Exhibit 99.1
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| News Release | | | | News Release |
Magnum Hunter Resources Reports
Second Quarter 2013 Financial and Operating Results
Record Net Income of $151.3 million or $0.89 per share Reported for the Quarter
2013 Production Exit Rate Estimate Reaffirmed at 23,000 - 25,000 BOEPD
Houston, TX - (Marketwire) - August 9, 2013 - Magnum Hunter Resources Corporation (NYSE: MHR) (NYSE MKT: MHR.PRC; MHR.PRD; and MHR.PRE) (the “Company” or “Magnum Hunter”) announced today financial and operating results for the three months and six months ended June 30, 2013. The Company plans to file its Form 10-Q for the quarter ended June 30, 2013 with the Securities and Exchange Commission later today. Highlights include the following:
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| • | Total revenue increased 98% to $84.0 million for the second quarter of 2013, as compared to total revenue of $42.5 million for the second quarter of 2012(a) |
•Adjusted EBITDAX(b)(c) was $38.5 million for the second quarter of 2013
•Adjusted net loss(b)(c) of ($0.18) per diluted share for the second quarter of 2013
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| • | Production(d) of 15,941 BOEPD and adjusted production(d)(e) of 17,814 BOEPD for the second quarter of 2013 |
•Net income for the second quarter of 2013 was $151.3 million or $0.89 per share
•Current estimated throughput volumes on Eureka Hunter Pipeline of 125,000 MMBTU per day
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| (a) | Does not include revenues from the Eagle Ford Hunter, Inc. operations sold in April 2013, which have been classified as discontinued operations |
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| (b) | See Non-GAAP Financial Measures and Reconciliations below |
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| (c) | Includes net income from the Eagle Ford Hunter, Inc. operations sold in April 2013 through the date of sale |
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| (d) | Includes, on a pro forma basis, 816 BOEPD of actual production from Eagle Ford Hunter, Inc. operations sold in April 2013 through the date of sale |
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| (e) | Includes adjusted production of 1,873 BOEPD of temporary shut-ins in Appalachia due to pipeline and liquid handling issues |
Financial and Operating Results for the Three Months Ended June 30, 2013
Magnum Hunter reported an increase in revenues of 98% to $84.0 million for the three months ended June 30, 2013 compared to $42.5 million for the three months ended June 30, 2012(a). This increase in revenues was driven primarily by increases in our oil and natural gas liquids production as a result of increased drilling activity in our unconventional resource plays focused primarily on oil and liquids, and to a lesser extent, acquisitions.
The Company reported net income of $151.3 million attributable to common shareholders, or $0.89 per basic and diluted common shares outstanding, for the three months ended June 30, 2013, compared to a net loss of $22.7 million, or ($0.15) per basic and diluted common shares outstanding, for the three months ended June 30, 2012. When adjusted for non-cash and non-recurring gains on asset sales and expenses, the Company's adjusted net loss attributable to common shareholders for the three months ended June 30, 2013 was ($0.18) per basic and diluted common shares outstanding (see Non-GAAP Financial Measures and Reconciliations below)(f).
For the three months ended June 30, 2013, Magnum Hunter's Adjusted Earnings Before Interest, Income Taxes, Depreciation, Amortization and Exploration (“Adjusted EBITDAX”) was $38.5 million as compared to $38.5 million for the three months ended June 30, 2012 (See Non-GAAP Financial Measures and Reconciliations below)(f). The increase in Adjusted EBITDAX was primarily due to both an overall production increase and increased oil and liquids as a percentage of total production (48% oil/liquids)(f). However, natural gas production shut-ins (described below), higher lease operating expenses (“LOE”) per BOE, and higher non-recurring cash general and administrative costs (see Non-GAAP Financial Measures and Reconciliations below) per BOE partially offset the increase. The increase in LOE costs per BOE was primarily due to new oil wells placed on production in the Williston Basin which generally have higher LOE costs per BOE than natural gas wells. In addition, the LOE costs in the Williston Basin increased primarily due to higher costs associated with rental equipment (such as generators), diesel fuel and additional manpower required to operate the equipment. The Company anticipates LOE costs in the Williston Basin to decrease over time due to increased efficiencies at the field level which are currently being implemented and include electrification of fields. General and administrative expenses increased overall during the three months ended June 30, 2013 due mainly to additional accounting personnel and professional service expenses necessitated by the recent growth of the Company and the extended period of time to complete the 2012 annual audit and related SEC filings.
Oil and gas production increased 23% for the three months ended June 30, 2013 to 1.451 million barrels of oil equivalent ("MMBoe") or 15,941 barrels of oil equivalent per day (“Boepd”)(f) (48% oil/liquids) as compared to production of 1.179 MMBoe or 12,954 Boepd for the three months ended June 30, 2012. On an adjusted basis, production increased 38% to 17,814 Boepd including production shut-ins of 1,873 BOEPD as described below(e)(f). The increase in production was attributable primarily to the Company's successful drilling program in its shale plays. In addition, the Company's oil/liquids production mix increased to 48% of overall production in the second quarter of 2013 compared to 45% in the second quarter of 2012. This change is a result of the shift in our capital expenditure program towards an oil and liquids rich development program.
In the second quarter of 2013, the Company's production was adversely impacted by production shut-ins in the Appalachian division primarily due to pipeline and liquid handling issues relating to the Company's midstream gathering facilities. The Company experienced higher than anticipated NGLs present in its Marcellus production which necessitated that Eureka Hunter Pipeline implement a pigging process at its gathering lines. Once the pigging process was implemented, the Company was also further delayed as new air permits for compression facilities were required from the State of West Virginia. These production shut-ins were largely natural gas and NGLs, thus the impact on the Company's cash flow was substantially less than any reduction in our oil volumes. All gathering and liquids handling issues associated with the production of our Marcellus natural gas were resolved in May 2013, and the pipeline is fully operational with all natural gas and natural gas liquids now being processed at MarkWest's Mobley processing facility.
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| (f) | Results include net income/production from the Eagle Ford Hunter, Inc. operations sold on April 24, 2013 through the date of sale. These operations were classified as a discontinued operation for the six months ended June 30, 2013. |
Financial and Operating Results for the Six Months Ended June 30, 2013
Magnum Hunter reported an increase in revenues of 84% to $156.2 million for the six months ended June 30, 2013 compared to $84.8 million for the six months ended June 30, 2012(a). This increase in revenues was driven primarily by increases in our oil and natural gas liquids production as a result of increased drilling activity in our unconventional resource plays.
The Company reported net income of $93.6 million attributable to common shareholders, or $0.55 per basic and diluted common shares outstanding, for the six months ended June 30, 2013, compared to a net loss of $37.9 million, or ($0.27) per basic and diluted common shares outstanding, for the six months ended June 30, 2012. When adjusted for non-cash and non-recurring and gains on asset sales and expenses, the Company's adjusted net loss attributable to common shareholders for the six months ended June 30, 2013 was ($0.28) per basic and diluted common shares outstanding (see Non-GAAP Financial Measures and Reconciliations below)(f).
For the six months ended June 30, 2013, Magnum Hunter's Adjusted EBITDAX was $88.1 million as compared to $72.3 million for the six months ended June 30, 2012 (See Non-GAAP Financial Measures and Reconciliations below)(f). The increase in Adjusted EBITDAX was primarily due to both an overall production increase and increased oil and liquids as a percentage of total production (54%). However, natural gas production shut-ins (as discussed above), higher LOE costs per BOE, and higher non-recurring cash general and administrative costs (see Non-GAAP Financial Measures and Reconciliations below) per BOE partially offset the increase. The increase in LOE costs per BOE was primarily due to new oil wells placed on production in the Williston Basin which generally have higher LOE costs per BOE than natural gas wells. The LOE costs in the Williston Basin also increased due to higher costs associated with rental equipment (such as generators), diesel fuel and additional manpower required to operate the equipment. The Company anticipates LOE costs in the Williston Basin to decrease over time due to increased efficiencies at the field level which are currently being implemented and include electrification of fields. General and administrative expenses increased overall during the six months ended June 30, 2013 due mainly to additional accounting personnel and professional service expenses necessitated by the recent growth of the Company and the extended period of time to complete the 2012 annual audit and related SEC filings.
Oil and gas production increased 16% for the six months ended June 30, 2013 to 2.690 MMBoe or 14,861 Boepd (54% oil/liquids) as compared to the 2.328 MMBoe or 12,789 Boepd reported for the six months ended June 30, 2012(e). For the six months ended June 30, 2013, adjusted production, which includes actual production and production shut-ins of 2,493 Boepd as described above, increased 36% to 17,354 Boepd(e)(f). The increase in production was primarily attributable to the Company's successful drilling program in its shale plays and, to a lesser extent, acquisitions. In addition, the Company's oil/liquids production mix increased to 54% of overall production for the six months ended June 30, 2013 compared to 40% for the same period in 2012.
Capital Expenditures and Liquidity
Magnum Hunter's total upstream and midstream capital expenditures, excluding acquisitions and Eagle Ford Shale capital expenditures (which were recouped through the closing date purchase price adjustments expected to be finalized in August 2013 as a result of the January 1, 2013 effective date of the sale of the Eagle Ford Hunter, Inc. operations in April 2013), were $56.4 million for the three months ended June 30, 2013. Total upstream capital expenditures for the three months ended June 30, 2013 were $46.3 million, consisting of $24.7 million for the Williston Basin and $21.6 million for the Appalachian region. For the six months ended June 30, 2013, total upstream capital expenditures were $102.3 million, consisting of $56.6 million for the Williston Basin, $43.2 million for the Appalachian region and $2.5 million for the South Texas region. As a result of our Eagle Ford Hunter, Inc. properties sale, the Company reallocated its 2013 upstream capital expenditure budget of $300 million, with $150 million allocated to the Appalachian Basin, almost all of which is allocated to its Marcellus Shale and Utica Shale plays, and $150 million allocated to its Williston Basin/Bakken/Sanish Shale play. In addition, during the second quarter of 2013, the Company spent $10.1 million for the continued expansion of the Eureka Hunter Pipeline gas gathering system.
Magnum Hunter believes that, as a result of the Company's internally generated cash flows, availability under its Senior Revolving Credit Facility and additional liquidity sources, it has sufficient liquidity to fund the remainder of its fiscal 2013 upstream capital budget. As of June 30, 2013, the Company had total liquidity of approximately $297.7 million, comprised of approximately $32.7 million of cash and $265.0 million of borrowing availability under its Senior Revolving Credit Facility. In order to enhance its liquidity and further reduce leverage, the Company intends to divest up to $200 million of non-core assets in 2013 and 2014. The Company is also working on plans to monetize its ownership in Eureka Hunter Pipeline, its midstream subsidiary, in early 2014.
Proved Reserves Overview
Magnum Hunter's total proved reserves decreased by 6% to 57.8 MMBoe (51% crude oil and NGLs; 61% proved developed producing) at June 30, 2013 as compared to 61.6 MMBoe (57% crude oil and NGLs; 56% proved developed producing) at December 31, 2012, primarily due to higher LOE costs in the Williston Basin which moved certain proved undeveloped reserves into the probable category (g). Proved developed producing reserves increased by 3% from year-end 2012 to 35.4 MMBoe as of June 30, 2013 as a result of the Company's continued execution of its development
drilling program. Aggregate proved undeveloped reserves decreased slightly primarily due to higher LOE costs related to rental equipment, man power and diesel. The Company anticipates LOE costs in the Williston Basin to decrease over time due to increased efficiencies at the field level which include electrification of fields.
As of June 30, 2013, no proved reserves have been booked in Magnum Hunter's significant leasehold acreage position owned in the Utica Shale in Appalachia (80,000+ net acres) where the Company has initiated an active drilling program. The Company also expects a significant increase in reserves during the second half of the year due to “Pad” related drilling in Appalachia for both the Utica and Marcellus Shales. Given the Company's successful drilling results to-date, as well as those of other operators in the vicinity of our leasehold acreage, Magnum Hunter believes that a substantial portion of its Utica Shale acreage will be added to proved reserves over time as more wells are drilled and delineated in this region. The Appalachian Basin accounted for 65% of Magnum Hunter's proved reserve volumes at June 30, 2013, the Williston Basin accounted for 34% and other legacy assets, including our remaining assets in South Texas, accounted for the remaining 1%. At mid-year 2013, 50% of the Company's proved reserves by volume were natural gas, 38% were crude oil and 12% were NGLs.
Magnum Hunter's proved reserves at June 30, 2013 were audited by third-party engineering consultant, Cawley Gillespie & Associates, Inc. (“Cawley”). Cawley is currently finalizing the PV-10 analysis for the proved reserves and is preparing a 3P reserve report for the Company, the results of which we expect to publicly release in mid-August 2013.
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| (g) | The December 31, 2012 and June 30, 2013 proved reserves amounts exclude the proved reserves associated with the Eagle Ford Hunter, Inc. properties, which were sold on April 24, 2013. |
Eureka Hunter Pipeline
In the second quarter of 2013, Eureka Hunter Pipeline's focus has been on expansion efforts in Monroe County, Ohio. Eureka Hunter has acquired and cleared in excess of 20 miles of right-of-way in southeastern Ohio and has initiated pipeline construction in this region. Eureka Hunter Pipeline anticipates production from Monroe County wells to begin flowing into this new gathering system before year-end 2013 with additional pipeline(s) to be installed throughout 2014.
During the second quarter of 2013, Eureka Hunter Pipeline also set its third compressor at its Carbide central facilities site located in Wetzel County, West Virginia to assist with low pressure gathering and to help manage on going mainline pigging operations. Current daily throughput on Eureka Hunter is averaging more than 125,000 MMBtu per day, and Eureka Hunter Pipeline anticipates the connection of significant new gas supplies in the third and fourth quarters of 2013.
Management Comments
Mr. Gary C. Evans, Chairman of the Board and Chief Executive Officer of Magnum Hunter Resources, commented, “The production growth momentum we previously expressed to our shareholders is now becoming a reality. We reiterate today our projected production growth exit rate of 23,000 - 25,000 BOEPD for year-end 2013. This projection excludes any new Utica wells located in Southeastern Ohio that are planned for completion prior to year-end. We are staying within our capital budget program having only spent approximately one-third of our annual budget through the first six months of the year. Our midstream subsidiary continues to hit record throughput volumes each month with current take-away north of 125,000 MMBtu per day. The Williston Basin division is now producing approximately 6,000 BOEPD with a target of 7,000 BOEPD by the end of the year. Non-core asset sales preparations are picking up speed with announcements of transactions anticipated in the near future. Our Appalachian land group has been continuing its efforts to grow our existing acreage position in the Utica/Marcellus plays as we see this region generating some of our highest rate of returns for new wells drilled, even during a sub-optimum natural gas and NGLs commodity price environment.”
Non-GAAP Financial Measures
This release contains certain financial measures that are non-GAAP measures. We have provided reconciliations within this release of the non-GAAP financial measures to the most directly comparable GAAP financial measures. These non-GAAP financial measures should be considered in addition to, but not as a substitute for, measures for financial performance prepared in accordance with GAAP that are presented in this release.
Magnum Hunter defines adjusted income (loss) as reported net income (loss) attributable to common shareholders, plus non-recurring and non-cash items which include (1) exploration and abandonment expense, (2) impairment of oil and gas properties, (3) non-cash stock compensation expense, (4) non-cash 401k matching expense, (5) non-recurring transaction and other expense, (6) unrealized (gain) loss on investments, (7) interest expense - fees, (8) unrealized (gain) loss on derivatives, (9) (gain) loss on sale of assets, (10) income tax expense (benefit), (11) (gain) loss from sale of discontinued operations and (12) income from discontinued operations.
Magnum Hunter defines Adjusted EBITDAX as net income (loss) from continuing operations before (1) net interest expense, (2) (gain) loss on sale of assets, (3) depletion, depreciation and amortization, (4) impairment of oil and gas properties, (5) exploration and abandonment expense, (6) non-cash stock compensation expense, (7) non-cash 401k matching expense, (8) non-recurring transaction and other expense, (9) unrealized (gain) loss on investments, (10) income tax (benefit) and (11) unrealized (gain) loss on derivatives. Adjusted EBITDAX is not a measure of net income or cash flows as determined by GAAP.
Magnum Hunter defines recurring cash G&A as total general and administrative expenses before (1) non-cash stock compensation and (2) transaction and other non-recurring expense.
Management believes these non-GAAP financial measures facilitate evaluation of the Company's business on a “normalized” or recurring basis and without giving effect to certain non-cash expenses and other items, thereby providing management, investors and analysts with comparative information for evaluating the Company in relation to other oil and gas companies providing corresponding non-GAAP financial measures. These non-GAAP financial measures should be considered in addition to, but not as a substitute for, measures for financial performance prepared in accordance with GAAP, and that the reconciliations to the closest corresponding GAAP measure should be reviewed carefully.
About Magnum Hunter Resources Corporation
Magnum Hunter Resources Corporation and subsidiaries are a Houston, Texas based independent exploration and production company engaged in the acquisition, development and production of crude oil, natural gas and natural gas liquids, primarily in the states of West Virginia, Ohio, North Dakota, Kentucky, Texas 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 and Williston Basin/Bakken Shale.
For more information, please view our website at www.magnumhunterresources.com.
Forward-Looking Statements
The statements and information contained in this press release that are not statements of historical fact, including any estimates and assumptions contained herein, are “forward looking statements” as defined in Section 27A of the Securities Act of 1933, as amended, referred to as the Securities Act, and Section 21E of the Securities Exchange Act of 1934, as amended, referred to as the Exchange Act. 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 and our midstream activities, market
conditions in the oil and gas industry and the impact of environmental and other governmental regulation. In addition, with respect to any pending transactions described herein, forward-looking statements include, but are not limited to, statements regarding the expected timing of the completion of proposed transactions; the ability to complete proposed transactions considering various closing conditions; the benefits of any such transactions and their impact on the Company's business; and any statements of assumptions underlying any of the foregoing. In addition, if and when any proposed transaction is consummated, there will be risks and uncertainties related to the Company's ability to successfully integrate the operations and employees of the Company and the acquired business. 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 others, the following: adverse economic conditions in the United States, Canada 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, natural gas and natural gas liquids; 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 therefore our oil and natural gas income through exploration and development; our ability to successfully apply horizontal drilling techniques; the effects of increased federal and state regulation, including regulation of the environmental aspects, of hydraulic fracturing; 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; regulatory, environmental and land management issues, and demand for gas gathering services, relating to our midstream operations; and the adequacy of our capital resources and liquidity including, but not limited to, access to additional borrowing capacity.
These factors are in addition to the risks described in the “Risk Factors” and “Management's Discussion and Analysis of Financial Condition and Results of Operations” sections of the Company's 2012 annual report on Form 10-K, and subsequent Form 10-Qs, filed with the Securities and Exchange Commission, which we refer to as the SEC. Most of these factors are difficult to anticipate and beyond our control. Because forward-looking statements are subject to risks and uncertainties, actual results may differ materially from those expressed or implied by such statements. You 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, whether as a result of new information, future events or otherwise. We urge readers to review and consider disclosures we make in our reports that discuss factors germane to our business. See in particular our reports on Forms 10-K, 10-Q and 8-K subsequently filed from time to time with the SEC. All forward-looking statements attributable to us are expressly qualified in their entirety by these cautionary statements.
Results of Operations
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| | | | | | | | | | | | | | | | | |
| | | | Three Months Ended June 30, | | Six Months Ended June 30, |
| | | | 2013 | | 2012 | | 2013 | | 2012 |
| Oil and gas revenue and production | | | | | | | | | |
| Revenues (in thousands, U.S. Dollars) | | | | | | | | | |
| Oil | US | | $ | 35,869 |
| | $ | 19,199 |
| | $ | 63,077 |
| | $ | 32,683 |
|
| | Canada | | 8,330 |
| | 7,357 |
| | 20,935 |
| | 16,295 |
|
| Gas | US | | 17,646 |
| | 9,272 |
| | 28,727 |
| | 22,858 |
|
| | Canada | | 203 |
| | 114 |
| | 376 |
| | 224 |
|
| NGLs | US | | 4,409 |
| | 1,242 |
| | 5,907 |
| | 2,900 |
|
| | Canada | | — |
| | 1 |
| | — |
| | 7 |
|
| Total oil and gas sales | | | $ | 66,457 |
| | 37,185 |
| | 119,022 |
| | 74,967 |
|
| | | | | | | | | | |
| Production | | | | | | | | | |
| Oil (mbbls) | US | | 421 |
| | 240 |
| | 732 |
| | 391 |
|
| | Canada | | 93 |
| | 91 |
| | 245 |
| | 186 |
|
| Gas (mmcfs) | US | | 4,451 |
| | 3,802 |
| | 7,227 |
| | 8,156 |
|
| | Canada | | 45 |
| | 61 |
| | 91 |
| | 125 |
|
| NGL (mboe) | US | | 114 |
| | 35 |
| | 158 |
| | 71 |
|
| Total (mboe) | | | 1,376 |
| | 1,008 |
| | 2,355 |
| | 2,028 |
|
| Total (boe/d) | | | 15,125 |
| | 11,089 |
| | 13,009 |
| | 11,141 |
|
| | | | | | | | | | |
| Average prices (U.S. Dollars) | | | | | | | | | |
| Oil (per bbl) | US | | $ | 85.20 |
| | $ | 80.35 |
| | $ | 86.11 |
| | $ | 83.75 |
|
| | Canada | | $ | 89.69 |
| | $ | 80.85 |
| | $ | 85.54 |
| | $ | 87.38 |
|
| Gas (per mcf) | US | | $ | 3.96 |
| | $ | 2.44 |
| | $ | 3.98 |
| | $ | 2.80 |
|
| | Canada | | $ | 4.46 |
| | $ | 1.87 |
| | $ | 4.12 |
| | $ | 1.80 |
|
| NGL (per boe) | US | | $ | 38.93 |
| | $ | 35.55 |
| | $ | 37.45 |
| | $ | 41.06 |
|
| Total average price (per boe) | | | $ | 48.28 |
| | $ | 36.85 |
| | $ | 50.55 |
| | $ | 36.97 |
|
| | | | | | | | | | |
| Costs and expenses (per boe) | | | | | | | | | |
| Lease operating expense | | | $ | 14.98 |
| | $ | 10.62 |
| | $ | 13.90 |
| | $ | 10.62 |
|
| Severance tax and marketing | | | $ | 3.53 |
| | $ | 2.72 |
| | $ | 3.42 |
| | $ | 2.74 |
|
| Exploration and abandonment expense | | | $ | 3.75 |
| | $ | 9.33 |
| | $ | 14.84 |
| | $ | 9.09 |
|
| Impairment of proved oil and gas property | | | $ | 11.65 |
| | $ | — |
| | $ | 6.81 |
| | $ | — |
|
| General and administrative expense (see Footnote 1 below) | | | $ | 14.24 |
| | $ | 16.66 |
| | $ | 17.79 |
| | $ | 15.60 |
|
| Depletion, depreciation and accretion | | | $ | 27.61 |
| | $ | 22.49 |
| | $ | 28.47 |
| | $ | 20.87 |
|
| | | | | | | | | | |
| Midstream and oilfield service segments (in thousands) | | | | | | | | | |
| Midstream and marketing operations segment revenue | | | $ | 14,413 |
| | $ | 4,199 |
| | $ | 30,309 |
| | $ | 5,360 |
|
| Midstream and marketing operations segment expense | | | $ | 13,414 |
| | $ | 1,971 |
| | $ | 26,845 |
| | $ | 2,091 |
|
| Oilfield services segment revenue | | | $ | 3,612 |
| | $ | 957 |
| | $ | 7,305 |
| | $ | 4,614 |
|
| Oilfield services segment expense | | | $ | 4,066 |
| | $ | 1,567 |
| | $ | 7,401 |
| | $ | 3,567 |
|
MAGNUM HUNTER RESOURCES CORPORATION
CONSOLIDATED BALANCE SHEETS
(In thousands, except share and per share data)
|
| | | | | | | | |
| | | June 30,
2013 | | December 31, 2012 |
| | | (unaudited) | | |
|
| ASSETS | | | | |
| CURRENT ASSETS: | | |
| | |
|
| Cash and cash equivalents | | $ | 32.742 |
| | $ | 57,623 |
|
| Restricted cash | | — |
| | 1,500 |
|
| Accounts receivable, net of allowance for doubtful accounts of $444 and $448 as of June 30, 2013 and December 31, 2012, respectively | | 72,094 |
| | 124,861 |
|
| Derivative assets | | 3,205 |
| | 5,146 |
|
| Inventory | | 13,088 |
| | 9,162 |
|
| Investments | | 49,294 |
| | 3,278 |
|
| Prepaid expenses and other assets | | 2,977 |
| | 2,249 |
|
| Assets held for sale | | 500 |
| | 500 |
|
| Total current assets | | 173,900 |
| | 204,319 |
|
| | | | | |
| PROPERTY, PLANT AND EQUIPMENT: | | |
| | |
|
| Oil and natural gas properties, successful efforts method of accounting | | 1,737,830 |
| | 1,908,118 |
|
| Accumulated depletion, depreciation, and accretion | | (187,810 | ) | | (185,615 | ) |
| Total oil and natural gas properties, net | | 1,550,020 |
| | 1,722,503 |
|
| Gas transportation, gathering and processing equipment, net | | 247,720 |
| | 201,910 |
|
| Total property and equipment, net | | 1,797,740 |
| | 1,924,413 |
|
| | | | | |
| OTHER ASSETS: | | |
| | |
|
| Deferred financing costs, net of amortization of $8,886 and $8,024 as of June 30, 2013 and December 31, 2012, respectively | | 21,610 |
| | 23,862 |
|
| Derivatives and other assets | | 4,452 |
| | 6,455 |
|
| Intangible assets, net | | 7,616 |
| | 8,981 |
|
| Goodwill | | 30,602 |
| | 30,602 |
|
| Total assets | | $ | 2,035,920 |
| | $ | 2,198,632 |
|
MAGNUM HUNTER RESOURCES CORPORATION
CONSOLIDATED BALANCE SHEETS
(In thousands, except share and per share data)
|
| | | | | | | | |
| | | June 30, 2013 | | December 31, 2012 |
| LIABILITIES AND SHAREHOLDERS' EQUITY | | (unaudited) | | |
|
| CURRENT LIABILITIES: | | |
| | |
|
| Current portion of notes payable | | $ | 4,353 |
| | $ | 3,991 |
|
| Accounts payable | | 120,375 |
| | 196,515 |
|
| Accrued liabilities | | 10,520 |
| | 11,212 |
|
| Revenue payable | | 19,189 |
| | 20,394 |
|
| Derivatives and other liabilities | | 20,581 |
| | 11,544 |
|
| Total current liabilities | | 175,018 |
| | 243,656 |
|
| | | | | |
| Long-term debt | | 665,318 |
| | 886,769 |
|
| Asset retirement obligation | | 30,258 |
| | 28,322 |
|
| Deferred tax liability | | 66,881 |
| | 74,258 |
|
| Derivative liabilities | | 56,123 |
| | 47,524 |
|
| Other long term liabilities | | 5,521 |
| | 5,573 |
|
| Total liabilities | | 999,119 |
| | 1,286,102 |
|
| COMMITMENTS AND CONTINGENCIES (Note 14) | | | | |
| REDEEMABLE PREFERRED STOCK: | | |
| | |
|
| Series C Cumulative Perpetual Preferred Stock ("Series C Preferred Stock"), cumulative dividend rate 10.25% per annum, 4,000,000 authorized, 4,000,000 issued and outstanding as of June 30, 2013 and December 31, 2012, respectively, with liquidation preference of $25.00 per share | | 100,000 |
| | 100,000 |
|
| Series A Convertible Preferred Units of Eureka Hunter Holdings, LLC, cumulative distribution rate of 8.0% per annum, 8,902,326 and 7,672,892 issued and outstanding as of June 30, 2013 and December 31, 2012, respectively, with liquidation preference of $202,446 and $167,403 as of June 30, 2013 and December 31, 2012, respectively | | 121,271 |
| | 100,878 |
|
| | | 221,271 |
| | 200,878 |
|
| SHAREHOLDERS' EQUITY: | | |
| | |
|
| Preferred Stock, 10,000,000 shares authorized | | | | |
| Series D Cumulative Preferred Stock ("Series D Preferred Stock"), cumulative dividend rate 8.0% per annum, 5,750,000 authorized, 4,424,889 and 4,208,821 issued and outstanding as of June 30, 2013 and December 31, 2012, respectively, with liquidation preference of $50.00 per share | | 221,244 |
| | 210,441 |
|
| Series E Cumulative Convertible Preferred Stock ("Series E Preferred Stock"), cumulative dividend rate 8.0% per annum, 12,000 authorized, 3,803 and 3,775 issued and 3,722 and 3,705 outstanding as of June 30, 2013 and December 31, 2012, respectively, with liquidation preference of $25,000 per share | | 95,069 |
| | 94,371 |
|
| Common stock, $0.01 par value per share, 350,000,000 and 250,000,000 shares authorized, and 170,670,884 and 170,032,999 issued, and 169,755,932 and 169,118,047 outstanding as of June 30, 2013 and December 31, 2012, respectively | | 1,706 |
| | 1,700 |
|
| Exchangeable common stock, par value $0.01 per share, none and 505,835 issued and outstanding as of June 30, 2013 and December 31, 2012, respectively | | — |
| | 5 |
|
| Additional paid in capital | | 722,302 |
| | 715,033 |
|
| Accumulated deficit | | (213,858 | ) | | (307,484 | ) |
| Accumulated other comprehensive loss | | (16,239 | ) | | (8,889 | ) |
| Treasury Stock, at cost: | | | | |
| Series E Preferred Stock, 81 and 70 shares as of June 30, 2013 and December 31, 2012, respectively | | (2,030 | ) | | (1,750 | ) |
| Common stock, 914,952 shares as of June 30, 2013 and December 31, 2012 | | (1,914 | ) | | (1,914 | ) |
| Total Magnum Hunter Resources Corporation shareholders' equity | | 806,280 |
| | 701,513 |
|
| Non-controlling interest | | 9,250 |
| | 10,139 |
|
| Total shareholders' equity | | 815,530 |
| | 711,652 |
|
| Total liabilities and shareholders' equity | | $ | 2,035,920 |
| | $ | 2,198,632 |
|
MAGNUM HUNTER RESOURCES CORPORATION
UNAUDITED CONSOLIDATED STATEMENT OF OPERATIONS
(In thousands, except share and per share data)
|
| | | | | | | | | | | | | | | | |
| | | Three Months Ended June 30, | | Six Months Ended June 30, |
| | | 2013 | | 2012 | | 2013 | | 2012 |
| REVENUE: | | | | | | | | |
| Oil and gas sales | | $ | 66,457 |
| | $ | 37,185 |
| | $ | 119,022 |
| | $ | 74,967 |
|
| Gas transportation, gathering, processing, and marketing | | 14,413 |
| | 4,199 |
| | 30,309 |
| | 5,360 |
|
| Oilfield services | | 3,612 |
| | 957 |
| | 7,305 |
| | 4,614 |
|
| Gain (loss) on sale of assets and other revenue | | (442 | ) | | 117 |
| | (419 | ) | | (154 | ) |
| Total revenue | | 84,040 |
| | 42,458 |
| | 156,217 |
| | 84,787 |
|
| EXPENSES: | | | | | | | | |
| Lease operating expenses | | 20,609 |
| | 10,700 |
| | 32,740 |
| | 21,540 |
|
| Severance taxes and marketing | | 4,852 |
| | 2,740 |
| | 8,045 |
| | 5,559 |
|
| Exploration and abandonments | | 5,157 |
| | 9,409 |
| | 34,940 |
| | 18,425 |
|
| Impairment of proved oil and gas properties | | 16,034 |
| | — |
| | 16,034 |
| | — |
|
| Gas transportation, gathering, processing, and marketing | | 13,414 |
| | 1,971 |
| | 26,845 |
| | 2,091 |
|
| Oilfield services | | 4,066 |
| | 1,567 |
| | 7,401 |
| | 3,567 |
|
| Depletion, depreciation, amortization and accretion | | 37,986 |
| | 22,669 |
| | 67,040 |
| | 42,322 |
|
| General and administrative | | 19,601 |
| | 16,796 |
| | 41,907 |
| | 31,639 |
|
| Total expenses | | 121,719 |
| | 65,852 |
| | 234,952 |
| | 125,143 |
|
| | | | | | | | | |
| OPERATING LOSS | | (37,679 | ) | | (23,394 | ) | | (78,735 | ) | | (40,356 | ) |
| | | | | | | | | |
| OTHER INCOME (EXPENSE): | | | | | | | | |
| Interest income | | 94 |
| | 62 |
| | 205 |
| | 96 |
|
| Interest expense | | (18,842 | ) | | (19,432 | ) | | (37,593 | ) | | (24,816 | ) |
| Gain (loss) on derivative contracts, net | | 6,400 |
| | 18,104 |
| | (1,091 | ) | | 19,207 |
|
| Other income | | 1,466 |
| | 931 |
| | 2,488 |
| | 1,965 |
|
| Total other income (expense) | | (10,882 | ) | | (335 | ) | | (35,991 | ) | | (3,548 | ) |
| Loss from continuing operations before income tax | | (48,561 | ) | | (23,729 | ) | | (114,726 | ) | | (43,904 | ) |
| Income tax benefit | | 37,370 |
| | 3,001 |
| | 48,420 |
| | 5,293 |
|
| Loss from continuing operations, net of tax | | (11,191 | ) | | (20,728 | ) | | (66,306 | ) | | (38,611 | ) |
| Income from discontinued operations, net of tax | | 3,793 |
| | 6,273 |
| | 14,208 |
| | 11,374 |
|
| Gain (loss) on sale of discontinued operations, net of tax | | 172,452 |
| | — |
| | 172,452 |
| | 2,224 |
|
| Net income (loss) | | 165,054 |
| | (14,455 | ) | | 120,354 |
| | (25,013 | ) |
| Net (income) loss attributable to non-controlling interest | | 386 |
| | (48 | ) | | 889 |
| | (22 | ) |
| Net income (loss) attributable to Magnum Hunter Resources Corporation | | 165,440 |
| | (14,503 | ) | | 121,243 |
| | (25,035 | ) |
| Dividends on preferred stock | | (14,129 | ) | | (8,205 | ) | | (27,617 | ) | | (12,860 | ) |
| Net income (loss) attributable to common shareholders | | $ | 151,311 |
| | $ | (22,708 | ) | | $ | 93,626 |
| | $ | (37,895 | ) |
| Weighted average number of common shares outstanding, basic and diluted | | 169,690,622 |
| | 151,464,372 |
| | 169,657,806 |
| | 142,293,282 |
|
| Loss from continuing operations per share, basic and diluted | | $ | (0.36 | ) | | $ | (0.19 | ) | | $ | (0.8 | ) | | $ | (0.37 | ) |
| Income from discontinued operations per share, basic and diluted | | 1.25 |
| | 0.04 |
| | 1.35 |
| | 0.1 |
|
| Net income (loss) per common share, basic and diluted | | $ | 0.89 |
| | $ | (0.15 | ) | | $ | 0.55 |
| | $ | (0.27 | ) |
| | | | | | | | | |
| Amounts attributable to Magnum Hunter Resources Corporation: | | | | | | | | |
| Loss from continuing operations, net of tax | | $ | (46,554 | ) | | $ | (20,776 | ) | | $ | (107,362 | ) | | $ | (38,633 | ) |
| Income from discontinued operations, net of tax | | 211,994 |
| | 6,273 |
| | 228,605 |
| | 13,598 |
|
| Net income (loss) | | $ | 165,440 |
| | $ | (14,503 | ) | | $ | 121,243 |
| | $ | (25,035 | ) |
MAGNUM HUNTER RESOURCES CORPORATION
UNAUDITED CONSOLIDATED STATEMENT OF CASH FLOWS
(In thousands, except share and per share data)
|
| | | | | | | | |
| | | Six Months Ended June 30, |
| | | 2013 | | 2012 |
| Cash flows from operating activities | | | | |
| Net income | | $ | 120,354 |
| | $ | (25,013 | ) |
| Adjustments to reconcile net loss to net cash provided by (used in) operating activities: | | | | |
| Depletion, depreciation, amortization and accretion | | 73,078 |
| | 56,860 |
|
| Exploration and abandonments | | 34,168 |
| | 17,693 |
|
| Impairment of proved oil and gas properties | | 16,034 |
| | — |
|
| Impairment of other operating assets | | 263 |
| | — |
|
| Share based compensation | | 8,699 |
| | 12,539 |
|
| Cash paid for plugging wells | | — |
| | (101 | ) |
| Gain on sale of assets | | (206,082 | ) | | (3,369 | ) |
| Unrealized (gain) loss on derivative contracts | | 786 |
| | (13,469 | ) |
| Unrealized loss on investments | | 1,152 |
| | 265 |
|
| Amortization and write-off of deferred financing costs and discount on Senior Notes included in interest expense | | 2,758 |
| | 10,086 |
|
| Deferred tax benefit | | (6,475 | ) | | (3,811 | ) |
| Changes in operating assets and liabilities: | | | | |
| Accounts receivable, net | | 7,760 |
| | (2,530 | ) |
| Inventory | | (459 | ) | | (1,231 | ) |
| Prepaid expenses and other current assets | | (802 | ) | | (991 | ) |
| Accounts payable | | 24,099 |
| | (10,340 | ) |
| Revenue payable | | (1,204 | ) | | 3,356 |
|
| Accrued liabilities | | (261 | ) | | 9,221 |
|
| Net cash provided by operating activities | | 73,868 |
| | 49,165 |
|
| Cash flows from investing activities | | | | |
| Capital expenditures and advances | | (277,492 | ) | | (224,925 | ) |
| Cash paid in acquisitions | | — |
| | (434,322 | ) |
| Change in restricted cash | | 1,500 |
| | — |
|
| Change in deposits and other long-term assets | | 154 |
| | (256 | ) |
| Proceeds from sales of assets | | 380,036 |
| | 783 |
|
| Net cash provided by (used in) investing activities | | 104,198 |
| | (658,720 | ) |
| Cash flows from financing activities | | | | |
| Net proceeds from sale of common shares | | — |
| | 148,675 |
|
| Net proceeds from sale of preferred shares | | 10,181 |
| | 50,883 |
|
| Fees on preferred shares issued in acquisition | | (109 | ) | | — |
|
| Proceeds from sale of Series A convertible preferred units in Eureka Hunter Holdings, LLC | | 19,600 |
| | 127,393 |
|
| Proceeds from exercise of warrants and options | | — |
| | 1,197 |
|
| Preferred stock dividend paid | | (10,424 | ) | | (9,531 | ) |
| Principal repayments of debt | | (327,076 | ) | | (466,209 | ) |
| Proceeds from borrowings on debt | | 105,991 |
| | 341,684 |
|
| Proceeds from issuing Senior Notes | | — |
| | 443,971 |
|
| Payment of deferred financing costs | | (701 | ) | | (18,709 | ) |
| Change in other long-term liabilities | | (52 | ) | | 145 |
|
| Net cash provided by (used in) financing activities | | (202,590 | ) | | 619,499 |
|
| Effect of exchange rate changes on cash | | (357 | ) | | (33 | ) |
| Net increase (decrease) in cash and cash equivalents | | (24,881 | ) | | 9,911 |
|
| Cash and cash equivalents, beginning of period | | 57,623 |
| | 14,851 |
|
| Cash and cash equivalents, end of period | | $ | 32,742 |
| | $ | 24,762 |
|
| | | | | |
| Supplemental disclosure of cash flow information | | | | |
| Cash paid for interest | | $ | 34,448 |
| | $ | 10,434 |
|
| Non-cash transactions | | | | |
| Common stock issued for acquisitions | | $ | — |
| | $ | 1,902 |
|
| Non-cash consideration received from sale of assets | | $ | 42,300 |
| | $ | 7,087 |
|
| Change in accrued capital expenditures | | $ | (42,774 | ) | | $ | 25,505 |
|
| Non-cash additions to asset retirement obligation | | $ | 1,896 |
| | $ | 2,055 |
|
| Eureka Hunter Series A common units issued for acquisition | | $ | — |
| | $ | 12,453 |
|
| Eureka Hunter Holdings, LLC Series A convertible preferred unit dividends paid in kind | | $ | 2,253 |
| | $ | — |
|
Reconciliations
|
| | | | | | | | | | | | | | | | |
| Adjusted Loss per Common Share Reconciliation | | Three Months Ended | | Six Months Ended |
| | | June 30, | | June 30, |
| ($ in thousands) | | 2013 | | 2012 | | 2013 | | 2012 |
| | | | | | | | | |
| Net income (loss) attributable to common shareholders - reported | | $ | 151,311 |
| | $ | (22,708 | ) | | $ | 93,626 |
| | $ | (37,895 | ) |
| | | | | | | | | |
| Non-recurring and non-cash items: | | | | | | | | |
| Exploration and abandonment expense | | $ | 5,157 |
| | $ | 9,409 |
| | $ | 34,940 |
| | $ | 18,425 |
|
| Impairment of oil and gas properties | | $ | 16,034 |
| | $ | — |
| | $ | 16,034 |
| | $ | — |
|
| Non-cash: stock compensation expense | | $ | 2,450 |
| | $ | 7,922 |
| | $ | 8,699 |
| | $ | 12,539 |
|
| Non-cash: 401k matching expense | | $ | 150 |
| | $ | — |
| | $ | 299 |
| | $ | — |
|
| Non-recurring transaction and other expense | | $ | 8,702 |
| | $ | 2,440 |
| | $ | 15,045 |
| | $ | 5,303 |
|
| Unrealized (gain) loss on investments | | $ | 546 |
| | $ | 265 |
| | $ | 1,152 |
| | $ | 265 |
|
| Interest expense - fees | | $ | 1,901 |
| | $ | 9,523 |
| | $ | 2,758 |
| | $ | 10,086 |
|
| Unrealized (gain) loss on derivatives | | $ | (7,661 | ) | | $ | (13,853 | ) | | $ | 786 |
| | $ | (13,469 | ) |
| (Gain) loss on sale of assets | | $ | 1,181 |
| | $ | (100 | ) | | $ | 1,162 |
| | $ | 174 |
|
| Income tax (benefit) | | $ | (37,370 | ) | | $ | (3,001 | ) | | $ | (48,420 | ) | | $ | (5,293 | ) |
| (Gain) loss from sale of discontinued operations | | $ | (172,452 | ) | | $ | — |
| | $ | (172,452 | ) | | $ | (2,224 | ) |
| Income from discontinued operations | | $ | (3,793 | ) | | $ | (6,273 | ) | | $ | (14,208 | ) | | $ | (11,374 | ) |
| | | | | | | | | |
| Total non-recurring and non-cash items | | $ | (185,156 | ) | | $ | 6,332 |
| | $ | (154,205 | ) | | $ | 14,432 |
|
| | | | | | | | | |
| Net income (loss) attributable to common shareholders - recurring | | $ | (33,845 | ) | | $ | (16,376 | ) | | $ | (60,579 | ) | | $ | (23,463 | ) |
| Net income (loss) from discontinued operations | | $ | 3,793 |
| | $ | 6,273 |
| | $ | 14,208 |
| | $ | 11,374 |
|
| | | | | | | | | |
| Net income (loss) attributable to common shareholders - recurring | | $ | (0.20 | ) | | $ | (0.11 | ) | | $ | (0.36 | ) | | $ | (0.16 | ) |
| Net income (loss) from discontinued operations (1) | | $ | 0.02 |
| | $ | 0.04 |
| | $ | 0.08 |
| | $ | 0.08 |
|
| Net income (loss) per common share - basic and diluted (including the effect of discontinued operations) | | $ | (0.18 | ) | | $ | (0.07 | ) | | $ | (0.28 | ) | | $ | (0.08 | ) |
| | | | | | | | | |
| (1) Results include net income from the Eagle Ford Hunter, Inc. operations sold on April 24, 2013. These operations were classified as a discontinued operation for the six months ended June 30, 2013. |
|
| | | | | | | | | | | | | | | | |
| Adjusted EBITDAX Reconciliation | | | | | | | | |
| | | Three Months Ended | | Six Months Ended |
| | | June 30, | | June 30, |
| ($ in thousands) | | 2013 | | 2012 | | 2013 | | 2012 |
| | | | | | | | | |
| Net income (loss) from continuing operations | | $ | (11,191 | ) | | $ | (20,728 | ) | | $ | (66,306 | ) | | $ | (38,611 | ) |
| Net Interest expense | | $ | 18,748 |
| | $ | 19,370 |
| | $ | 37,388 |
| | $ | 24,720 |
|
| (Gain) loss on sale of assets | | $ | 1,181 |
| | $ | (100 | ) | | $ | 1,162 |
| | $ | 174 |
|
| Depletion, depreciation and amortization | | $ | 37,986 |
| | $ | 22,669 |
| | $ | 67,040 |
| | $ | 42,322 |
|
| Impairment of oil and gas properties | | $ | 16,034 |
| | $ | — |
| | $ | 16,034 |
| | $ | — |
|
| Exploration and abandonment expense | | $ | 5,157 |
| | $ | 9,409 |
| | $ | 34,940 |
| | $ | 18,425 |
|
| Non-cash stock compensation expense | | $ | 2,449 |
| | $ | 7,922 |
| | $ | 8,699 |
| | $ | 12,539 |
|
| Non-cash 401k matching expense | | $ | 150 |
| | $ | — |
| | $ | 299 |
| | $ | — |
|
| Non-recurring transaction and other expense | | $ | 8,702 |
| | $ | 2,440 |
| | $ | 15,045 |
| | $ | 5,303 |
|
| Unrealized (gain) loss on investments | | $ | 546 |
| | $ | 265 |
| | $ | 1,152 |
| | $ | 265 |
|
| Income tax (benefit) | | $ | (37,370 | ) | | $ | (3,001 | ) | | $ | (48,420 | ) | | $ | (5,293 | ) |
| Unrealized (gain) loss on derivatives | | $ | (7,661 | ) | | $ | (13,853 | ) | | $ | 786 |
| | $ | (13,469 | ) |
| Total Adjusted EBITDAX from continuing operations | | $ | 34,731 |
| | $ | 24,393 |
| | $ | 67,819 |
| | $ | 46,375 |
|
| Total Adjusted EBITDAX from discontinued operations (1) | | $ | 3,793 |
| | $ | 14,085 |
| | $ | 20,246 |
| | $ | 25,908 |
|
| Total Adjusted EBITDAX (including the effect of discontinued operations) | | $ | 38,524 |
| | $ | 38,478 |
| | $ | 88,065 |
| | $ | 72,283 |
|
| | | | | | | | | |
| (1) Total Adjusted EBITDAX from discontinued operations represents net income plus DD&A associated with Eagle Ford Hunter operations through April 24, 2013. These operations were sold on April 24, 2013, and have been classified as a discontinued operation for the six months ended June 30, 2013. |
|
| | | | | | | | | | | | | | | | |
| Recurring Cash G&A Reconciliation | | | | | | | | |
| | | Three Months Ended | | Six Months Ended |
| | | June 30, | | June 30, |
| ($ in thousands) | | 2013 | | 2012 | | 2013 | | 2012 |
| | | | | | | | | |
| Total G&A | | $ | 19,601 |
| | $ | 16,796 |
| | $ | 41,907 |
| | $ | 31,639 |
|
| | | | | | | | | |
| Adjustments: | | | | | | | | |
| Non-cash stock compensation | | $ | 2,449 |
| | $ | 7,922 |
| | $ | 8,699 |
| | $ | 12,539 |
|
| Transaction and other non-recurring expense | | $ | 6,412 |
| | $ | 2,319 |
| | $ | 12,522 |
| | $ | 4,541 |
|
| Recurring Cash G&A | | $ | 10,740 |
| | $ | 6,555 |
| | $ | 20,685 |
| | $ | 14,559 |
|
| | | | | | | | | |
| Recurring Cash G&A Per BOE | | $ | 7.8 |
| | $ | 6.5 |
| | $ | 8.79 |
| | $ | 7.18 |
|
Contact:
Chris Benton
AVP, Finance and Capital Markets
ir@magnumhunterresources.com
(832) 203-4539
