements are subject to risks and uncertainties, actual results may differ materially from those expressed or implied by such statements. Readers are cautioned not to place undue reliance on forward-looking statements, contained herein, which speak only as of the date of this document. Other unknown or unpredictable factors may cause actual results to differ materially from those projected by the forward-looking statements. Unless otherwise required by law, we undertake no obligation to publicly update or revise any forward-looking statements, including estimates, whether as a result of new information, future events, or otherwise. We urge readers to review and consider disclosures we make in our public filings made from time to time with the Securities and Exchange Commission that discuss factors germane to our business, including our Annual Report on Form 10-K, as amended for the year ended December 31, 2010 and our Quarterly Reports on Form 10-Q for the quarters ended March 31, 2011 and June 30, 2011. All forward-looking statements attributable to us are expressly qualified in their entirety by these cautionary statements.
:
M. Bradley Davis
Senior Vice President of Capital Markets
(832) 203-4545