Magnum Hunter Provides Fourth Quarter 2011 Company Wide Operational Update

Fourth Quarter Production of 9,166 Boepd -- Up 74% From Third Quarter; 2011 Production of 5,520 Boepd -- Up 237% From 2010 Production; 2012 Production Exit Rate Guidance Raised to 15,000 Boepd

Marketwired

HOUSTON, TX--(Marketwire -01/30/12)- Magnum Hunter Resources Corporation (NYSE: MHR - News) (AMEX: MHR-PC - News) (AMEX: MHR-PrD) (the "Company" or "Magnum Hunter") announced today an operational update on each of the Company's three upstream unconventional resource plays for the fourth quarter of 2011 which include (i) the Eagle Ford Shale, (ii) the Williston Basin, and (iii) the Appalachia/Marcellus/Utica Shale. Additionally, the Company also provided an operational update for the Company's midstream division, Eureka Hunter Pipeline.

Magnum Hunter achieved an average production rate of 9,166 barrels of oil equivalent per day ("Boepd") during the fourth quarter of 2011. This production rate represents a 455% increase from the fourth quarter 2010 production and a 74% increase from the prior quarter (third quarter 2011) average production number. This significant production increase is due primarily to the drilling and completion success achieved in each of the Company's operating regions. The Company had a year-end 2011 exit rate above 12,500 Boepd and is currently producing over 13,000 Boepd (45% oil/liquids).

Eagle Ford

During the fourth quarter of fiscal year 2011, Eagle Ford Hunter, Inc. ("Eagle Ford Hunter") completed and placed on production four gross operated wells (two net) in the Eagle Ford Shale. All four wells had an initial production rate in excess of 1,200 Boepd separately in their initial one-day test period, with one of the wells testing over 2,000 Boepd. Highlights for Eagle Ford Hunter include:

  • The Furrh #2H which was drilled to a measured depth of 15,876 feet (horizontal lateral length of 5,945 feet), was fraced with 20 stages and placed on production November 11, 2011. The 24 hour flowing initial production rate ("IP") was 1,275 Boepd on a 19/64" choke with 1,680 psi FCP. Magnum Hunter operates the Furrh #2H and owns a 50% working interest.

  • The Kudu Hunter #1H was drilled and cased to a measured depth of 16,412 feet (horizontal lateral length of 5,696 feet), and was fraced with 20 stages in mid-November. The 24 hour IP rate was 1,590 Boepd on a 22/64" choke with 2,200 psi FCP. The Kudu Hunter #1H was placed on production November 26, 2011. Magnum Hunter operates the Kudu Hunter #1H and owns a 46.3% working interest.

  • The Snipe Hunter #1H was drilled and cased to a measured depth of 16,202 feet (horizontal lateral length of 6,094 feet), and was fraced with 23 stages in late December. The 24 hour IP rate was 2,033 Boepd on a 20/64" choke with 2,100 psi FCP. The Snipe Hunter #1H was placed on production December 30, 2011. Magnum Hunter operates the Snipe Hunter #1H and owns a 50% working interest.

  • The Leopard Hunter #1H was drilled and cased to a measured depth of 16,936 feet (horizontal lateral length of 6,708 feet), and was fraced with 25 stages in early January. The 24 hour IP rate was 1,333 Boepd on an 18/64" choke with 1,700 psi FCP. The Leopard Hunter #1H was placed on production January 8, 2012. Magnum Hunter operates the Leopard Hunter #1H and owns a 50% working interest.

Mr. H.C. "Kip" Ferguson, President of Eagle Ford Hunter commented, "We are continuing to see a significant improvement in IP24, 30 and 60 day production rates as a result of our increasing knowledge, improved fracing techniques, and the combination of longer laterals and more frac stages per lateral. Since we have implemented these changes, our average IP24 rates have been in excess of 1,650 Boepd with a high test rate of 2,000 Boepd. We are fortunate to hold some of the better mineral lease acreage positions in the entire Eagle Ford play when comparing rates of return on capital deployed along with the premium product pricing for our produced high quality crude and high BTU natural gas. Eagle Ford Hunter has a substantial inventory of 198 drilling locations currently identified across our 52,000 gross leasehold acreage position. Magnum Hunter's in-house reservoir engineers have identified a net unrisked resource potential of approximately 39.0 million net Boe's on our leasehold acreage."

Williston Basin

During the fourth quarter, Williston Hunter, Inc. ("Williston Hunter") completed and placed on production three gross (three net) operated wells in the Tableland Field in Saskatchewan. Additionally, Williston Hunter was also in the process of fracture stimulating two gross (two net) operated wells in this area during the fourth quarter, which have been subsequently placed on production in January 2012.

The Tableland core field production has benefitted over the last several months from a redesigned fracture stimulation program implemented on the most recent four well completions. Initial well productivity has increased by 100% from IP24 rates of 255 Boepd to average IP24 rates of 590 Boepd. Recent wells have been drilled, cased, completed, and tied into our pipeline and processing facility within 40 days from spud date. Additionally, the Tableland Field battery facilities were expanded in the fourth quarter with the addition of 3.75 miles of gathering system and a free water knock out. These additions improved the area operating costs by reducing emulsion trucking costs. A further reduction in operating costs to below $10/bbl is targeted for the first quarter of 2012. Netbacks on Tableland crude oil production continue to benefit from provincial government incentives that substantially reduce the horizontal oil well royalty rate and, when coupled with low operating costs, result in $80/bbl to $85/bbl netbacks (assuming average NYMEX $100 bbl crude oil prices).

Highlights for the Tableland Field include:

  • 1-14-1-10W2M, a 100% WI operated well was drilled to a measured depth of 12,340 feet including 4,612 feet of horizontal lateral section and was fracture stimulated with 26 stages. The well was placed on production October 27, 2011 and achieved an IP24 rate of 749 Boepd.

  • 13-16-1-10W2M, a 100% WI operated well was drilled to a measured depth of 11,391 feet including 3,583 feet of horizontal lateral section and was fracture stimulated with 24 stages. This well was placed on production December 17, 2011 and achieved an IP24 rate of 491 Boepd.

  • 13-10-1-10W2M, a 100% WI operated well was drilled to a measured depth of 11,840 feet including 4,068 feet of horizontal lateral section and was fracture stimulated with 24 stages. The well was placed on flow back January 7, 2012 and achieved an IP24 rate of 576 Boepd.

  • 12-10-1-10W2M, a 100% WI operated well was drilled to a measured depth of 11,693 feet including 3,885 feet of horizontal lateral section and was fracture stimulated with 21 stages. The well was placed on flowback January 12, 2012 and achieved an IP24 rate of 543 Boepd.

During the fourth quarter, Williston Hunter's non-operated position in Divide and Burke Counties North Dakota included 9 gross wells (0.7 net) that were completed and placed on production. Operations in North Dakota benefited from an increased number of scheduled frac days per month, which resulted in reducing our behind pipe inventory to 10 gross (1.8 net) wells at year end. This inventory represents approximately 400 Boepd of combined net production at IP30 day type curve forecast production

Highlights for Williston Hunter's North Dakota non-operated properties include:

 
                                                       IP7     IP30    IP60
                                                      7 Day   30 Day  60 Day
                 MHR  Lateral  Frac           IP24hr Average Average Average
Well     County W.I.%  Length Stages   Zone    boepd  boepd   boepd   boepd
Thomte
 8-5-
 163-99  Divide  10.0  2 Mile   30   TFSanish   1309    1241       -       -
Hauge
 13-21
 28-33-
 163-99) Divide   1.9  2 Mile   20   TFSanish    897     782       -       -
Edna 14-
 23-160-
 100     Divide   7.0  2 Mile   18   TFSanish    406     353       -       -
Lark 29-
 32-162-
 97      Divide  10.0  2 Mile   26   TFSanish    636     417       -       -
Stork
 17-20-
 162-96  Divide  10.0  2 Mile   20   TFSanish    621     515       -       -
Blue Jay
 32-29-
 163-95  Divide  10.3  2 Mile   26    Bakken     852     455     346       -
Bonnevil
 le 25-
 36-163-
 100     Divide   5.6  2 Mile   26   TFSanish    950     937     751     597
Mustang
 7-6-
 163-98  Divide   7.5  2 Mile   26   TFSanish    565     438     345     273
Ranchero
 18-19-
 163-98  Divide  10.0  2 Mile   26   TFSanish    843     791     651     572

Negotiations continue with third parties for transportation and processing of Williston Hunter natural gas and associated liquids produced in Divide County, North Dakota which is currently being flared. At present, Magnum Hunter has not booked any natural gas liquids reserves associated with the Company's natural gas production and associated liquids in this region.

Mr. Glenn Dawson, President of Williston Hunter commented, "In the fourth quarter of 2011, we focused on an aggressive drilling and completion program utilizing a new hydraulic fracing technique. This significantly increased our Initial Production ("IP") rates of light 42°API oil from four new Tableland, Saskatchewan wells. This fracing modification has increased recent well performance consistently by 100%. Operating costs continue to improve, reflecting the increased oil production volumes and utilization of upgraded facilities at Tableland. We look forward to additional production gains in the first quarter of 2012 due to these changes we have implemented. Recent land sale and lease acquisition activity adjacent to our existing land positions have further supported the value of our mineral acreage position. Williston Hunter has a multi-year inventory of 490 net currently identified drilling locations across our 81,740 net leasehold acreage position located in North Dakota and Saskatchewan, Canada. Magnum Hunter's in-house reservoir engineers and geologists have identified net resource potential of 114 Million BOE over the Company's entire Williston Basin acreage position."

Appalachia

During the fourth quarter of 2011, the Appalachian Basin Division completed most notably four successful 100% working interest horizontal operated wells located in the Marcellus Shale. Highlights include:

  • The Roger Weese #1110, located in Tyler County, West Virginia, was drilled to a measured depth of 11,033 feet (horizontal lateral length of 4,350 feet). The well was fraced with 16 stages and tested at an IP24 rate of 9.7 MMcfepd on an adjustable choke with a 2,437 psi FCP. The well was placed on production October 25, 2011.

  • The Everett Weese #1107, located in Tyler County, West Virginia, was drilled to a measured depth of 12,135 feet (horizontal lateral length of 5,300 feet) The well was fraced with 18 stages and was tested at an IP24 rate of 9.6 MMcfepd on an adjustable choke with a 2,650 psi FCP. The well was placed on production December 20, 2011.

  • The Everett Weese #1108, located in Tyler County, West Virginia, was drilled to a measured depth of 12,155 feet (horizontal lateral length of 5,200 feet). The well was fraced with 16 stages and tested at an IP24 rate of 9.4 MMcfepd on an adjustable choke with a 2,091 psi FCP. The well was placed on production December 20, 2011.

  • The Everett Weese #1109, located in Tyler County, West Virginia, was drilled to a measured depth of 12,343 feet (horizontal lateral length of 5,550 feet). The well was fraced with 18 stages and tested at an IP24 of 9.5 MMcfepd per day on an adjustable choke with a 2,471 psi FCP. The well was placed on production December 20, 2011.

In addition to the Company's Marcellus Shale drilling program during fiscal year 2011, 21 gross wells (17.9 net wells) were drilled in Kentucky principally to maintain our large acreage position of approximately 300,000 net acres. These wells are comprised of four Weir Oil wells, two in the Arch Field and two in the Amvest Field, and twelve Lower Huron Shale wells, six in the Fonde Field, five in the Amvest Field, and one in the Martin's Fork Field. In addition, five Cleveland Shale wells were drilled, two in Martin's Fork Field, two in Amvest Field, and one in the Straight Creek Field. Initial production rates from these newly completed wells ranged from 400,000 Mcfe - 1.3 Mmcfe per day each.

Mr. Jim Denny, President of the Appalachian Basin Division, commented, "During the fourth quarter of fiscal year 2011, the Appalachian Basin Division drilled, completed and tested four very successful liquids-rich Marcellus Shale horizontal wells on our Northwestern West Virginia lease acreage. As experienced in other operating divisions within Magnum Hunter, the more history and experience we gain in our regional development has resulted in successfully obtaining better overall production results. A combination of longer laterals, more frac stages, and certain modifications to down hole equipment has led to consistent new well completions ranging from 8.0 - 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 due to the significant liquids content of the gas stream. When one compares internal rates of return on capital deployed, our high Btu equivalent in our natural gas stream provides economics not seen elsewhere in natural gas development. We have a significant inventory for many years to come with 774 net drilling locations currently identified across our 369,000 net leasehold acreage position. Our Company's in-house reservoir engineers have identified net possible reserves of 265 Million Boe, and 44 Million Boe of contingent resources over our entire Appalachian mineral acreage."

Eureka Hunter Pipeline System

From June 2010 to December 2011, the Company has completed a combined 45 miles of 20 inch and 16 inch high pressure pipeline. Eureka Hunter Pipeline, LLC's ("Eureka Hunter") actual construction costs have averaged significantly below industry competitors at approximately $1.3 million per mile. Fiscal year 2011 expansion projects included: (i) the completion of 8 miles of 20-inch mainline pipe westward across Tyler County, WV; (ii) the completion of the "Pursley Lateral", 14 miles of 20-inch pipe extending north from the Eureka Hunter Mainline in Tyler County to just south of the Ohio River; and (iii) the commencement of the "Doddridge Lateral", of which Eureka Hunter completed 4 miles of 16-inch pipe extending south from the Mainline into Doddridge County, WV. Eureka Hunter is currently gathering in excess of 50,000 Mcfepd and projects to have in excess of 90,000 Mcfepd of through put once the MarkWest Liberty Mobley II processing plant is completed later this year.

In October 2011, Triad Hunter, LLC ("Triad Hunter") and Eureka Hunter announced a comprehensive processing and fractionation services agreement with MarkWest Liberty Midstream and Resources. As part of this comprehensive solution, Eureka Hunter agreed to sell its 200 MMcfepd capacity Thomas Russell cryogenic processing plant that was under construction to MarkWest Liberty. MarkWest Liberty will install this new plant as Mobley 2, adjacent to the Mobley 1 plant in 2012. Triad Hunter as well as Eureka Hunter's third party shippers will then have access to the full suite of processing, fractionation, NGL handling, and marketing services offered by MarkWest Liberty. Producers on the Eureka Hunter Pipeline System will also be able to realize the significant value added uplift which will be achieved through the extraction of NGLs by processing the gas stream. The addition of Mobley as another processing delivery option for producers connected to Eureka Hunter enhances the value and optionality that makes the system so unique in this region.

The Eureka Hunter Pipeline System has approximately 182 miles of pipeline and existing rights-of-way that has the capacity to gather significant volumes of Marcellus and Utica Shale production in northwest West Virginia and Southeastern Ohio.

Magnum Hunter Chairman Comments

Mr. Gary C. Evans, Chairman of the Board and Chief Executive Officer of Magnum Hunter, commented, "We started 2011 with a lot of moving parts due to our acquisition efforts that ultimately gave us the significant drilling inventory that we are exploiting today. We are now beginning to see the fruits of our labor in all three upstream divisions. We were fortunate to have selected new regions that were a bit 'under the radar screen' so to speak at the time, but have now proven to be some of the most sought after areas in the industry. When you couple great acreage positions with highly talented industry professionals who are willing to continue tweaking their drilling and completion techniques in an effort to improve both production results and ultimate recoveries, you then create substantial equity value for shareholders. Current Company-wide production rates now give us the confidence to increase our 2012 exit rate guidance to 15,000 Boe per day. Our corporate strategy continues to be focused exclusively on creating above market returns through a balanced program of acquisitions of companies and properties and low-risk development and exploration drilling, exclusively in unconventional resources plays with a crude oil and/or liquids focus."

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, natural gas and natural gas liquids, primarily in the states of West Virginia, Kentucky, Ohio, Texas, North Dakota and Saskatchewan, Canada. The Company is presently active in three of the most prolific unconventional shale resource plays in North America, namely the Marcellus Shale, Utica Shale, Eagle Ford Shale and Williston Basin/Bakken Shale.

For more information, please view our website at http://www.magnumhunterresources.com/

Forward-Looking Statements

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, estimates of oil and natural gas resource potential, 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, June 30, 2011 and September 30, 2011. All forward-looking statements attributable to us are expressly qualified in their entirety by these cautionary statements.

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. In this press release, we use the term "resource potential" to describe the Company's internal estimates of volumes of oil and natural gas that are not classified as proved reserves but are potentially recoverable through exploratory drilling or additional drilling or recovery techniques. This is a broader description of potentially recoverable volumes than probable and possible reserves, as defined by SEC regulations. The "resource potential" disclosed in this press release includes both possible reserves and potentially recoverable volumes that cannot be classified as proved, probable or possible reserves. "Contingent resources" disclosed in this press release also includes potentially recoverable volumes that cannot be classified as proved, probable or possible reserves. Estimates of unproved 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. We believe our estimates of unproved resources and future drillsites are reasonable, but such estimates have not been reviewed by independent engineers. Estimates of unproved resources may change significantly as development provides additional data, and actual quantities that are ultimately recovered may differ substantially from prior estimates.

Contact:
Magnum Hunter Contact:
Gabe Scott
Assistant Vice President of Finance and Assistant Treasurer
ir@magnumhunterresources.com
(832) 203-4545

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