Magnum Hunter Resources Reports Fourth Quarter and Full Year 2013 Financial and Operating Results
HOUSTON, TX -- (Marketwired) -- 02/24/14 -- Magnum Hunter Resources Corporation (NYSE: MHR) (NYSE MKT: MHR.PRC) (NYSE MKT: MHR.PRD) (NYSE MKT: MHR.PRE) (the "Company" or "Magnum Hunter") announced today financial and operating results for the three months and twelve months ended December 31, 2013. The Company plans to file its Form 10-K for the year ended December 31, 2013 with the Securities and Exchange Commission tomorrow, Tuesday, February 25, 2014. Highlights of the Company's financial and operating results include the following:
(b) Adjusted production includes 2,118 BOEPD of actual production from discontinued operations, and, on a pro forma basis, shut-in and curtailed production of 1,970 BOEPD in Appalachia
Financial and Operating Results for the Three Months Ended December 31, 2013
Magnum Hunter reported an increase in oil and gas revenues of 64% to $59.4 million for the three months ended December 31, 2013, compared with $36.1 million for the three months ended December 31, 2012. The increase in oil and gas revenues resulted principally from (i) increases in the Company's oil and natural gas production as a result of prior acquisitions and expanded drilling efforts in the Company's unconventional resources plays this past year and (ii) higher average realized commodity prices for the period. Midstream and marketing revenues also increased to $18.2 million for the three months ended December 31, 2013, or 595%, from $2.6 million for the three months ended December 31, 2012. The increase in midstream and marketing revenues was due primarily to (i) increased throughput volumes on the Eureka Hunter Pipeline System, (ii) increased utilization of TransTex Hunter, LLC's gas treating and processing equipment and (iii) increased third-party gas marketing volumes.
The Company reported a net loss of ($61.2) million attributable to common shareholders, or ($0.36) per basic and diluted common shares outstanding, for the three months ended December 31, 2013, compared with a net loss of ($87.2) million, or ($0.52) per basic and diluted common shares outstanding, for the three months ended December 31, 2012. When adjusted for a combination of 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 December 31, 2013 was ($0.14) per basic and diluted common shares outstanding (see Non-GAAP Financial Measures and Reconciliations below).
For the three months ended December 31, 2013, Magnum Hunter's Adjusted Earnings Before Interest, Income Taxes, Depreciation, Amortization and Exploration ("Adjusted EBITDAX") was $37.0 million, compared with $24.1 million for the three months ended December 31, 2012 (See Non-GAAP Financial Measures and Reconciliations below), an increase of 54%. The increase in Adjusted EBITDAX was due primarily to (i) an overall production increase as a result of prior acquisitions and expanded drilling operations with a greater focus on oil and liquids as a percentage of total production (56.7% oil/liquids) in the Company's core areas of operations and (ii) higher average realized commodity prices during the period. However, natural gas production shut-ins (described below), and higher lease operating expenses ("LOE") per barrel of oil equivalent ("BOE") partially offset these increases. The increase in LOE per BOE was primarily due to (i) higher costs in the Appalachian region due to increased liquids production which generally have higher LOE per BOE than natural gas production, (ii) higher gas transportation reservation charges and (iii) increased maintenance, labor, transportation and electrification costs in the Williston Basin. The Company anticipates LOE in the Williston Basin to decrease over time due to increased efficiencies at the field level which continue to be implemented. Recurring general and administrative expenses per BOE for the three months ended December 31, 2013 decreased 34% to $6.32 per BOE from $9.54 per BOE during the three months ended December 31, 2012, primarily due to (i) production increases during the period and (ii) less reliance on third-party consultants (See Non-GAAP Financial Measures and Reconciliations below). The Company anticipates that its reliance on third-party consultants will continue to decrease, thus reducing its recurring general and administrative expenses per BOE.
Oil and gas production increased 44.0% for the three months ended December 31, 2013 to 1.039 million BOE ("MMBoe") or an average of 11,298 BOE per day ("Boe/d") (56.7% oil/liquids), compared with production of 722 thousand BOE ("MBoe") or an average of 7,846 Boe/d for the three months ended December 31, 2012. The increase in production was attributable primarily to the Company's expanded drilling program in its core areas of operations. In addition, the Company's oil/liquids production mix increased to 56.7% of overall production in the fourth quarter of 2013, compared with 44.0% in the fourth quarter of 2012. This increase is a result of (i) last year's shift in our capital expenditure program towards more of an oil and liquids rich development program and (ii) shut-in production during the period due to adverse weather and pipeline delays. For the three months ended December 31, 2013, adjusted production, which includes actual production from continuing operations, actual production from discontinued operations of 2,118 Boe/d and production shut-ins of 1,970 Boe/d as described below, increased 96.1% to 15,386 Boe/d(b) compared with 7,846 Boe/d for the three months ended December 31, 2012.
In the fourth quarter of 2013, the Company's production was impacted by production shut-ins in the Appalachian region primarily due to the previously reported shut-down of MarkWest's Mobley processing facilities from August 2013 to early October 2013 as a result of a break in a MarkWest natural gas liquids pipeline. All processing plant issues affecting the production of the Company's Marcellus Shale natural gas were resolved in mid-October 2013, and all such natural gas production is now flowing through the Eureka Hunter Pipeline System for processing at the Mobley processing facilities. The Mobley processing facilities' shut-down resulted in a decrease in the Company's daily production by approximately 925 Boe/d for the three months ended December 31, 2013. The Company also experienced approximately 1,045 Boe/d of curtailments for the three months ended December 31, 2013 at its Ormet Pad location in Ohio as a result of the Company's continued build out of midstream infrastructure and liquids handling equipment and delays in obtaining certain air permits.
Financial and Operating Results for the Twelve Months Ended December 31, 2013
Magnum Hunter reported an increase in oil and gas revenues of 72.3% to $197.6 million for the twelve months ended December 31, 2013, compared with $114.7 million for the twelve months ended December 31, 2012. The increase in oil and gas revenues resulted principally from increases in our oil and natural gas production as a result of (i) acquisitions and expanded drilling operations in the Company's unconventional resources plays throughout 2013 and (ii) higher average realized commodity prices during the period. Midstream and marketing revenues increased to $60.6 million for the twelve months ended December 31, 2013, or 365.0%, from $13.0 million for the twelve months ended December 31, 2012. The increase in midstream and marketing revenues was primarily due to (i) increased throughput volumes of the Eureka Hunter Pipeline System, (ii) increased utilization of TransTex Hunter, LLC's gas treating and processing equipment and (iii) increased third-party gas marketing volumes.
The Company reported a net loss of ($278.9) million attributable to common shareholders, or ($1.64) per basic and diluted common shares outstanding, for the twelve months ended December 31, 2013, compared with a net loss of ($167.4) million, or ($1.07) per basic and diluted common shares outstanding, for the twelve months ended December 31, 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 twelve months ended December 31, 2013 was ($0.65) per basic and diluted common shares outstanding (see Non-GAAP Financial Measures and Reconciliations below).
For the twelve months ended December 31, 2013, Magnum Hunter's Adjusted EBITDAX was $112.4 million, compared with $76.2 million for the twelve months ended December 31, 2012 (See Non-GAAP Financial Measures and Reconciliations below). The 48% increase in Adjusted EBITDAX was primarily due to (i) an overall production increase as a result of prior acquisitions and expanded drilling operations with a greater focus on oil and liquids as a percentage of total production (52.0% oil/liquids) in the Company's core areas of operations and (ii) higher average realized commodity prices during the period. 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 per BOE was primarily due to (i) higher costs in the Appalachian region due to increased liquids production which generally have higher LOE per BOE than natural gas production, (ii) higher gas transportation reservation charges and (iii) increased maintenance, labor, transportation and electrification costs in the Williston Basin. The Company anticipates LOE in the Williston Basin to decrease over time due to increased efficiencies at the field level which continue to be implemented. General and administrative expenses increased overall during the twelve months ended December 31, 2013 due to (i) expansion activities necessitated by the growth of the Company and (ii) its focus on remediation of previously identified internal control deficiencies. The Company anticipates that its reliance on third-party consultants will continue to decrease in fiscal 2014, thus reducing its recurring general and administrative expenses per BOE.
Oil and gas production increased 26.9% for the twelve months ended December 31, 2013 to 3.593 MMBoe or an average of 9,845 Boe/d (52.0% oil/liquids), compared with 2.832 MMBoe or an average of 7,739 Boe/d for the twelve months ended December 31, 2012. The increase in production was attributable primarily to the Company's expanded drilling program in its core areas of operations. In addition, the Company's oil/liquids production mix increased to 52.0% of overall production for the twelve months ended December 31, 2013, compared with 34.0% for the twelve months ended December 31, 2012. For the twelve months ended December 31, 2013, adjusted production, which includes actual production from continuing operations, production from discontinued operations of 2,925 Boe/d and production shut-ins of 2,061 Boe/d as described above, increased 91.6% to 14,831 Boe/d compared with 7,739 Boe/d for the twelve months ended December 31, 2012.
2013 Significant Divestitures
During 2013, Magnum Hunter completed several divestitures resulting in proceeds in excess of $500 million, including purchase price adjustments. The Company successfully divested its Eagle Ford assets in Lavaca and Gonzales Counties, in South Texas, for a contracted price of $401 million to Penn Virginia Corporation ("PVA") (and recorded a gain of $8.3 million on the sale of the PVA stock received as partial consideration for such sale), properties in Burke County, North Dakota for $32.5 million and legacy waterfloods in North Dakota for $45 million.
Capital Expenditures and Liquidity
Magnum Hunter's total upstream and midstream capital expenditures, including leasehold acquisitions, were $173.3 million for the three months ended December 31, 2013. Total upstream capital expenditures for the three months ended December 31, 2013 were $76.9 million, consisting of $19.7 million for the Williston Basin, $53.0 million for the Appalachian region and $4.2 million for the South Texas region. Leasehold acquisition expenditures for the three months ended December 31, 2013, were $56.2 million with a primary emphasis in the Utica and Marcellus Shale plays. Total midstream capital expenditures for such period were $40.2 million.
For the twelve months ended December 31, 2013, total upstream capital expenditures were $301.9 million, consisting of $131.8 million for the Williston Basin, $132.4 million for the Appalachian region and $37.7 million for the South Texas region. Leasehold acquisition expenditures for the twelve months ended December 31, 2013, were $144.3 million with a primary emphasis in the Utica and Marcellus Shale plays. Total midstream capital expenditures for such period were $87.5 million.
Magnum Hunter believes that its internally generated cash flows, anticipated increased borrowing availability under its Senior Revolving Credit Facility resulting from anticipated borrowing base increases, and additional liquidity sources, including but not limited to proceeds from non-core asset sales and potential capital market financings, will provide it with sufficient liquidity to fund its fiscal 2014 capital budget. As of January 31, 2014, the Company had total liquidity of approximately $55.5 million, comprised of approximately $48.5 million of cash and $7.0 million of borrowing availability under its Senior Revolving Credit Facility. To further enhance its liquidity, the Company is actively pursuing up to $400 million (estimated) of non-core asset sales, which the Company expects to close throughout the 2014 fiscal year.
Operations
During the quarter ended December 31, 2013, the Company commenced or participated in the drilling of a total of 23 gross wells, of which 10 were operated by the Company. The Company had a 100% success rate on the 24 wells in which it had a working interest that were completed in the fourth quarter of 2013.
The table below summarizes the Company's gross drilling activities by area for the fourth quarter of 2013:
Currently, the Company is running six drilling rigs (two operated and four non-operated rigs). Of these six rigs, three rigs (two operated and one non-operated) are drilling wells in the Marcellus and Utica Shales in West Virginia and Ohio, and three non-operated rigs are drilling wells in the Williston Basin/Bakken Shale in North Dakota.
Marcellus and Utica Shale
During the fourth quarter of 2013, the Company completed the drilling of 7 gross (7 net) wells and completed 8 gross (6 net) wells in the Marcellus Shale and Utica Shale plays. These 8 gross (6 net) completed wells are currently flowing to sales via the Eureka Hunter Pipeline System. The Company's net production in the fourth quarter of 2013 attributable to Triad Hunter, LLC's operations was approximately 37.6 Mcfe/d, a 24% increase over such production during the fourth quarter of 2012.
The Company's first dry gas Utica Shale well, the Stalder #3UH located on the Stalder Pad (18 potential wells) in Monroe County, Ohio, was placed on production approximately two weeks ago and tested at a peak rate of 32.5 MMCF of natural gas per day on an adjustable rate choke with 4,300 psi FCP. The well continues to flow to sales points via the Eureka Hunter Pipeline System with the amount of frac water continuing to decrease since the commencement of initial sales.
The Company's first Marcellus Shale well drilled on the Stalder Pad, the Stalder #2MH, is awaiting the start of completion operations which the Company expects to commence in the next several weeks. The Stalder #2MH was drilled and cased to a true vertical depth of 6,070 feet with a 5,474 foot horizontal lateral. The Company expects the production from this well to be very liquids rich.
On the Farley Pad located in Washington County, Ohio, the Company has drilled and cased the Farley #1306H well in the Utica Shale to a true vertical depth of 7,850 feet with a 6,313 foot horizontal lateral. The Company has commenced the drilling of another Utica Shale well on the Farley Pad, the Farley #1304H. The Company is currently drilling the vertical section of this well and anticipates reaching a true vertical depth of 7,885 feet, and completing the drilling of a 5,500 foot horizontal lateral, within the next 30 days. Following the drilling of the Farley #1304H, the Company will begin fracture stimulation of these two new Farley wells in mid-March 2014 and expects to report initial production test rates in early-summer 2014 following an approximate 30-day resting period. The Company is in the advanced stages of negotiating new take-away capacity with a third-party midstream company and expects to be ready to flow production of all three wells on the Farley Pad to sales following the resting period.
On the WVDNR Pad located in Wetzel County, West Virginia, the Company has drilled and is in the process of completing three 100% owned Marcellus Shale wells, the WVDRN #1207, #1208 and #1209. The wells were drilled and cased to an average vertical depth of 7,500 feet with a 4,000 foot average horizontal lateral. The Company has fracture stimulated 9 of the proposed 20 stages on each of the three wells. During the last several weeks, the Company has experienced substantial completion delays in this region primarily due to the effects of extreme cold weather conditions. The Company expects to complete fracture stimulating the three WVDNR wells over the next 7 to 10 days, and anticipates production from the wells to begin to flow to sales in mid-March 2014.
On the Stewart Winland Pad located in Tyler County, West Virginia, the Company has drilled and cased the pad's first Marcellus Shale well, the Stewart Winland #1301. The Stewart Winland #1301 was drilled to a true vertical depth of 6,144 feet with a 5,770 foot horizontal lateral. The Company has skid the drilling rig and commenced the drilling of another Marcellus Shale well, the Stewart Winland #1302, on this pad. One additional Marcellus Shale well and one Utica Shale well will be subsequently drilled on this pad. The Company expects to report initial production test rates from the four wells on the Stewart Winland Pad during mid-summer 2014. As previously reported, the Company is in the process of making several production equipment changes at both its Collins and Spencer Pads in Tyler County, West Virginia to better handle the anticipated new liquids production. The Company is on target for these production equipment changes to be completed within the next 30 to 45 days. As a result, the Company does not expect to encounter any liquids infrastructure issues associated with the initial production from the four wells on the Stewart Winland Pad.
Williston Basin
During the fourth quarter of 2013, the Company drilled a total of 15 gross (6.2 net) wells in the Bakken/Three Forks Sanish formations in North Dakota. In the Company operated areas, the Company drilled 2 gross (2.0 net) wells, and in the Company non-operated areas, 13 gross (4.2 net) wells were drilled. During the fourth quarter, (i) six two-mile lateral wells were completed in the Middle Bakken formation, with an average IP 24-hour rate of 561 Boe/d and an average IP 30-day rate of 389 Boe/d, (ii) seven two-mile lateral wells were completed in the Three Forks Sanish formation with an average IP 24-hour rate of 584 Boe/d and an average IP 30-day rate of 287 Boe/d and (iii) three one-mile lateral wells were completed, one in the Three Forks Sanish formation, with an IP 24-hour rate of 760 Boe/d and an IP 30-day rate of 282 Boe/d, and two in the Middle Bakken formation, one with an IP 24-hour rate of 680 Boe/d and an IP 30-day rate of 253 Boe/d and the other for which the Company is still awaiting more complete initial production results. At the end of the fourth quarter of 2013, 12 gross (4.3 net) Company wells were drilling or waiting on fracture stimulation in North Dakota.
Eureka Hunter
As of February 16, 2014, Eureka Hunter Pipeline, LLC, ("Eureka Hunter"), was gathering approximately 171,634 MMBtu/d. The Eureka Hunter Pipeline System's gathering flow through recently hit a peak rate of 198,000 MMBtu/d. Eureka Hunter has connected a significant amount of new Marcellus production volumes from several Triad Hunter, LLC and third-party wells into the Eureka Hunter Pipeline System located in Tyler and Wetzel Counties, West Virginia.
Eureka Hunter is in the process of installing liquids stabilization equipment and loading facilities near its Ohio River crossing near Sardis, Ohio, which are expected to be in full operation during the first quarter of 2014. To further assist with volume demands and to reduce line pressure for producers, Eureka Hunter is also adding new mainline compression at its Carbide facility in Tyler County, West Virginia.
The new Marcellus Shale volumes flowing into Eureka Hunter's gathering system are coupled with the addition of dry Utica Shale production in Ohio from various third-party producers and Triad Hunter, LLC. Eureka Hunter expects to connect significant volumes of new Utica Shale production throughout 2014.
The build out of Eureka Hunter's gathering system in Ohio continues despite weather delays. The first lateral to be completed in Ohio was a 20-inch extension from the Ohio River past Triad Hunter, LLC's Stalder Pad extending approximately 11 miles to the west to gather gas from Eclipse Resources' Tippens pad site. This line is initially gathering dry Utica Shale gas production and was put into service in December 2013. The second Ohio line, the "Ormet lateral", is also a 20-inch line, and is approximately 95% complete at this time. The Company expects to complete the Ormet lateral in April 2014 barring any further weather delays. The necessary liquids handling equipment should also be installed in March 2014 with production anticipated in April 2014.
Other Eureka Hunter pipeline construction projects slated for 2014 include a northerly extension to interconnect with Rocky Mountain Express, Texas Eastern Transmission and possibly Dominion Transmission, all near Clarington, Ohio. Eureka also plans to connect to rich gas production for delivery to the Blue Racer Natrium plant in Marshall County, West Virginia and to a residue gas line extension from the MarkWest Mobley processing facilities tailgate to Columbia Gas. The Company's goal is to have as many production take-away outlets from this region as possible.
Management Comments
Mr. Gary C. Evans, Chairman of the Board and Chief Executive Officer of Magnum Hunter, commented, "Calendar year 2013 was a pivotal year for Magnum Hunter. We made the decision to sell our Eagle Ford assets, producing approximately 3,000 barrels of oil equivalent per day, for a contracted price of $401 million and redeploy those proceeds to our two remaining core areas, Appalachia and the Williston Basin. Revenues were still up over 72% and EBITDAX increased 48%. We drilled 21 gross wells (12.5 net) in the Marcellus and Utica resource plays and drilled 72 gross (24.6 net) in the Bakken and Three Forks Sanish plays of the Williston Basin. All 93 gross wells were deemed commercially successful. We also completed 23 miles of new pipeline in our midstream division, Eureka Hunter, where throughput increased 390%. Our lease acreage position has grown to 957,953 gross acres and 642,643 net acres, most of which is held by existing production which give us a tremendous amount of future inventory. In 2014, we will continue our divestiture efforts with respect to non-core assets which could bring in approximately $400 million of proceeds, an amount much greater than our current capital expenditure funding gap. The high grading of our portfolio is being reflected in our proved reserve additions, higher EUR's per well and higher production rates on new drills. Management's goal will be to continue improving our internal rates of return on every single dollar deployed and drill predominately in the core areas of the shale plays where we operate."
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, (2) impairment of proved 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, amortization and accretion, (4) impairment of proved oil and gas properties, (5) exploration, (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 and North Dakota. The Company is presently active in three of the most prolific unconventional shale resource plays in North America, namely the Marcellus Shale, Utica Shale and Williston Basin/Bakken Shale.
Availability of Information on the Company's Website
Magnum Hunter is providing a reminder that it makes available on its website (atwww.magnumhunterresources.com) a variety of information for investors, analysts and the media, including the following:
Certain information included on the Company's website constitutes forward-looking statements and is subject to the qualifications under the heading "Forward-Looking Statements" below and in the Company's Investor Presentation slide deck.
Forward-Looking Statements
This press release includes "forward-looking statements." All statements other than statements of historical facts included or incorporated herein may constitute forward-looking statements. Actual results could vary significantly from those expressed or implied in such statements and are subject to a number of risks and uncertainties. Although Magnum Hunter believes that the expectations reflected in the forward-looking statements are reasonable, Magnum Hunter can give no assurance that such expectations will prove to be correct. The forward-looking statements involve risks and uncertainties that affect operations, financial performance, and other factors as discussed in filings made by Magnum Hunter with the Securities and Exchange Commission (SEC). Among the factors that could cause results to differ materially are those risks discussed in the periodic reports filed by Magnum Hunter with the SEC, including Magnum Hunter's Annual Report on Form 10-K for the fiscal year ended December 31, 2012, and its to-be-filed Annual Report on Form 10-K for the fiscal year ended December 31, 2013, and its Quarterly Reports on Form 10-Q for the fiscal quarters ended after such fiscal year. You are urged to carefully review and consider the cautionary statements and other disclosures made in those filings, specifically those under the heading "Risk Factors." Forward-looking statements speak only as of the date of the document in which they are contained, and Magnum Hunter does not undertake any duty to update any forward-looking statements except as may be required by law.
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- Oil and gas revenues increased 64% to $59.4 million for the fourth quarter of 2013, compared with revenues of $36.1 million for the fourth quarter of 2012
- Midstream and marketing revenues increased 595% to $18.2 million for the fourth quarter of 2013, compared with revenues of $2.6 million for the fourth quarter of 2012
- Adjusted EBITDAX(a)for the fourth quarter of 2013 and full year 2013 were $37.0 million and $112.4 million, an increase of 54% and 48%, respectively
- Adjusted net loss(a)of ($0.14) per diluted share is reported for the fourth quarter of 2013
- Production of 11,298 BOEPD and adjusted production(b)of 15,386 BOEPD for the fourth quarter of 2013
- Form 10-K to report remediation of 11 of the 14 previously identified material weaknesses in internal controls over financial reporting
- All derivatives contracts for 2014 natural gas production converted from collars to fixed price swaps and 20,000 MMBtu/d of fixed price swaps added for calendar year 2015 natural gas production
- Executed on $69.5 million of non-core asset sales over the last 60 days with up to $400 million of additional non-core asset sales targeted in fiscal 2014
- Current throughput on Eureka Hunter Pipeline System of 171,634 MMBtu/d with a recent peak throughput rate of 198,000 MMBtu/d
(b) Adjusted production includes 2,118 BOEPD of actual production from discontinued operations, and, on a pro forma basis, shut-in and curtailed production of 1,970 BOEPD in Appalachia
Financial and Operating Results for the Three Months Ended December 31, 2013
Magnum Hunter reported an increase in oil and gas revenues of 64% to $59.4 million for the three months ended December 31, 2013, compared with $36.1 million for the three months ended December 31, 2012. The increase in oil and gas revenues resulted principally from (i) increases in the Company's oil and natural gas production as a result of prior acquisitions and expanded drilling efforts in the Company's unconventional resources plays this past year and (ii) higher average realized commodity prices for the period. Midstream and marketing revenues also increased to $18.2 million for the three months ended December 31, 2013, or 595%, from $2.6 million for the three months ended December 31, 2012. The increase in midstream and marketing revenues was due primarily to (i) increased throughput volumes on the Eureka Hunter Pipeline System, (ii) increased utilization of TransTex Hunter, LLC's gas treating and processing equipment and (iii) increased third-party gas marketing volumes.
The Company reported a net loss of ($61.2) million attributable to common shareholders, or ($0.36) per basic and diluted common shares outstanding, for the three months ended December 31, 2013, compared with a net loss of ($87.2) million, or ($0.52) per basic and diluted common shares outstanding, for the three months ended December 31, 2012. When adjusted for a combination of 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 December 31, 2013 was ($0.14) per basic and diluted common shares outstanding (see Non-GAAP Financial Measures and Reconciliations below).
For the three months ended December 31, 2013, Magnum Hunter's Adjusted Earnings Before Interest, Income Taxes, Depreciation, Amortization and Exploration ("Adjusted EBITDAX") was $37.0 million, compared with $24.1 million for the three months ended December 31, 2012 (See Non-GAAP Financial Measures and Reconciliations below), an increase of 54%. The increase in Adjusted EBITDAX was due primarily to (i) an overall production increase as a result of prior acquisitions and expanded drilling operations with a greater focus on oil and liquids as a percentage of total production (56.7% oil/liquids) in the Company's core areas of operations and (ii) higher average realized commodity prices during the period. However, natural gas production shut-ins (described below), and higher lease operating expenses ("LOE") per barrel of oil equivalent ("BOE") partially offset these increases. The increase in LOE per BOE was primarily due to (i) higher costs in the Appalachian region due to increased liquids production which generally have higher LOE per BOE than natural gas production, (ii) higher gas transportation reservation charges and (iii) increased maintenance, labor, transportation and electrification costs in the Williston Basin. The Company anticipates LOE in the Williston Basin to decrease over time due to increased efficiencies at the field level which continue to be implemented. Recurring general and administrative expenses per BOE for the three months ended December 31, 2013 decreased 34% to $6.32 per BOE from $9.54 per BOE during the three months ended December 31, 2012, primarily due to (i) production increases during the period and (ii) less reliance on third-party consultants (See Non-GAAP Financial Measures and Reconciliations below). The Company anticipates that its reliance on third-party consultants will continue to decrease, thus reducing its recurring general and administrative expenses per BOE.
Oil and gas production increased 44.0% for the three months ended December 31, 2013 to 1.039 million BOE ("MMBoe") or an average of 11,298 BOE per day ("Boe/d") (56.7% oil/liquids), compared with production of 722 thousand BOE ("MBoe") or an average of 7,846 Boe/d for the three months ended December 31, 2012. The increase in production was attributable primarily to the Company's expanded drilling program in its core areas of operations. In addition, the Company's oil/liquids production mix increased to 56.7% of overall production in the fourth quarter of 2013, compared with 44.0% in the fourth quarter of 2012. This increase is a result of (i) last year's shift in our capital expenditure program towards more of an oil and liquids rich development program and (ii) shut-in production during the period due to adverse weather and pipeline delays. For the three months ended December 31, 2013, adjusted production, which includes actual production from continuing operations, actual production from discontinued operations of 2,118 Boe/d and production shut-ins of 1,970 Boe/d as described below, increased 96.1% to 15,386 Boe/d(b) compared with 7,846 Boe/d for the three months ended December 31, 2012.
In the fourth quarter of 2013, the Company's production was impacted by production shut-ins in the Appalachian region primarily due to the previously reported shut-down of MarkWest's Mobley processing facilities from August 2013 to early October 2013 as a result of a break in a MarkWest natural gas liquids pipeline. All processing plant issues affecting the production of the Company's Marcellus Shale natural gas were resolved in mid-October 2013, and all such natural gas production is now flowing through the Eureka Hunter Pipeline System for processing at the Mobley processing facilities. The Mobley processing facilities' shut-down resulted in a decrease in the Company's daily production by approximately 925 Boe/d for the three months ended December 31, 2013. The Company also experienced approximately 1,045 Boe/d of curtailments for the three months ended December 31, 2013 at its Ormet Pad location in Ohio as a result of the Company's continued build out of midstream infrastructure and liquids handling equipment and delays in obtaining certain air permits.
Financial and Operating Results for the Twelve Months Ended December 31, 2013
Magnum Hunter reported an increase in oil and gas revenues of 72.3% to $197.6 million for the twelve months ended December 31, 2013, compared with $114.7 million for the twelve months ended December 31, 2012. The increase in oil and gas revenues resulted principally from increases in our oil and natural gas production as a result of (i) acquisitions and expanded drilling operations in the Company's unconventional resources plays throughout 2013 and (ii) higher average realized commodity prices during the period. Midstream and marketing revenues increased to $60.6 million for the twelve months ended December 31, 2013, or 365.0%, from $13.0 million for the twelve months ended December 31, 2012. The increase in midstream and marketing revenues was primarily due to (i) increased throughput volumes of the Eureka Hunter Pipeline System, (ii) increased utilization of TransTex Hunter, LLC's gas treating and processing equipment and (iii) increased third-party gas marketing volumes.
The Company reported a net loss of ($278.9) million attributable to common shareholders, or ($1.64) per basic and diluted common shares outstanding, for the twelve months ended December 31, 2013, compared with a net loss of ($167.4) million, or ($1.07) per basic and diluted common shares outstanding, for the twelve months ended December 31, 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 twelve months ended December 31, 2013 was ($0.65) per basic and diluted common shares outstanding (see Non-GAAP Financial Measures and Reconciliations below).
For the twelve months ended December 31, 2013, Magnum Hunter's Adjusted EBITDAX was $112.4 million, compared with $76.2 million for the twelve months ended December 31, 2012 (See Non-GAAP Financial Measures and Reconciliations below). The 48% increase in Adjusted EBITDAX was primarily due to (i) an overall production increase as a result of prior acquisitions and expanded drilling operations with a greater focus on oil and liquids as a percentage of total production (52.0% oil/liquids) in the Company's core areas of operations and (ii) higher average realized commodity prices during the period. 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 per BOE was primarily due to (i) higher costs in the Appalachian region due to increased liquids production which generally have higher LOE per BOE than natural gas production, (ii) higher gas transportation reservation charges and (iii) increased maintenance, labor, transportation and electrification costs in the Williston Basin. The Company anticipates LOE in the Williston Basin to decrease over time due to increased efficiencies at the field level which continue to be implemented. General and administrative expenses increased overall during the twelve months ended December 31, 2013 due to (i) expansion activities necessitated by the growth of the Company and (ii) its focus on remediation of previously identified internal control deficiencies. The Company anticipates that its reliance on third-party consultants will continue to decrease in fiscal 2014, thus reducing its recurring general and administrative expenses per BOE.
Oil and gas production increased 26.9% for the twelve months ended December 31, 2013 to 3.593 MMBoe or an average of 9,845 Boe/d (52.0% oil/liquids), compared with 2.832 MMBoe or an average of 7,739 Boe/d for the twelve months ended December 31, 2012. The increase in production was attributable primarily to the Company's expanded drilling program in its core areas of operations. In addition, the Company's oil/liquids production mix increased to 52.0% of overall production for the twelve months ended December 31, 2013, compared with 34.0% for the twelve months ended December 31, 2012. For the twelve months ended December 31, 2013, adjusted production, which includes actual production from continuing operations, production from discontinued operations of 2,925 Boe/d and production shut-ins of 2,061 Boe/d as described above, increased 91.6% to 14,831 Boe/d compared with 7,739 Boe/d for the twelve months ended December 31, 2012.
2013 Significant Divestitures
During 2013, Magnum Hunter completed several divestitures resulting in proceeds in excess of $500 million, including purchase price adjustments. The Company successfully divested its Eagle Ford assets in Lavaca and Gonzales Counties, in South Texas, for a contracted price of $401 million to Penn Virginia Corporation ("PVA") (and recorded a gain of $8.3 million on the sale of the PVA stock received as partial consideration for such sale), properties in Burke County, North Dakota for $32.5 million and legacy waterfloods in North Dakota for $45 million.
Capital Expenditures and Liquidity
Magnum Hunter's total upstream and midstream capital expenditures, including leasehold acquisitions, were $173.3 million for the three months ended December 31, 2013. Total upstream capital expenditures for the three months ended December 31, 2013 were $76.9 million, consisting of $19.7 million for the Williston Basin, $53.0 million for the Appalachian region and $4.2 million for the South Texas region. Leasehold acquisition expenditures for the three months ended December 31, 2013, were $56.2 million with a primary emphasis in the Utica and Marcellus Shale plays. Total midstream capital expenditures for such period were $40.2 million.
For the twelve months ended December 31, 2013, total upstream capital expenditures were $301.9 million, consisting of $131.8 million for the Williston Basin, $132.4 million for the Appalachian region and $37.7 million for the South Texas region. Leasehold acquisition expenditures for the twelve months ended December 31, 2013, were $144.3 million with a primary emphasis in the Utica and Marcellus Shale plays. Total midstream capital expenditures for such period were $87.5 million.
Magnum Hunter believes that its internally generated cash flows, anticipated increased borrowing availability under its Senior Revolving Credit Facility resulting from anticipated borrowing base increases, and additional liquidity sources, including but not limited to proceeds from non-core asset sales and potential capital market financings, will provide it with sufficient liquidity to fund its fiscal 2014 capital budget. As of January 31, 2014, the Company had total liquidity of approximately $55.5 million, comprised of approximately $48.5 million of cash and $7.0 million of borrowing availability under its Senior Revolving Credit Facility. To further enhance its liquidity, the Company is actively pursuing up to $400 million (estimated) of non-core asset sales, which the Company expects to close throughout the 2014 fiscal year.
Operations
During the quarter ended December 31, 2013, the Company commenced or participated in the drilling of a total of 23 gross wells, of which 10 were operated by the Company. The Company had a 100% success rate on the 24 wells in which it had a working interest that were completed in the fourth quarter of 2013.
The table below summarizes the Company's gross drilling activities by area for the fourth quarter of 2013:
Fourth Quarter 2013
------------------------------------------------------------------
Total Drilled Wells Operated Wells Completed Wells Awaiting Frac
-------------------- --------------- --------------- -------------
Marcellus
Shale 7 7 8 8
Utica
Shale 1 1 0 1
Williston
Basin 15 2 16 3
-------------------- --------------- --------------- -------------
Total 23 10 24 12
-------------------- --------------- --------------- -------------
Currently, the Company is running six drilling rigs (two operated and four non-operated rigs). Of these six rigs, three rigs (two operated and one non-operated) are drilling wells in the Marcellus and Utica Shales in West Virginia and Ohio, and three non-operated rigs are drilling wells in the Williston Basin/Bakken Shale in North Dakota.
Marcellus and Utica Shale
During the fourth quarter of 2013, the Company completed the drilling of 7 gross (7 net) wells and completed 8 gross (6 net) wells in the Marcellus Shale and Utica Shale plays. These 8 gross (6 net) completed wells are currently flowing to sales via the Eureka Hunter Pipeline System. The Company's net production in the fourth quarter of 2013 attributable to Triad Hunter, LLC's operations was approximately 37.6 Mcfe/d, a 24% increase over such production during the fourth quarter of 2012.
The Company's first dry gas Utica Shale well, the Stalder #3UH located on the Stalder Pad (18 potential wells) in Monroe County, Ohio, was placed on production approximately two weeks ago and tested at a peak rate of 32.5 MMCF of natural gas per day on an adjustable rate choke with 4,300 psi FCP. The well continues to flow to sales points via the Eureka Hunter Pipeline System with the amount of frac water continuing to decrease since the commencement of initial sales.
The Company's first Marcellus Shale well drilled on the Stalder Pad, the Stalder #2MH, is awaiting the start of completion operations which the Company expects to commence in the next several weeks. The Stalder #2MH was drilled and cased to a true vertical depth of 6,070 feet with a 5,474 foot horizontal lateral. The Company expects the production from this well to be very liquids rich.
On the Farley Pad located in Washington County, Ohio, the Company has drilled and cased the Farley #1306H well in the Utica Shale to a true vertical depth of 7,850 feet with a 6,313 foot horizontal lateral. The Company has commenced the drilling of another Utica Shale well on the Farley Pad, the Farley #1304H. The Company is currently drilling the vertical section of this well and anticipates reaching a true vertical depth of 7,885 feet, and completing the drilling of a 5,500 foot horizontal lateral, within the next 30 days. Following the drilling of the Farley #1304H, the Company will begin fracture stimulation of these two new Farley wells in mid-March 2014 and expects to report initial production test rates in early-summer 2014 following an approximate 30-day resting period. The Company is in the advanced stages of negotiating new take-away capacity with a third-party midstream company and expects to be ready to flow production of all three wells on the Farley Pad to sales following the resting period.
On the WVDNR Pad located in Wetzel County, West Virginia, the Company has drilled and is in the process of completing three 100% owned Marcellus Shale wells, the WVDRN #1207, #1208 and #1209. The wells were drilled and cased to an average vertical depth of 7,500 feet with a 4,000 foot average horizontal lateral. The Company has fracture stimulated 9 of the proposed 20 stages on each of the three wells. During the last several weeks, the Company has experienced substantial completion delays in this region primarily due to the effects of extreme cold weather conditions. The Company expects to complete fracture stimulating the three WVDNR wells over the next 7 to 10 days, and anticipates production from the wells to begin to flow to sales in mid-March 2014.
On the Stewart Winland Pad located in Tyler County, West Virginia, the Company has drilled and cased the pad's first Marcellus Shale well, the Stewart Winland #1301. The Stewart Winland #1301 was drilled to a true vertical depth of 6,144 feet with a 5,770 foot horizontal lateral. The Company has skid the drilling rig and commenced the drilling of another Marcellus Shale well, the Stewart Winland #1302, on this pad. One additional Marcellus Shale well and one Utica Shale well will be subsequently drilled on this pad. The Company expects to report initial production test rates from the four wells on the Stewart Winland Pad during mid-summer 2014. As previously reported, the Company is in the process of making several production equipment changes at both its Collins and Spencer Pads in Tyler County, West Virginia to better handle the anticipated new liquids production. The Company is on target for these production equipment changes to be completed within the next 30 to 45 days. As a result, the Company does not expect to encounter any liquids infrastructure issues associated with the initial production from the four wells on the Stewart Winland Pad.
Williston Basin
During the fourth quarter of 2013, the Company drilled a total of 15 gross (6.2 net) wells in the Bakken/Three Forks Sanish formations in North Dakota. In the Company operated areas, the Company drilled 2 gross (2.0 net) wells, and in the Company non-operated areas, 13 gross (4.2 net) wells were drilled. During the fourth quarter, (i) six two-mile lateral wells were completed in the Middle Bakken formation, with an average IP 24-hour rate of 561 Boe/d and an average IP 30-day rate of 389 Boe/d, (ii) seven two-mile lateral wells were completed in the Three Forks Sanish formation with an average IP 24-hour rate of 584 Boe/d and an average IP 30-day rate of 287 Boe/d and (iii) three one-mile lateral wells were completed, one in the Three Forks Sanish formation, with an IP 24-hour rate of 760 Boe/d and an IP 30-day rate of 282 Boe/d, and two in the Middle Bakken formation, one with an IP 24-hour rate of 680 Boe/d and an IP 30-day rate of 253 Boe/d and the other for which the Company is still awaiting more complete initial production results. At the end of the fourth quarter of 2013, 12 gross (4.3 net) Company wells were drilling or waiting on fracture stimulation in North Dakota.
Eureka Hunter
As of February 16, 2014, Eureka Hunter Pipeline, LLC, ("Eureka Hunter"), was gathering approximately 171,634 MMBtu/d. The Eureka Hunter Pipeline System's gathering flow through recently hit a peak rate of 198,000 MMBtu/d. Eureka Hunter has connected a significant amount of new Marcellus production volumes from several Triad Hunter, LLC and third-party wells into the Eureka Hunter Pipeline System located in Tyler and Wetzel Counties, West Virginia.
Eureka Hunter is in the process of installing liquids stabilization equipment and loading facilities near its Ohio River crossing near Sardis, Ohio, which are expected to be in full operation during the first quarter of 2014. To further assist with volume demands and to reduce line pressure for producers, Eureka Hunter is also adding new mainline compression at its Carbide facility in Tyler County, West Virginia.
The new Marcellus Shale volumes flowing into Eureka Hunter's gathering system are coupled with the addition of dry Utica Shale production in Ohio from various third-party producers and Triad Hunter, LLC. Eureka Hunter expects to connect significant volumes of new Utica Shale production throughout 2014.
The build out of Eureka Hunter's gathering system in Ohio continues despite weather delays. The first lateral to be completed in Ohio was a 20-inch extension from the Ohio River past Triad Hunter, LLC's Stalder Pad extending approximately 11 miles to the west to gather gas from Eclipse Resources' Tippens pad site. This line is initially gathering dry Utica Shale gas production and was put into service in December 2013. The second Ohio line, the "Ormet lateral", is also a 20-inch line, and is approximately 95% complete at this time. The Company expects to complete the Ormet lateral in April 2014 barring any further weather delays. The necessary liquids handling equipment should also be installed in March 2014 with production anticipated in April 2014.
Other Eureka Hunter pipeline construction projects slated for 2014 include a northerly extension to interconnect with Rocky Mountain Express, Texas Eastern Transmission and possibly Dominion Transmission, all near Clarington, Ohio. Eureka also plans to connect to rich gas production for delivery to the Blue Racer Natrium plant in Marshall County, West Virginia and to a residue gas line extension from the MarkWest Mobley processing facilities tailgate to Columbia Gas. The Company's goal is to have as many production take-away outlets from this region as possible.
Management Comments
Mr. Gary C. Evans, Chairman of the Board and Chief Executive Officer of Magnum Hunter, commented, "Calendar year 2013 was a pivotal year for Magnum Hunter. We made the decision to sell our Eagle Ford assets, producing approximately 3,000 barrels of oil equivalent per day, for a contracted price of $401 million and redeploy those proceeds to our two remaining core areas, Appalachia and the Williston Basin. Revenues were still up over 72% and EBITDAX increased 48%. We drilled 21 gross wells (12.5 net) in the Marcellus and Utica resource plays and drilled 72 gross (24.6 net) in the Bakken and Three Forks Sanish plays of the Williston Basin. All 93 gross wells were deemed commercially successful. We also completed 23 miles of new pipeline in our midstream division, Eureka Hunter, where throughput increased 390%. Our lease acreage position has grown to 957,953 gross acres and 642,643 net acres, most of which is held by existing production which give us a tremendous amount of future inventory. In 2014, we will continue our divestiture efforts with respect to non-core assets which could bring in approximately $400 million of proceeds, an amount much greater than our current capital expenditure funding gap. The high grading of our portfolio is being reflected in our proved reserve additions, higher EUR's per well and higher production rates on new drills. Management's goal will be to continue improving our internal rates of return on every single dollar deployed and drill predominately in the core areas of the shale plays where we operate."
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, (2) impairment of proved 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, amortization and accretion, (4) impairment of proved oil and gas properties, (5) exploration, (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 and North Dakota. The Company is presently active in three of the most prolific unconventional shale resource plays in North America, namely the Marcellus Shale, Utica Shale and Williston Basin/Bakken Shale.
Availability of Information on the Company's Website
Magnum Hunter is providing a reminder that it makes available on its website (atwww.magnumhunterresources.com) a variety of information for investors, analysts and the media, including the following:
- annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and any amendments to those reports as soon as reasonably practicable after the material is electronically filed with or furnished to the Securities and Exchange Commission;
- the most recent version of the Company's Investor Presentation slide deck;
- announcements of conference calls, webcasts, investor conferences, speeches and other events at which Company executives may discuss the Company and its business and archives or transcripts of such events;
- press releases regarding annual and quarterly earnings, operational developments, legal developments and other matters; and
- corporate governance information, including the Company's corporate governance guidelines, committee charters, code of conduct and other governance-related matters.
Certain information included on the Company's website constitutes forward-looking statements and is subject to the qualifications under the heading "Forward-Looking Statements" below and in the Company's Investor Presentation slide deck.
Forward-Looking Statements
This press release includes "forward-looking statements." All statements other than statements of historical facts included or incorporated herein may constitute forward-looking statements. Actual results could vary significantly from those expressed or implied in such statements and are subject to a number of risks and uncertainties. Although Magnum Hunter believes that the expectations reflected in the forward-looking statements are reasonable, Magnum Hunter can give no assurance that such expectations will prove to be correct. The forward-looking statements involve risks and uncertainties that affect operations, financial performance, and other factors as discussed in filings made by Magnum Hunter with the Securities and Exchange Commission (SEC). Among the factors that could cause results to differ materially are those risks discussed in the periodic reports filed by Magnum Hunter with the SEC, including Magnum Hunter's Annual Report on Form 10-K for the fiscal year ended December 31, 2012, and its to-be-filed Annual Report on Form 10-K for the fiscal year ended December 31, 2013, and its Quarterly Reports on Form 10-Q for the fiscal quarters ended after such fiscal year. You are urged to carefully review and consider the cautionary statements and other disclosures made in those filings, specifically those under the heading "Risk Factors." Forward-looking statements speak only as of the date of the document in which they are contained, and Magnum Hunter does not undertake any duty to update any forward-looking statements except as may be required by law.
MAGNUM HUNTER RESOURCES CORPORATION UNAUDITED RESULTS OF OPERATIONS
(Continuing Operations)
Years Ended December 31,
-----------------------------
2013 2012 2011
--------- --------- ---------
(in thousands except per
unit)
Oil and gas revenue and production
Revenues
Oil $ 140,426 $ 77,172 $ 37,520
Gas 41,867 36,657 21,206
NGL 15,306 830 -
--------- --------- ---------
Total oil and gas sales $ 197,599 $ 114,659 $ 58,726
========= ========= =========
Production
Oil (MBbl) 1,564 939 430
Gas (MMcf) 10,352 11,212 4,574
NGL(MBoe) 304 25 -
Total MBoe 3,593 2,833 1,192
Boe/d 9,844 7,740 3,266
Average prices (U.S. Dollars)
Oil (per Bbl) $ 89.79 $ 82.19 $ 87.26
Gas (per Mcf) $ 4.04 $ 3.27 $ 4.64
NGL (per Boe) $ 50.35 $ 33.20 $ -
Total average price (per Boe) $ 55.00 $ 40.47 $ 49.27
Costs and expenses (per Boe)
Lease operating $ 15.02 $ 9.47 $ 12.58
Severance tax and marketing $ 4.93 $ 2.77 $ 4.48
Exploration $ 27.09 $ 27.61 $ 2.19
Impairment of properties $ 2.77 $ 1.33 $ -
Depletion, depreciation, amortization and
accretion $ 27.61 $ 21.08 $ 19.50
General and administrative (1) $ 20.99 $ 18.87 $ 45.60
Other segments (in thousands)
Midstream and marketing operations segment
revenue $ 69,306 $ 15,692 $ 1,990
Midstream and marketing operations segment
expense $ 72,823 $ 17,419 $ 2,512
Oilfield services segment revenue $ 21,527 $ 13,552 $ 9,426
Oilfield services segment expense $ 21,610 $ 12,405 $ 9,320
MAGNUM HUNTER RESOURCES CORPORATION
UNAUDITED CONSOLIDATED BALANCE SHEETS
(In thousands, except share and per share data)
December 31,
----------------------
2013 2012
---------- ----------
ASSETS
CURRENT ASSETS
Cash and cash equivalents $ 41,713 $ 57,623
Restricted cash 5,000 1,500
Accounts receivable, net of allowance for doubtful
accounts of $292 and $448 as of December 31, 2013
and 2012, respectively 55,681 124,861
Derivative assets 608 5,146
Inventory 7,158 9,162
Investments 2,262 3,278
Prepaid expenses and other assets 2,938 2,249
Assets held for sale 5,366 500
---------- ----------
Total current assets 120,726 204,319
---------- ----------
PROPERTY, PLANT AND EQUIPMENT
Oil and natural gas properties, successful efforts
method of accounting 1,355,288 1,908,659
Accumulated depletion, depreciation, and accretion (130,629) (186,156)
---------- ----------
Total oil and natural gas properties, net 1,224,659 1,722,503
Gas transportation, gathering and processing
equipment and other, net 289,420 201,910
---------- ----------
Total property, plant and equipment, net 1,514,079 1,924,413
---------- ----------
OTHER ASSETS
Deferred financing costs, net of amortization of
$12,842 and $8,024 as of December 31, 2013 and
2012, respectively 20,008 23,862
Derivatives assets 25 -
Intangible assets, net 6,530 8,981
Goodwill 30,602 30,602
Other assets 1,994 6,455
Assets held for sale 162,687 -
---------- ----------
Total assets $1,856,651 $2,198,632
========== ==========
MAGNUM HUNTER RESOURCES CORPORATION
UNAUDITED CONSOLIDATED BALANCE SHEETS
(In thousands, except share and per share data)
December 31,
2013 2012
---------- ----------
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES
Current portion of notes payable $ 3,804 $ 3,991
Accounts payable 107,860 196,515
Accrued liabilities 44,629 11,212
Revenue payable 6,313 20,394
Derivatives liabilities 1,903 3,501
Other liabilities 6,491 8,043
Liabilities associated with assets held for sale 12,865 -
---------- ----------
Total current liabilities 183,865 243,656
Long-term debt 876,106 886,769
Asset retirement obligation 16,163 28,322
Deferred tax liability - 74,258
Derivative liabilities 76,310 47,524
Other long-term liabilities 2,279 5,573
Liabilities associated with assets held for sale 14,523 -
---------- ----------
Total liabilities 1,169,246 1,286,102
---------- ----------
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 December
31, 2013 and 2012, 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, 9,885,048 and 7,672,892
issued and outstanding as of December 31, 2013
and 2012, respectively, with liquidation
preference of $200,620 and $167,403 as of
December 31, 2013 and 2012, respectively 136,675 100,878
---------- ----------
236,675 200,878
SHAREHOLDERS' EQUITY
Preferred Stock of Magnum Hunter Resources
Corporation, 10,000,000 authorized, including
authorized shares of Series C Preferred Stock
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 December
31, 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 3,755 issued and 3,722
and 3,705 shares outstanding as of December 31,
2013 and 2012, respectively, with liquidation
preference of $25,000 per share 95,069 94,371
Common stock, $0.01 par value; 350,000,000 and
250,000,000 authorized, 172,409,000 and
170,032,999 issued and 171,494,071 and
169,118,047 outstanding as of December 31, 2013
and 2012, respectively 1,724 1,700
Exchangeable common stock, par value $0.01 per
share, none and 505,835 shares issued and
outstanding as of December 31, 2013 and 2012,
respectively - 5
Additional paid in capital 733,753 715,033
Accumulated deficit (586,365) (307,484)
Accumulated other comprehensive loss (19,901) (8,889)
Treasury Stock, at cost
Series E Cumulative Preferred Stock, 81 shares
and 70 as of December 31, 2013 and 2012,
respectively (2,030) (1,750)
Common stock, 914,952 shares as of December 31,
2013 and 2012, respectively (1,914) (1,914)
---------- ----------
Total Magnum Hunter Resources Corporation
shareholders' equity 441,580 701,513
Non-controlling interest 9,150 10,139
---------- ----------
Total shareholders' equity 450,730 711,652
---------- ----------
Total liabilities and shareholders' equity $1,856,651 $2,198,632
========== ==========
MAGNUM HUNTER RESOURCES CORPORATION
UNAUDITED CONSOLIDATED STATEMENT OF OPERATIONS
(In thousands, except share and per share data)
Year Ended December 31,
2013 2012 2011
------------ ------------ ------------
REVENUES AND OTHER
Oil and natural gas sales $ 197,599 $ 114,659 $ 58,726
Natural gas transportation,
gathering, processing, and
marketing 60,632 13,040 494
Oilfield services 18,431 12,333 7,149
Other revenue 3,749 324 86
------------ ------------ ------------
Total revenue 280,411 140,356 66,455
------------ ------------ ------------
OPERATING EXPENSES
Lease operating expenses 53,961 26,839 14,998
Severance taxes and marketing 17,721 7,854 5,341
Exploration 97,342 78,221 2,605
Natural gas transportation,
gathering, processing, and
marketing 52,099 8,028 373
Oilfield services 14,825 10,037 6,759
Impairment of proved oil and gas
properties 9,968 3,772 -
Depreciation, depletion,
amortization and accretion 99,198 59,730 23,246
Loss on sale of assets, net 44,654 628 361
General and administrative 75,407 53,454 54,360
------------ ------------ ------------
Total operating expenses 465,175 248,563 108,043
------------ ------------ ------------
OPERATING LOSS (184,764) (108,207) (41,588)
OTHER INCOME (EXPENSE)
Interest income 220 199 10
Interest expense (72,423) (51,616) (11,752)
Gain (loss) on derivative
contracts, net (25,274) 22,239 (6,346)
Other income (expense) 7,892 (1,583) -
------------ ------------ ------------
Total other expense, net (89,585) (30,761) (18,088)
------------ ------------ ------------
LOSS FROM CONTINUING OPERATIONS
BEFORE INCOME TAX (274,349) (138,968) (59,676)
------------ ------------ ------------
Income tax benefit (expense) 70,297 19,312 2,862
------------ ------------ ------------
LOSS FROM CONTINUING OPERATIONS (204,052) (119,656) (56,814)
Loss from discontinued
operations, net of tax (71,131) (19,474) (19,598)
Gain on disposal of discontinued
operations, net of tax 52,019 2,409 -
------------ ------------ ------------
NET LOSS (223,164) (136,721) (76,412)
Net loss (income) attributable
to non-controlling interest 988 4,013 (249)
------------ ------------ ------------
NET LOSS ATTRIBUTABLE TO MAGNUM
HUNTER RESOURCES CORPORATION (222,176) (132,708) (76,661)
Dividends on preferred stock (56,705) (34,706) (14,007)
------------ ------------ ------------
NET LOSS ATTRIBUTABLE TO COMMON
SHAREHOLDERS $ (278,881) $ (167,414) $ (90,668)
============ ============ ============
Weighted average number of
common shares outstanding,
basic and diluted 170,088,108 155,743,418 113,154,270
============ ============ ============
Loss from continuing operations
per share, basic and diluted $ (1.53) $ (0.96) $ (0.63)
Income (loss) from discontinued
operations per share, basic and
diluted (0.11) (0.11) (0.17)
------------ ------------ ------------
NET LOSS PER COMMON SHARE, BASIC
AND DILUTED $ (1.64) $ (1.07) $ (0.80)
============ ============ ============
AMOUNTS ATTRIBUTABLE TO MAGNUM
HUNTER RESOURCES
Loss from continuing operations,
net of tax $ (203,064) $ (115,643) $ (57,063)
Income (loss) from discontinued
operations, net of tax (19,112) (17,065) (19,598)
------------ ------------ ------------
Net loss attributable to Magnum
Hunter Resources $ (222,176) $ (132,708) $ (76,661)
============ ============ ============
MAGNUM HUNTER RESOURCES CORPORATION
UNAUDITED CONSOLIDATED STATEMENT OF CASH FLOWS
(In thousands, except share and per share data)
Year Ended December 31,
2013 2012 2011
----------- ----------- -----------
CASH FLOWS FROM OPERATING ACTIVITIES
Net loss $ (223,164) $ (136,721) $ (76,412)
Adjustments to reconcile net loss
to net cash provided by (used in)
operating activities:
Depletion, depreciation,
amortization and accretion 134,867 135,896 49,090
Share-based compensation 13,624 15,696 25,057
Impairment of oil and gas
properties 89,041 4,096 21,782
Exploration 115,069 116,686 1,118
Gain on sale of assets (7,318) (3,074) (186)
Cash paid for plugging wells (14) - -
Loss (gain) on open derivative
contracts 17,058 (10,945) 4,210
Loss (gain) on investments (7,009) 2,200 -
Amortization and write off of
deferred financing cost and
discount on Senior Notes
included in interest expense 4,836 7,399 3,636
Deferred tax benefit (84,527) (21,595) (696)
Changes in operating assets and
liabilities:
Accounts receivable, net 22,781 (73,549) (25,075)
Inventory 4,658 (6,198) (3,889)
Prepaid expenses and other
current assets (1,073) (538) (124)
Accounts payable 42,050 16,390 25,883
Revenue payable (11,589) 8,776 6,979
Accrued liabilities 2,421 3,492 2,465
----------- ----------- -----------
Net cash provided by operating
activities 111,711 58,011 33,838
----------- ----------- -----------
CASH FLOWS FROM INVESTING ACTIVITIES
Change in restricted cash (3,500) - -
Capital expenditures and advances (631,511) (568,610) (291,942)
Cash paid in acquisitions, net of
cash received of $0; $34; and
$2,500, respectively - (444,844) (78,524)
Proceeds from sale of assets 506,297 4,158 8,709
Change in deposits and other long-
term assets 854 89 42
----------- ----------- -----------
Net cash used in investing
activities (127,860) (1,009,207) (361,715)
----------- ----------- -----------
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from issuing Senior Notes - 596,907 -
Proceeds from borrowings on debt 373,991 546,043 493,906
Principal repayments of debt (380,923) (542,654) (242,472)
Proceeds from sale of Series A
preferred units in Eureka Hunter
Holdings 35,280 149,655 -
Net proceeds from sale of common
stock - 148,241 13,892
Net proceeds from sale of preferred
shares 10,072 144,635 94,764
Proceeds from exercise of warrants
and options 5,352 2,331 7,618
Change in other long-term
liabilities (1,222) 186 69
Purchase of treasury shares - (1,750) -
Payment of deferred financing costs (1,246) (20,313) (11,577)
Preferred stock dividends paid (40,648) (26,839) (14,007)
----------- ----------- -----------
Net cash provided by financing
activities 656 996,442 342,193
----------- ----------- -----------
Effect of foreign exchange rate
changes on cash (417) (2,474) (19)
----------- ----------- -----------
NET INCREASE (DECREASE) IN CASH AND
CASH EQUIVALENTS (15,910) 42,772 14,297
CASH AND CASH EQUIVALENTS, BEGINNING
OF YEAR 57,623 14,851 554
----------- ----------- -----------
CASH AND CASH EQUIVALENTS, END OF
YEAR $ 41,713 $ 57,623 $ 14,851
=========== =========== ===========
Magnum Hunter Resources Reconciliations (Unaudited)
Adjusted Loss per
Common Share
Reconciliation Three Months Ended Twelve Months Ended
December 31, December 31,
-------------------------- --------------------------
($ in thousands) 2013 2012 2013 2012
------------ ------------ ------------ ------------
Net income (loss)
attributable to
common shareholders
- reported $ (61,208) $ (87,235) $ (278,881) $ (167,414)
Non-recurring and
non-cash items:
Exploration expense $ 23,940 $ 60,078 $ 97,342 $ 78,221
Impairment of
proved oil and gas
properties $ - $ 3,772 $ 9,968 $ 3,772
Non-cash: stock
compensation
expense $ 1,790 $ 938 $ 13,624 $ 15,696
Non-cash: 401k
matching expense $ 298 $ 531 $ 1,856 $ 1,403
Non-recurring
transaction and
other expense $ 8,487 $ 7,396 $ 29,807 $ 15,085
Unrealized (gain)
loss on
investments $ (229) $ (301) $ 814 $ -
Interest expense -
fees $ 1,175 $ (3,326) $ 4,836 $ 7,399
Unrealized (gain)
loss on
derivatives $ (6,699) $ (9,851) $ 17,058 $ (10,945)
(Gain) loss on sale
of assets $ 2,538 $ 100 $ 44,654 $ 628
Income tax
(benefit) $ (29,353) $ (10,169) $ (70,297) $ (19,312)
(Gain) loss from
sale of
discontinued
operations $ 35,979 $ 4,633 $ (52,019) $ 2,409
Income from
discontinued
operations $ (324) $ (16,642) $ 71,131 $ (19,474)
------------ ------------ ------------ ------------
Total non-recurring
and non-cash items $ 37,602 $ 37,159 $ 168,774 $ 74,882
Net income (loss)
attributable to
common shareholders
- as adjusted $ (23,606) $ (50,076) $ (110,107) $ (92,532)
Net income (loss)
attributable to
common shareholders
- as adjusted $ (0.14) $ (0.30) $ (0.65) $ (0.59)
Weighted Average
Shares 171,085,346 169,197,301 170,088,108 155,743,418
Adjusted EBITDAX Reconciliation
Three Months Ended Twelve Months Ended
December 31, December 31,
-------------------- --------------------
($ in thousands) 2013 2012 2013 2012
--------- --------- --------- ---------
Net income (loss) from
continuing operations $ (10,257) $ (57,173) $(204,052) $(119,656)
Net Interest expense $ 19,220 $ 11,237 $ 72,423 $ 51,616
(Gain) loss on sale of assets $ 2,538 $ 100 $ 44,654 $ 628
Depletion, depreciation,
amortization and accretion $ 27,242 $ 17,531 $ 99,198 $ 59,730
Impairment of proved oil and gas
properties $ - $ 3,772 $ 9,968 $ 3,772
Exploration expense $ 23,940 $ 60,078 $ 97,342 $ 78,221
Non-cash stock compensation
expense $ 1,790 $ 938 $ 13,624 $ 15,696
Non-cash 401k matching expense $ 298 $ 531 $ 1,856 $ 1,403
Non-recurring transaction and
other expense $ 8,487 $ 7,396 $ 29,807 $ 15,085
Unrealized (gain) loss on
investments $ (229) $ (301) $ 814 $ -
Income tax (benefit) $ (29,353) $ (10,169) $ (70,297) $ (19,312)
Unrealized (gain) loss on
derivatives $ (6,699) $ (9,851) $ 17,058 $ (10,945)
--------- --------- --------- ---------
Total Adjusted EBITDAX $ 36,977 $ 24,089 $ 112,395 $ 76,238
Recurring Cash G&A
Reconciliation
Three Months Ended Twelve Months Ended
December 31, December 31,
--------------------- ---------------------
($ in thousands) 2013 2012 2013 2012
---------- ---------- ---------- ----------
Total G&A $ 16,849 $ 15,228 $ 75,407 $ 53,454
Adjustments:
Non-cash stock compensation $ 1,790 $ 938 $ 13,624 $ 15,696
Acquisition and other non-
recurring expense $ 8,487 $ 7,396 $ 29,807 $ 15,085
---------- ---------- ---------- ----------
Recurring Cash G&A $ 6,571 $ 6,894 $ 31,975 $ 22,673
Recurring Cash G&A Per BOE $ 6.32 $ 9.54 $ 8.91 $ 8.00
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