HOUSTON, TX — (Marketwire) — 08/09/11 — Magnum Hunter Resources Corporation (NYSE: MHR) (NYSE Amex: MHR-PrC) (NYSE Amex: MHR-PrD) (“Magnum Hunter” or the “Company”) announced today financial and operating results for the second quarter of 2011 and six months ended June 30, 2011.
Magnum Hunter reported an increase in total revenues of 298% for the second quarter of 2011 compared to the second quarter of 2010. Total revenues were $33.4 million for the three months ended June 30, 2011 compared to $8.4 million for the three months ended June 30, 2010. This increase in revenues was driven principally by the significant increase in production derived from the NGAS and NuLoch acquisitions and the Company–s ongoing drilling programs in the three unconventional resource plays. Operating margins also improved substantially as lease operating expenses per barrel of oil equivalent (“Boe”) declined from $23.24 per Boe to $16.42 per Boe, primarily due to the addition of new production and tighter controls on field operating expenses related to producing properties acquired. Recurring cash general and administrative costs per Boe also declined from $28.75 to $15.52 per Boe. The Company anticipates this trend of improving operating statistics to continue during the second half of 2011.
The Company reported a net loss of $18.5 million or ($0.16) per basic and diluted common shares outstanding for the second quarter of 2011, compared to a net loss of $6.0 million, or ($0.10) per basic and diluted common shares outstanding during the second quarter of 2010. The Company–s net loss per share for the second quarter of 2011 would have been ($0.01) when adjusted for non-recurring and non-cash charges of $16.8 million. These extraordinary charges specifically relate to acquisitions and non-recurring costs of $6.1 million ($0.05 per share) and non-cash stock compensation expense of $10.6 million ($0.09 per share) predominately associated with new management and employees at the companies acquired.
For the three months ended June 30, 2011, Magnum Hunter–s –Adjusted Earnings Before Interest, Income Taxes, Depreciation and Amortization– (“Adjusted EBITDA”) was $12.8 million or $0.11 per basic and diluted common shares outstanding. Adjusted EBITDA was $0.3 million for prior comparable period during the three months ended June 30, 2010.
Magnum Hunter reported an increase in revenues of 223% for the six months ended June 30, 2011 compared to the six months ended June 30, 2010. Total revenues were $48.8 million for the six months ended June 30, 2011 compared to $15.1 million during the six months ended June 30, 2010. This increase in revenues was driven principally by the significant increase in production from the Company–s recent acquisitions and drilling programs. Operating margins also improved substantially as lease operating expenses per Boe declined to $15.13 per Boe from $23.26 per Boe, primarily due to the addition of new production with lower operating costs and tighter controls on field operating expenses related to acquired and existing properties. Recurring cash general and administrative costs per Boe also declined significantly from $34.49 per Boe to $15.62 per Boe. The Company anticipates this trend of improving operating statistics to continue in the second half of 2011.
The Company reported a net loss of $27.8 million or ($0.29) per basic and diluted common shares outstanding for the six months ended June 30, 2011, compared to a net loss of $10.0 million, or ($0.17) per basic and diluted common shares outstanding during the six months ended June 30, 2010. The Company–s net loss for the six months ended June 30, 2011 would have been ($0.04) per basic and diluted common shares outstanding when adjusted for $23.7 million of non-recurring and non-cash charges which included acquisition and non-recurring costs of $7.8 million ($0.08 per share) and non-cash stock compensation expense of $12.0 million ($0.13 per share).
For the six months ended June 30, 2011, Magnum Hunter–s Adjusted EBITDA was $19.4 million or $0.20 per basic and diluted common shares outstanding. This represented a 462% increase over the $3.4 million or $0.06 per basic and diluted share of Adjusted EBITDA for the six months ended June 30, 2010.
Total capital expenditures incurred during the second quarter of 2011 were $42.3 million, excluding acquisitions. During the second quarter, the Company completed approximately $575 million of acquisitions including Nuloch ($430.5 million), NGAS ($124.5 million) and Post Rock ($20 million). Also, on August 5, 2011, the Company announced that it had agreed to acquire additional Williston Basin properties from a privately held seller for $57 million. Magnum Hunter–s fiscal year 2011 total capital expenditure budget remains at $255 million. The Company intends to fund its remaining fiscal year 2011 capital expenditure program through a combination of existing liquidity, increasing internally generated cash flows, expansion of the Company–s senior commercial bank credit facilities, additional debt capital sources, continued issuance of Series “D” Preferred Stock (non-convertible into common), possible joint ventures and selective asset divestitures. The Company also is finalizing a new non-recourse debt facility to fund Eureka Hunter Pipeline capital expenditures, including capital expenditures for the remainder of 2011 as well as future planned capital expenditures for this subsidiary.
Magnum Hunter–s borrowing base on its senior commercial bank facility recently increased from $145 million to $170 million based on the Company–s first quarter reserve report. This 17% increase in Magnum Hunter–s borrowing base was entirely due to organic growth of the Company–s total proved reserve base. As of June 30, 2011, the Company had $139 million of outstanding indebtedness under its existing senior bank credit facility. As of June 30, 2011, the Company had $36 million of liquidity from a combination of cash and existing availability under its $170 million borrowing base. The Company expects to increase its borrowing base due to the June 30, 2011 reserve increase and the acquisition of certain North Dakota producing oil and gas which will further enhance the Company–s liquidity position. The Company has continued to maintain its strong capital ratios. Magnum Hunter–s net Debt/Total Capitalization ratio was 18% as of June 30, 2011 and Debt/Adjusted EBITDA (based on the second quarter 2011 Adjusted EBITA on an annualized basis) of 2.8x.
The Company–s total proved reserves increased by 17.8 million Boe to 31.2 million Boe (55% crude oil and ngls; 50% proved developed producing) as of June 30, 2011 as compared to 13.4 million Boe (51% crude oil & ngls; 44% proved developed producing) at December 31, 2010. The increase in total proved reserves from December 31, 2010 to June 30, 2011 includes total proved reserves added from the Company–s recently closed acquisition of both NGAS Resources and NuLoch Resources.
Average daily production during the second quarter ended June 30, 2011 was 4,947 barrels of oil equivalent per day (“Boepd”) (46% crude oil) which represents a 255% increase over the 1,393 Boepd reported during the second quarter of 2010 and an 88% increase over the production rate of 2,629 Boepd reported during the first quarter of 2011. The increase in the Company–s production rate was a result of the NGAS and NuLoch acquisitions and the Company–s ongoing success in its drilling programs in the three unconventional resource plays. Although the Company saw significant production increases over prior periods, the second quarter June 30, 2011 production rate was significantly impacted by shut-in production in the Williston Basin due to adverse weather related issues. The Company–s current daily production capacity is 6,100 Boepd (pro forma for the recently announced agreement to acquire the additional North Dakota Williston Basin properties). Magnum Hunter remains on target to achieve its stated goal of a daily production exit rate for fiscal year 2011 in excess 10,000 Boepd.
As of August 8, 2011, the Company is currently drilling 7 gross (2 net) wells, completing 14 gross (3 net) wells and has 21 gross (5.5 net) wells drilled but awaiting completion.
Magnum Hunter has allocated approximately $75 million (29.4% of the total fiscal year 2011 capex budget) to drill 17 gross wells (9 net wells) during the year in the oil window of the Eagle Ford Shale play, with our focus predominately in Gonzales County, Texas. Since spudding its first Eagle Ford Shale well in June 2010, through August 8, 2011, Magnum Hunter has drilled and completed 9 gross wells (5.4 net wells). The Oryx Hunter 1H well is currently being fracture stimulated and the Sable Hunter 1H is drilling in “zone”. Magnum Hunter anticipates spudding an additional 8 wells and completing 6 of these wells by December 31, 2011.
Highlights for the second quarter of 2011 regarding our Eagle Ford activities include the Furrh #1H well which was completed in April 2011 and posted a 24-hour initial production (IP) rate of 882 Boepd. The GeoHunter #1H was completed in May 2011 and posted a 24-hour IP rate of 854 Boepd. Additionally, all producing wells in this region have been tied into a new gas gathering system as of August 1, 2011. The associated natural gas from these producing oil wells had previously been flared since initial production operations began last year. The Company estimates the Eagle Ford Division to achieve a December 31, 2011 production exit rate of approximately 1,900 Boepd.
In the Appalachian Basin, Magnum Hunter has allocated approximately $70 million (27.5% of the total capital budget) to drill 37 gross wells (22 net wells) during fiscal year 2011. This includes approximately $65 million for 17 gross wells (15.5 net wells) targeting the liquids rich Marcellus Shale play of Northwestern West Virginia and Southeastern Ohio and approximately $5 million primarily for 20 gross wells (6.5 net wells) targeting the Huron Shale and Weir Oil Sands located in Kentucky. The Company estimates the Appalachian region to achieve a year-end 2011 production exit rate of approximately 5,700 Boepd.
Magnum Hunter has drilled 8 gross wells (6.5 net wells) in the liquids-rich Marcellus Shale play in Northwest West Virginia. Of these, 5 gross wells (3.5 net wells) are currently producing, 1 gross well (1.0 net well) is completing and 2 gross wells (2.0 net wells) are awaiting fracture stimulation. These wells will be completed in sequence during August, and are expected to have 16 to 20 frac stages each. One gross well (1.0 net well) is currently drilling in the Marcellus. During June 2011, the Company successfully completed 2 gross wells (1.0 net well), the Lance Mills Unit 2 #2H and the Lance Mills Unit 2 #5H, both located in Wetzel County, West Virginia with IP rates of 3.9 MMcfed and 3.4 MMcfed, respectively. It should be noted that these wells were tested and remain on restricted production rates until additional pipeline expansion has been completed. Magnum Hunter currently anticipates spudding an additional 8 gross wells (8 net wells) in its Marcellus Shale region prior to year-end 2011.
The Company has drilled and completed 5 gross wells (1.5 net wells) on lease acreage recently acquired from NGAS, targeting the Huron Shale and Weir Oil Sands. Magnum Hunter currently anticipates spudding an additional 15 gross wells (5 net wells), primarily on Huron Shale acreage prior to year-end 2011.
The severe winter weather in the Williston Basin, followed by a wet break-up, adversely impacted second quarter 2011 production levels. The Company has recently restored production levels to approximately 1,400 Boepd (proforma for the recently announced agreement to acquire the additional Williston Basin properties). Approximately 450 Boepd of net daily production capacity remains shut-in due to adverse weather related conditions which we anticipate should be restored to production in later August 2011. In addition, we have 19 gross (3.4 net) new wells awaiting completion activities. The Company estimates the Williston Hunter Division to achieve a December 31, 2011 production exit rate of approximately 2,400 Boepd.
Magnum Hunter has allocated approximately $70 million (27.5% of the total capital budget) to drill 57 gross wells (9.4 net wells) in the Williston Basin during fiscal year 2011. This includes $55 million to drill 52 gross (5.0 net) Middle Bakken/Three Forks Sanish wells in North Dakota; and $15 million to drill 5 gross (4.4 Net) Middle Bakken/Three Forks Sanish in the Company–s higher working interest properties and the 100% operated Tableland Field located in Saskatchewan, Canada. The Company has identified approximately $37 million in capital projects for the balance of 2011, assuming five drilling rigs running in North Dakota. In addition, the Company is in the process of adding a sixth drilling rig in North Dakota to further accelerate development.
As of August 2011, Williston Hunter has drilled 21 gross wells (3.5 net wells) year-to-date. In North Dakota, 19 wells (1.5 net) were spud or in the process of being spudded and 2 wells (2.0 net) were drilled in Saskatchewan. Completions in the Williston Basin were the biggest challenge during the first six months of 2011, as unusually harsh winter weather and equipment delays slowed progress. Of the 18 wells (4.4 net) in the Company–s year-end inventory, 16 (4.1 net) have not been completed. Additionally, 4 (0.3 net) of the wells spud in 2011 have also been completed. Currently the Company has 19 wells (3.4 net) awaiting completion operations.
In Divide County, North Dakota, we have experienced higher IP rates on most recently drilled wells due to improved fracture stimulation techniques and pump design. In March 2011, we drilled our best well to date, the Almos Farms well (0.1 net), which was brought on production at a peak rate of 1,236 Boepd. Average IP rates at Williston Hunter have been 482 Boepd in North Dakota and 333 Boepd for a recent well completed in Tableland, Saskatchewan, where we pay a substantially reduced royalty due to provincial government incentives and lower service costs. Negotiations have commenced with third parties for the transportation and processing of Williston Hunter–s natural gas and associated natural gas liquids produced in Divide County, North Dakota. Currently, Magnum Hunter has not booked any natural gas and natural gas liquids reserves associated with the Company–s production in this region.
Magnum Hunter has allocated approximately $40 million (15.7% of the total capital budget) for fiscal year 2011 capex requirements associated with expansion activities of the Eureka Hunter Pipeline system in northwest West Virginia. From June 2010 to August 2011, the Company has completed 32 miles of 20 inch high pressure pipe at a total cost of approximately $50 million. Our actual construction costs have been averaging significantly below industry competitors. Fiscal year 2011 expansion projects include: (i) completion of 8 miles of 20-inch mainline pipe westward; (ii) commencing installation of 7 miles of 20-inch pipe known as the “Pursley Lateral” in Tyler County West Virginia; (iii) installation of 7 miles of 16-inch pipe known as the “Wetzel DNR Lateral” in the third quarter of 2011; and (iv) installation of 7 miles of 20-inch pipe known as the “Logansport Lateral” to connect Eureka to the Markwest Mobley processing facility in the fourth quarter of 2011. Other possible projects that could begin during fiscal year 2011 are: (i) installation of 12 miles of 16-inch pipe known as the “Doddridge Lateral”; (ii) installation of 6 miles of 20-inch pipe under the Ohio River in order to connect Magnum Hunter–s southeastern Ohio production into the Eureka Hunter Pipeline System; and (iii) 12 miles of 16-inch pipe to extend the system to the Ohio River. The Eureka Hunter gas pipeline system has approximately 182 miles of pipe and existing rights-of-way that will ultimately have capacity to gather 200-300 MMcf per day in northwest West Virginia. Additionally, the Company is scheduled to take delivery of a 200 MMcfd cryogenic gas processing plant currently under construction in the second quarter of 2012.
Note: Adjusted EBITDA is a non-GAAP financial accounting measure and as such, a full reconciliation of the above exhibited Adjusted EBITDA numbers to the Company–s reported net income for the three and six months ended June 30, 2010 and 2011 using standardized GAAP financial accounting methodology and as reported to and filed with the Securities and Exchange Commission can be found and is exhibited in the footnotes of this Press Release below. Also, a reconciliation of the recurring loss per common share to the reported loss per common share and a reconciliation to recurring cash G&A for the three and six months ended June 30, 2011 is provided in the footnotes of this press release below.
Mr. Gary C. Evans, Chairman of the Board and Chief Executive Officer of Magnum Hunter Resources commented, “Our business plan remains on track. We have successfully closed two significant acquisitions during the second quarter and we are prudently developing our reserves in all three unconventional resource plays where we are active. Daily production is accelerating in each of these business units with new successful well completions. Because we now operate over 75% of our properties within our portfolio, if need be due to the extreme volatility being experienced in both the commodity and financial markets today, we can immediately adjust our capital expenditure program as needed. Magnum Hunter remains on target to exit 2011 at or above 10,000 barrels of oil equivalent per day.”
Magnum Hunter Resources Corporation is an independent oil and gas company engaged in the acquisition, development and production of oil and natural gas, primarily in West Virginia, Kentucky, Ohio, Texas, North Dakota and Saskatchewan, Canada. The Company is presently active in three of the most prolific shale resource plays in the United States, namely the Marcellus Shale, Eagle Ford Shale and Williston Basin/Bakken Shale.
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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 ending March 31, 2011 and June 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 presentation, 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. 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 drill sites 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.
References to reserves and future net revenue in this presentation have been determined in accordance with the SEC guidelines and the United States Financial Accounting Standards Board (“U.S. Rules”) and not in accordance with 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 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 the U.S. Rules.
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M. Bradley Davis
Senior Vice President of Capital Markets
(832) 203-4545