Item 1.
BUSINESS
Unless stated otherwise or unless the context otherwise requires, all references in this report to Magnum Hunter, the Company, we, our, ours and us are to Magnum Hunter Resources Corporation, a Delaware corporation, and its consolidated subsidiaries. We have provided definitions for some of the oil and natural gas industry terms used in this annual report under “Glossary of Oil and Natural Gas Terms” at the end of this “Business” section of this annual report.
Our Company
We are an independent oil and natural gas company engaged in the exploration for and the exploitation, acquisition, development and production of crude oil, natural gas and natural gas liquids resources in the United States. We are active in what we believe to be three of the most prolific unconventional shale resource plays in the United States, specifically, the Marcellus Shale in West Virginia and Ohio; the Utica Shale in southeastern Ohio and western West Virginia; and the Williston Basin/Bakken Shale in North Dakota. Our core oil and natural gas reserves and operations are primarily concentrated in West Virginia, Ohio and North Dakota. We are also engaged in midstream and oil field services operations, primarily in West Virginia and Ohio.
Since our current management team assumed leadership of our Company in May 2009 and refocused our business strategy, we have substantially increased our assets and production base through a combination of acquisitions, joint ventures and ongoing development drilling efforts on acquired acreage. We believe the increased scale in our core resource plays allows for ongoing cost recovery and production efficiencies as we exploit and monetize our asset base.
Our business strategy is to create significant value for our stockholders by growing reserves, production volumes and cash flow at an attractive rate of return through a combination of efficient development of our properties and strategic acquisitions and joint ventures, and to selectively monetize properties at opportune times and attractive prices. As part of our strategy:
•
We have approved a $400 million capital expenditure budget for fiscal year 2014, excluding acquisitions. We have allocated approximately $260 million in the Utica Shale and Marcellus Shale plays, approximately $50 million in the Williston Basin and approximately $90 million (net to our majority interest) for midstream operations. We expect this Appalachian-focused capital program to further drive our future production volumes and reserve additions and enable us to achieve our 2014 projected exit production rate of 35,000 Boe/d;
•
We have recently completed in excess of $500 million in divestitures, including sales of our Eagle Ford Shale properties in south Texas and certain non-core North Dakota properties (see “-Our Significant Recent Developments”);
•
We are actively marketing our southern Appalachian Basin properties located in Kentucky and Tennessee and our Canadian properties located in Saskatchewan and Alberta pursuant to a plan to divest those assets adopted in September 2013 (see “Management's Discussion and Analysis of Financial Condition and Results of Operations-Business Overview”); and
•
We have identified a number of other non-core U.S. upstream properties for possible divestiture in 2014 that we believe represent (together with the planned southern Appalachian Basin and Canada divestitures described above) in excess of $400 million in value.
As a result of our recent and planned divestitures, we are now strategically focused on our Marcellus Shale and Utica Shale plays in the Appalachian Basin in West Virginia and Ohio and our Bakken Shale play in the Williston Basin in North Dakota.
Appalachian Basin / Marcellus Shale and Utica Shale / West Virginia and Ohio
Appalachian Basin. Our Appalachian Basin drilling operations are focused on development in the liquids rich Marcellus Shale and Utica Shale underlying West Virginia and Ohio. We initially entered the Appalachian Basin through an asset acquisition in February 2010 and have subsequently expanded our operations through various acquisitions and joint ventures and development drilling efforts.
Marcellus Shale. As of January 31, 2014, we had a total of approximately 78,709 net leasehold acres in the Marcellus Shale. Our Marcellus Shale acreage is located principally in Tyler, Pleasants, Ritchie, Wetzel and Lewis Counties, West Virginia and in Washington and Monroe Counties, Ohio. As of January 31, 2014, we had (a) 35 horizontal wells (27.5 net) producing in the Marcellus Shale (including non-operated wells) and (b) 14 horizontal wells (7.9 net) awaiting completion, one horizontal well (one net) drilling, and one drilling rig operating on our Company-operated Marcellus Shale properties. As of January 31, 2014, approximately 76% of our mineral leases in the Marcellus Shale area were held by production. As of January 31, 2014, our five most recently completed Company-operated horizontal wells targeting the Marcellus Shale generated approximately 12,158 Mcfe/d and 7,005 Mcfe/d average IP-24 hour and IP-30 day rates, respectively.
Utica Shale. As of January 31, 2014, we had a total of approximately 99,078 net leasehold acres prospective for the Utica Shale. Approximately 63,877 of the net acres are located in Ohio (a portion of which acreage overlaps our Marcellus Shale acreage), and approximately 35,201 of the net acres are located in West Virginia (a portion of which acreage overlaps our Marcellus Shale acreage). Our Utica Shale acreage is located principally in Tyler, Pleasants and Wood Counties, West Virginia and in Washington, Monroe,
Morgan and Noble Counties, Ohio. We believe approximately 36,500 of our Utica Shale net acres are located in the wet gas window of the play. As of January 31, 2014, we had two horizontal wells (1.5 net) awaiting completion, one horizontal well (one net) drilling, and one drilling rig operating on our Company-operated Utica Shale properties. Approximately 65% of our acreage in the Utica Shale is held by shallow production. Our first dry gas Utica Shale well located on the Stalder Pad in Monroe County, Ohio, was placed on production on February 9, 2014 and tested at a peak rate of 32.5 MMcf of natural gas per day. The Stalder #3UH well was drilled and cased to a true vertical depth of 10,653 feet with a 5,050 foot horizontal lateral and successfully fraced with 20 stages.
Our 2014 capital expenditure budget includes approximately $260 million of capital expenditures in the Appalachian Basin, essentially all in the Marcellus Shale and Utica Shale regions. We intend to drill a total of approximately 25 gross horizontal wells in the Marcellus Shale and Utica Shale in 2014.
Williston Basin / Bakken Shale / North Dakota
We established our initial presence in the Bakken/Three Forks Sanish formations in North Dakota with an acquisition in May 2011 and have expanded our presence in the Bakken Shale through subsequent acquisitions. We recently sold certain non-core properties in North Dakota. See “-Our Significant Recent Developments-Sale of Non-Core North Dakota Assets.”
As of January 31, 2014, our Williston Basin properties in the United States, or Williston Basin U.S., included approximately 102,869 net acres in the Bakken/Three Forks Sanish formations in North Dakota. Our Williston Basin U.S. acreage is located in Divide County, North Dakota. As of January 31, 2014, we had 255 wells (61 net) producing, 4 wells (1.4 net) awaiting completion, 5 wells (1.4 net) drilling, and 2 drilling rigs operating on our Bakken/Three Forks Sanish properties in North Dakota. As of January 31, 2014, our five most recently completed Company-operated one-mile horizontal wells in Divide County, North Dakota generated an average IP-24 hour rate of approximately 475 Boe/d, and our five most recently completed third-party operated two-mile horizontal wells in Divide County, North Dakota generated an average IP-24 hour rate of approximately 408 Boe/d.
Our 2014 capital expenditure budget includes approximately $50 million of capital expenditures in the Williston Basin/Bakken Shale in North Dakota. We expect these capital expenditures to relate primarily to the drilling of wells in which we participate as a non-operated working interest owner. We anticipate these wells will include approximately 20 gross wells located primarily in the Ambrose Field in Divide County, North Dakota.
Midstream Operations
Our midstream operations are conducted through our majority-owned subsidiary, Eureka Hunter Holdings, LLC, or Eureka Hunter Holdings. Eureka Hunter Pipeline, LLC, or Eureka Hunter Pipeline, a subsidiary of Eureka Hunter Holdings, owns and operates a gas gathering system in West Virginia and Ohio, referred to as our Eureka Hunter Gas Gathering System. We are also engaged in the business of leasing natural gas treating plants to third-party producers in Texas and other states through a separate subsidiary, TransTex Hunter, LLC. We have obtained financing for our midstream operations through an equity purchase commitment from an unaffiliated third party, which also gives us the right to make capital contributions in conjunction with or alongside the capital contributions from the third party, and two separate credit facilities on a non-recourse basis to Magnum Hunter Resources Corporation.
Our midstream pipeline is a strategic asset to the development and delineation of our acreage position in the both the Utica Shale and Marcellus Shale plays. We believe that we have a competitive advantage by being vertically integrated and maintaining control of our natural gas gathering activities. From time to time, we have discussions with strategic companies in our core area of operations and may pursue joint ventures or other strategic transactions with respect to this asset.
We are continuing the commercial development of the Eureka Hunter Gas Gathering System to support the development of our existing and anticipated future Marcellus Shale and Utica Shale acreage positions, as well as the expanding gas gathering needs of third party producers in these regions. The system is being constructed primarily out of 20-inch and 16-inch high-pressure steel pipe with an estimated 350 MMcf/d of initial throughput capacity. As of January 31, 2014, we had completed the construction of a total of over 100 miles of pipeline as part of the system. See “-Our Significant Recent Developments-Expansion of Eureka Hunter Gas Gathering System.”
As of February 16, 2014, we were flowing approximately 171,000 MMbtus of natural gas per day through the Eureka Hunter Gas Gathering System. We gathered 3.2 Bcf of natural gas during January 2014 with a peak day of approximately 170,000 MMBtu of natural gas delivered to a processing plant located near the town of Mobley in Wetzel County, West Virginia, or the Mobley Processing Plant, owned by MarkWest Liberty Midstream & Resources, L.L.C., or MarkWest, on January 5, 2014. During the first six months of 2014, we expect to gather significant additional natural gas volumes from us and third party producers with production connected to the gathering system. We expect that the Eureka Hunter Gas Gathering System will enable us to continue to develop our substantial natural gas and natural gas liquids resources in the Marcellus Shale and Utica Shale, as well as provide the opportunity for substantial cash flow from the gathering of third party volumes of natural gas.
Our 2014 capital expenditure budget includes approximately $90 million (net to our majority interest) of capital expenditures relating to the Eureka Hunter Gas Gathering System.
Oil Field Services Operations
Our oil field services operations consist of the ownership and operation of six drilling rigs that are used primarily for vertical section (top-hole) air drilling in the Appalachian Basin for us and third parties. Our fleet of rigs includes a robotic walking drilling rig that can also drill the horizontal sections of wells in the shale plays where we are active. This drilling rig was designed especially for pad drilling with its unique footprint and capability to walk and rotate without being dismantled.
Summary of Proved Reserves, Production and Acreage
The oil and natural gas reserves and production information provided below includes reserves and production associated with our southern Appalachian Basin and Canadian properties that we intend to divest, which we have presented as assets held for sale in our December 31, 2013 consolidated balance sheet, as well as reserves and production associated with our Eagle Ford Shale and Pearsall Shale assets that were sold in January 2014.
•
As of December 31, 2013, we had approximately 75.9 MMBoe of estimated proved reserves, of which approximately 45.8% was oil and natural gas liquids and approximately 52.2% was classified as proved developed producing reserves. By comparison, as of December 31, 2012, our estimated proved reserves were approximately 73.1 MMBoe, of which approximately 62.9% was oil and natural gas liquids and approximately 52.0% was classified as proved developed producing reserves. Our estimated proved reserves, on a Boe basis, at year-end 2013 increased 3.9% from year-end 2012.
•
As of December 31, 2013, we had proved reserves with a PV-10 value of $922.1 million. This compares with proved reserves with a PV-10 value of $981.2 million as of December 31, 2012. The PV-10 value of our estimated proved reserves at year-end 2013 decreased 6% from year-end 2012. PV-10 values are different from the standardized measure of proved reserves due to the inclusion in the standardized measure of estimated future income taxes. The standardized measure of our proved reserves at December 31, 2013 was $844.5 million.
•
Our daily production volumes at December 31, 2013 were approximately 12,210 Boe/d. Our average daily production volumes for the year ended December 31, 2013, were approximately 9,844 Boe/d, which represented a 27.2% increase from the year ended December 31, 2012. Our average daily production volumes for the quarter ended December 31, 2013 were approximately 11,298 Boe/d.
•
Our daily production volumes at February 20, 2014 were approximately 16,142 Boe/d.
•
As of January 31, 2014, we had approximately 280,657 net leasehold acres in our core operating areas, including approximately 78,709 net acres in the Marcellus Shale, approximately 99,078 net acres prospective for the Utica Shale (a portion of which acreage overlaps our Marcellus Shale acreage) and approximately 102,869 net acres in the Williston Basin/Bakken Shale in North Dakota.
Reserve Summary
(a)
MMBoe is defined as one million barrels of oil equivalent determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.
(b)
The prices used to calculate this measure were $96.78 per barrel of oil and $3.67 per MMBtu of natural gas. The prices represent the average prices per barrel of oil and per MMBtu of natural gas at the beginning of each month in the 12-month period prior to the end of the reporting period. These prices were adjusted to reflect applicable transportation and quality differentials on a well-by-well basis to arrive at realized sales prices used to estimate our reserves at this date.
(c)
The standardized measure of our proved reserves at December 31, 2013 was $844.5 million. See “-Non-GAAP Measures; Reconciliations” for a definition of pre-tax PV-10 and a reconciliation of our pre-tax PV-10 value to our standardized measure.
(d)
We sold certain Eagle Ford Shale and Pearsall Shale assets in January 2014 (the reserves attributable to which assets are reflected in the table above). See "-Our Significant Recent Developments-Sale of Remaining Eagle Ford Shale and Pearsall Shale Assets" below and "Note 19 - Subsequent Events" in the notes to our consolidated financial statements included in this report. We continue to own certain miscellaneous assets in Texas and Louisiana.
(e)
Pertains to our Alberta, Canada properties.
Our Business Strategy
Key elements of our business strategy include:
Focus on Core Unconventional Resource Plays
As a result of our recent and planned divestitures, we are now strategically focused on the development and expansion of our core areas of operation in the Marcellus Shale in West Virginia and Ohio, in the Utica Shale in southeastern Ohio and western West Virginia and, to a lesser extent, in the Williston Basin/Bakken Shale in North Dakota. As of January 31, 2014, we had a total of approximately 513,628 gross acres (280,657 net acres) in these core areas.
Focus on Development and Acquisition of Liquids Rich Marcellus and Dry Gas and Liquids Rich Utica Resources
We intend to focus our development and acquisition efforts primarily on high return projects, including liquids rich gas (greater than 1,250 Btu) in the Marcellus Shale in West Virginia and Ohio, the dry gas and liquids rich area of the Utica Shale in southeastern Ohio and western West Virginia and oil reserves in the Williston Basin/Bakken Shale in North Dakota. We have allocated a significant portion of our 2014 upstream capital expenditure budget to these high return projects in the Marcellus Shale and Utica Shale plays. We intend to pursue strategic “bolt-on” acquisitions, primarily leasehold acreage, in our core areas, on a very selective and value accretive basis, to enhance long-term asset values and realize economies of scale.
Selected Monetization of Assets
Our strategy is to explore and develop our properties and to selectively monetize our developed properties at opportune times and attractive prices. In the past five years, we significantly expanded our positions in the Marcellus Shale, Utica Shale, Williston Basin, Eagle Ford Shale and southern Appalachian Basin through acquisitions and joint ventures and have monetized some of these assets through divestitures. We sold: (1) our core Eagle Ford Shale properties in April 2013 for a contract purchase price of $401 million of cash and stock; (2) certain non-core properties in Burke County, North Dakota in September 2013 for a contract purchase price
of $32.5 million in cash; (3) certain non-core properties in various counties of North Dakota in December 2013 for a contract purchase price of $45 million in cash; and (4) substantially all of our remaining Eagle Ford Shale and Pearsall Shale properties in south Texas in January 2014 for a contract purchase price of $24.5 million in cash and stock. These transactions resulted in aggregate proceeds in excess of $500 million in cash and stock. We expect to continue to develop our remaining core assets in 2014, while also monetizing certain of our non-core assets and interests. We have identified a number of non-core properties, which we believe represent in excess of $400 million in aggregate value (including our southern Appalachian properties in Kentucky and Tennessee and our Canadian assets in Saskatchewan and Alberta), for possible divestiture in 2014.
Allocate Capital to Projects with High Rates of Return
We intend to allocate capital to areas and projects with high potential rates of return. We have allocated a significant portion of our 2014 capital budget to the Marcellus Shale and Utica Shale plays to accelerate the development of our properties in these regions, to take advantage of our processing capacity at the Mobley Processing Plant (and the uplift in the realized price for our liquids-rich gas stream processed at the plant) and in anticipation of our continued build-out of our Eureka Hunter Gas Gathering System.
Utilize Expertise in Unconventional Resource Plays to Improve Rates of Return
We strive to use state-of-the-art drilling, completion and production technologies, including certain completion techniques that we have developed and continue to refine, allowing us the best opportunity for cost-effective drilling, completion and production success. Our technical team regularly reviews the most current technologies and, to the extent appropriate and cost-effective, applies them to our reserve base for the effective development of our project inventory. As a result of our improving drilling and completion techniques, our drilling and completion results in our core unconventional resource plays have improved significantly, resulting in substantially better initial production, or IP, rates, estimated ultimate recoveries, and, ultimately, rates of return on capital deployed. Additionally, our focus on increasing and concentrating our acreage provides the opportunity to capture economies of scale, such as pad drilling, and to reduce rig mobilization time and cost.
Focus on Properties with Operating Control
We believe that operatorship provides us with the ability to maximize the value of our assets, including control of the timing of drilling expenditures, greater control of operational costs and the ability to efficiently increase production volumes and reserves. During the past five years, we have significantly increased the number of wells that we operate and control. As of January 31, 2014, we were operating approximately 78% of our producing wells. As of December 31, 2013, we were the operator on leases accounting for approximately 65% of our proved reserves. Approximately 76% of our 2014 capital expenditure budget relates to our operated properties.
Continued Development of our Eureka Hunter Gas Gathering System
We are continuing the commercial development of our Eureka Hunter Gas Gathering System in West Virginia and Ohio to provide infrastructure to support the development of our existing and anticipated future Marcellus Shale and Utica Shale acreage positions, as well as to provide the opportunity for substantial cash flow from the increasing gathering needs of third party producers in these regions.
Our Competitive Strengths
We believe we have the following competitive strengths that will support our efforts to successfully execute our business strategy:
Long-Lived Asset Base with Substantial Oil and Liquids Reserves
We believe our mix of properties and drilling opportunities, combined with timely development and additional acquisitions of properties in our core resource areas, present us with a variety of highly economic growth opportunities. As of December 31, 2013, approximately 46% and 52% of our proved reserves and production, respectively, were oil and natural gas liquids. As of January 31, 2014, we held ownership interests in approximately 5,175 gross (3,658.7 net) wells. We expect to increase our oil and natural gas reserves over time through our focused drilling program in our core areas and through possible acquisitions.
Improving Results in Our Core Resource Areas
As a result of our improved drilling and completion techniques, our initial production, or IP, rates have steadily increased over the last couple years. As of January 31, 2014, IP-24 rates for our five most recently completed Company-operated horizontal wells in the Marcellus Shale averaged approximately 12,158 MMcf/d. In the Utica Shale, we recently announced our first dry gas well located on the Stalder Pad in Monroe County, Ohio, was placed on production on February 9, 2014, and tested at a peak rate of 32.5 MMcf of natural gas per day. We plan to continue to refine our drilling and completion techniques in the Marcellus Shale and the Utica Shale plays and thereby improve initial production rates with a goal to lower drilling and completion costs.
Operational Control over Significant Portion of Assets
We operate a significant portion of our assets (approximately 78% of our producing wells as of January 31, 2014). Consequently, we have substantial control over the timing, allocation and amount of a significant portion of our planned 2014 capital expenditures, which allows us the flexibility to reallocate these expenditures depending on commodity prices, rates of return and prevailing industry conditions. We have continued to demonstrate increasingly robust drilling and completion results in our operated areas as we execute on our strategy.
Experienced Management Team with Proven Operating and Acquisition History
Our senior management team, on average, has over 25 years of experience in the oil and gas industry and has extensive experience in managing, financing and operating public oil and gas companies. Magnum Hunter Resources, Inc., founded by Gary C. Evans, our chairman and chief executive officer, in 1985, achieved an average annual internal rate of return to shareholders of 38% during the 15 years it was publicly traded before it was sold to Cimarex Energy Corporation for $2.2 billion in 2005. Additionally, our management team has collectively completed financing transactions and acquisitions in the oil and gas industry totaling billions of dollars, and our key personnel have extensive expertise in the principal operational disciplines in our core unconventional resource plays.
Our Significant Recent Developments
Eagle Ford Properties Sale
On April 24, 2013, we sold our core properties in the oil window of the Eagle Ford Shale in Gonzales and Lavaca Counties, Texas to an affiliate of Penn Virginia Corporation, or Penn Virginia, for a total contract purchase price of $401 million, consisting of $361 million in cash (before customary purchase price adjustments) and $40 million in Penn Virginia common stock. At closing, we received $422.1 million in cash and stock, based on initial cash purchase price adjustments and the market price of the Penn Virginia common stock on the closing date. The cash portion of the purchase price is subject to final settlement of the purchase price adjustment amounts, and we estimate that the final adjustment will result in an obligation to Penn Virginia of $22 million to $33 million, net of taxes. See “Item 3. Legal Proceedings-Eagle Ford Properties Sale Final Settlement.” We used the cash portion of the purchase price to repay all then outstanding borrowings under our revolving credit facility and for general corporate purposes. The properties sold to Penn Virginia included approximately 19,000 net Eagle Ford Shale leasehold acres, and our operating and non-operating leasehold working interests in certain existing wells, in Gonzales and Lavaca Counties, Texas. The effective date of the transaction was January 1, 2013.
Sale of Non-Core North Dakota Assets
On September 27, 2013, we sold our non-operated working interests in certain oil and natural gas properties located in Burke County, North Dakota, to Oasis Petroleum of North America LLC, or Oasis, for a contract purchase price of $32.5 million in cash (before customary purchase price adjustments). The effective date of the transaction was July 1, 2013.
On December 30, 2013, we sold our North Dakota waterflood properties located in Burke, Renville, Bottineau and McHenry Counties, North Dakota to Enduro Operating LLC, or Enduro, for a contract purchase price of $45 million in cash (before customary purchase price adjustments). The effective date of the transaction was September 1, 2013.
Sale of Remaining Eagle Ford Shale and Pearsall Shale Assets
On January 28, 2014, we sold substantially all of our remaining oil and natural gas properties in the Eagle Ford Shale and Pearsall Shale in south Texas to an affiliate of New Standard Energy Limited, or NSE, for a total contract purchase price of $24.5 million, consisting of $15 million in cash (before customary purchase price adjustments) and $9.5 million in ordinary shares of NSE. The effective date of the transaction was December 1, 2013.
MNW Leasehold Acquisition
On August 12, 2013, we entered into an asset purchase agreement with MNW Energy, LLC or MNW. MNW represents an informal association of various land owners, lessees of mineral acreage and sub lessees of mineral acreage who own or have rights in mineral acreage located in Monroe, Noble and/or Washington Counties, Ohio. Pursuant to the agreement, we agreed to acquire from MNW up to 32,000 net mineral acres, including currently leased and subleased acreage, located in Monroe, Noble and/or Washington Counties, Ohio, over a period of time, in staggered closings, subject to the satisfaction of certain closing conditions, including our right to receive satisfactory title to the acreage. As of January 31, 2014, we had acquired 6,129 net acres pursuant to MNW closings. On December 30, 2013, a lawsuit was filed against us, MNW and others asserting certain claims relating to the acreage covered by our agreement with MNW. We believe the claims asserted against us in the lawsuit are without merit. However, the claims asserted in the lawsuit may impair our right to receive satisfactory title to the acreage; therefore, future MNW closings may be delayed until this matter is resolved. See “Item 3. Legal Proceedings-Dux Litigation.”
Expansion of Eureka Hunter Gas Gathering System
In 2013, we expanded our Eureka Hunter Gas Gathering System, completing the construction of approximately 22 miles of additional pipeline in Monroe County, Ohio, for a total of over 100 miles of completed pipeline at January 31, 2014. In January 2013, we extended our Pursley lateral section of the pipeline (which is a 20-inch lateral section extending north from our main line) under the Ohio River from Wetzel County, West Virginia into Monroe County, Ohio. In December 2013, we completed our Tippens lateral section of the pipeline, which is a 20-inch lateral section that extends approximately 11 miles west-northwesterly from our Ohio River crossing near Sardis, Ohio, allowing for the gathering of dry Utica Shale gas production from multiple well pads, including our Stalder pad. We continue to construct the pipeline further into Ohio to support the continued development of our Marcellus Shale and Utica Shale acreage in Ohio, as well as acreage of third party producers.
2014 Capital Expenditure Budget
Our capital expenditure budget for fiscal year 2014 is currently (a) $310 million for our core upstream operations, consisting of approximately $260 million for the Marcellus and Utica Shales in West Virginia and Ohio and approximately $50 million for the Williston Basin/Bakken Shale in North Dakota, and (b) $90 million (net to our majority interest) for our midstream operations (excluding, in each case, any budgeted amounts for operations that may be acquired pursuant to acquisitions). We expect that the 2014 capital expenditure budget for our midstream operations will be funded by us and by the third-party equity and non-recourse debt facilities we have obtained for our midstream operations. See "Management's Discussion and Analysis of Financial Condition and Results of Operations" in this annual report for a description of these facilities, including the third-party equity commitment for our midstream operations (under which we have the right to make capital contributions in conjunction with or alongside the capital contributions from the third party).
Because of the volatility of commodity prices and the risks involved in our industry, we believe in remaining flexible in our capital budgeting process. When appropriate, we may defer existing capital projects to pursue an attractive acquisition opportunity or reallocate capital to projects we believe can generate higher rates of return on capital employed. We also believe in maintaining a strong balance sheet and using commodity price derivatives to mitigate uncontrollable risk. This allows us to be more opportunistic in a lower commodity price environment as well as providing more consistent financial results in the long-term.
Our Operations
Appalachian Basin Properties
The Appalachian Basin is considered one of the most mature oil and natural gas producing regions in the United States. Our core Appalachian Basin properties are located in West Virginia and Ohio, targeting the liquids rich Marcellus Shale and Utica Shale and the dry gas window of the Utica Shale.
We initially entered the Appalachian Basin through an asset acquisition in February 2010 and have subsequently expanded our operations through various acquisitions and joint ventures and development drilling efforts. As of January 31, 2014, we had approximately 78,709 net leasehold acres in the Marcellus Shale and approximately 99,078 net leasehold acres prospective for the Utica Shale (a portion of which acreage overlaps our Marcellus Shale acreage). We believe approximately 36,500 of these Utica Shale net acres are located in the wet gas window of the play.
As of December 31, 2013, proved reserves attributable to our Appalachian Basin properties were 53.4 MMBoe, of which 57% were classified as proved developed producing. As of December 31, 2013, these proved reserves had a PV-10 value of $507.3 million.
Our capital budget for 2014 includes approximately $260 million for capital expenditures in the Appalachian Basin, essentially all in the Marcellus Shale and Utica Shale regions. We intend to drill a total of approximately 25 gross horizontal wells in the Marcellus Shale and Utica Shale in 2014.
Marcellus Shale Properties
As of January 31, 2014, we had a total of approximately 78,709 net leasehold acres in the Marcellus Shale. Our Marcellus Shale acreage is located principally in Tyler, Pleasants, Richie, Wetzel and Lewis Counties, West Virginia and in Washington and Monroe Counties, Ohio. As of January 31, 2014, we had (a) 35 horizontal wells producing in the Marcellus Shale (including non-operated wells), and (b) 14 horizontal wells (7.9 net) awaiting completion, one horizontal well (one net) drilling, and one drilling rig operating on our Company-operated Marcellus Shale properties. As of January 31, 2014, approximately 76% of our mineral leases in the Marcellus Shale area were held by production. As of January 31, 2014, our five most recently completed Company-operated horizontal wells targeting the Marcellus Shale generated approximately 12,158 Mcfe/d and 7,005 Mcfe/d average IP-24 hour and IP-30 day rates, respectively.
The liquids rich natural gas produced in our core Marcellus Shale area (which has a Btu content ranging from 1,125 to 1,435), coupled with a location near the energy-consuming regions of the mid-Atlantic and northeastern U.S., typically allow us to sell our natural gas at a premium to prevailing NYMEX spot prices. Historically, producers in the Appalachian Basin developed oil and natural gas from shallow Mississippian age sandstone and Upper Devonian age shales with low permeability, which are prevalent in the region. Traditional shallow wells in the Appalachian Basin generally produce little or no water, contributing to a low cost of operation. However, in recent years, the application of horizontal well drilling and completion technology has led to the development of the Marcellus Shale, transforming the Appalachian Basin into one of the country’s premier natural gas reserves. The productive limits of the Marcellus Shale cover a large area within New York, Pennsylvania, Ohio and West Virginia. This Devonian age shale is a black, organic rich shale deposit productive at depths between 5,500 and 7,500 feet and ranges in thickness from 50 to 80 feet. It is considered the largest natural gas field in the country. Marcellus Shale gas is best produced from hydraulically fractured horizontal wellbores, exceeding 2,000 feet in lateral length, and involving multistage fracturing completions.
In December 2011, we entered into joint development and operating agreements with Stone Energy Corporation, or Stone Energy, pursuant to which we and Stone Energy agreed to jointly develop a contract area consisting of approximately 1,925 leasehold acres in the Marcellus Shale in Wetzel County, West Virginia. Each party owns a 50% working interest in the contract area. Stone Energy
is the operator for the contract area. Stone Energy also contributed to the joint venture certain infrastructure assets, including improved roadways, certain central field processing units (including water handling) and gas flow lines, and agreed to commit its share of natural gas production from the contract area to gathering by our Eureka Hunter Gas Gathering System. As of January 31, 2014, Stone Energy had drilled and completed 15 producing Marcellus Shale wells pursuant to this joint development program. We expect an additional four program wells to be on production in 2014.
In January 2013, we entered into joint development and operating agreements with Eclipse Resources I, LP, or Eclipse Resources, pursuant to which the parties agreed to jointly develop a contract area consisting of approximately 1,950 leasehold acres in the Marcellus Shale and Utica Shale in Monroe County, Ohio. Each party owns a 47% working interest in the contract area. We are the operator for the contract area. Eclipse Resources also agreed to dedicate its share of production from the contract area to gathering by our Eureka Hunter Gas Gathering System. As of January 31, 2014, we had drilled one Marcellus Shale well and one Utica Shale well (and are in the process of completing the Utica Shale well) pursuant to this joint development program. We expect to drill an additional nine Marcellus Shale wells and seven Utica Shale wells pursuant to this joint development program over the next 12 to 18 months.
The following table contains certain information regarding our Marcellus Shale horizontal wells drilled or completed in 2013.
During 2014, we plan to drill a total of 18 gross (16 net) wells in the Marcellus Shale.
Utica Shale Properties
As of January 31, 2014, we had a total of approximately 99,078 net leasehold acres prospective for the Utica Shale. Approximately 63,877 of the net acres are located in Ohio (a portion of which acreage overlaps our Marcellus Shale acreage), and approximately 35,201 of the net acres are located in West Virginia (a portion of which acreage overlaps our Marcellus Shale acreage). Our Utica Shale acreage is located principally in Tyler, Pleasants and Wood Counties, West Virginia and in Washington, Monroe, Morgan and Noble Counties, Ohio. We believe approximately 36,500 of our Utica Shale net acres are located in the wet gas window of the play. As of January 31, 2014, we had two horizontal wells (1.5 net) awaiting completion, one horizontal well (one net) drilling, and one drilling rig operating on our Company-operated Utica Shale properties. Approximately 65% of our acreage in the Utica Shale is held by shallow production. Our first dry gas Utica Shale well located on the Stalder Pad in Monroe County, Ohio, was placed on production on February 9, 2014 and tested at a peak rate of 32.5 MMcf of natural gas per day. The Stalder #3UH well was drilled and cased to a true vertical depth of 10,653 feet with a 5,050 foot horizontal lateral, and successfully fraced with 20 stages.
On August 12, 2013, we entered into an asset purchase agreement with MNW. MNW represents an informal association of various land owners, lessees of mineral acreage and sub lessees of mineral acreage who own or have rights in mineral acreage located in Monroe, Noble and/or Washington Counties, Ohio. Pursuant to the agreement, we agreed to acquire from MNW up to 32,000 net mineral acres, including currently leased and subleased acreage, located in Monroe, Noble and/or Washington Counties, Ohio, over a period of time, in staggered closings, subject to the satisfaction of certain closing conditions, including our right to receive
satisfactory title to the acreage. As of January 31, 2014, we had acquired 6,129 net acres pursuant to MNW closings. On December 30, 2013, a lawsuit was filed against us, MNW and others asserting certain claims relating to the acreage covered by our agreement with MNW. We believe the claims asserted against us in the lawsuit are without merit. However, the claims asserted in the lawsuit may impair our right to receive satisfactory title to the acreage; therefore, any future MNW closings may be delayed until this matter is resolved. See “Item 3. Legal Proceedings-Dux Litigation.”
The Utica Shale is located in the Appalachian Basin of the United States and Canada. The Utica Shale is a rock unit comprised of organic-rich calcareous black shale that was deposited about 440 million to 460 million years ago during the Late Ordovician period. It overlies the Trenton Limestone and is located a few thousand feet below the Marcellus Shale, which is considered to be the largest exploration play in the eastern United States.
The Utica Shale may be comparable or thicker and more geographically extensive than the Marcellus Shale, although reported drilling results in the play are still not sufficient to conclusively establish the geographical extent of the play. The potential source rock portion of the Utica Shale underlies portions of Kentucky, Maryland, New York, Ohio, Pennsylvania, Tennessee, West Virginia and Virginia in the United States and is also present beneath parts of Lake Ontario, Lake Erie and Ontario, Canada. Throughout the potential source rock area, the Utica Shale ranges in thickness from less than 100 feet to over 500 feet. Over the rock unit as a whole, there is a general thinning from east to west.
The Utica Shale is deeper than the Marcellus Shale. In some parts of Pennsylvania, the Utica Shale is estimated to be over two miles below sea level and up to 7,000 feet below the Marcellus Shale. However, the depth of the Utica Shale decreases to the west into Ohio and to the northwest under the Great Lakes and into Canada to less than approximately 2,000 feet below sea level. Most of our acreage is located at depths of 7,600 to 11,000 feet and approximately 3,000 feet below the Marcellus Shale.
The Utica Shale is estimated to have higher carbonate and lower clay mineral content than the Marcellus Shale. The difference in mineralogy generally produces a different response to hydraulic fracturing treatments. Operation drillers have redesigned and improved the fracturing methods in the Utica Shale, to generally match or improve upon, to the extent deemed beneficial, those methods used in other natural gas shales with comparable carbonate content. For example, drillers have discovered methods to make the brittle carbonate zones in the Utica Shale fracture at generally higher rates than gas shale rock units in the Eagle Ford Shale in Texas. Drillers are researching methods to make other similar fracturing improvements in the Utica Shale.
The Point Pleasant formation in the Utica Shale is generally 100 to 150 feet thick and is our primary targeted reservoir for horizontal drilling in the play. This formation is primarily limestone with inter-bedded shales deposited within an organic rich marine environment. The Point Pleasant formation has the composition for hydrocarbon generation and brittleness. Combined with the organic content, or TOC, a 6% to16% porosity, thermal maturity and a significant geo-pressured condition, the Point Pleasant formation has the characteristics for an ideal unconventional reservoir. The Point Pleasant formation appears to have a significant amount of hydrocarbons in place, and the techniques for successful drilling in the formation appear similar to those of the Eagle Ford Shale in Texas; longer laterals, more stages of fracture stimulation and more effective treatment of the horizontal lateral appear to be key to the optimization of recoverable reserves and return on investment.
Based on estimates published by the Ohio Department of Natural Resources, or ODNR, in 2012, the Utica Shale had a recoverable potential of 1.3 billion to 5.5 billion barrels of oil and 3.8 to 15.7 trillion cubic feet of natural gas in Ohio alone. During 2013, a number of oil and gas companies made significant investments in acquiring Utica Shale acreage in eastern Ohio. Recently, the ODNR reported that in the Utica Shale in Ohio there were 292 producing horizontal wells, 315 horizontal wells that had been drilled but were not yet completed or connected to a pipeline, 40 horizontal wells that were being drilled and 1,061 horizontal wells that had been permitted.
During 2013, most of the drilling activity in the Utica Shale occurred in eastern Ohio, where our acreage is located. Based on the initial drilling results of other producers, the Utica Shale is prospective for oil, natural gas and natural gas liquids. Early wells drilled in the Utica Shale by other producers have indicated greater potential for production of significant amounts of natural gas liquids, which generally have a higher value, on an energy-equivalent basis, than natural gas.
During 2014, we plan to drill a total of seven gross (seven net) wells in the Utica Shale.
Recent Marcellus Shale and Utica Shale Activities
During the fourth quarter of 2013, we completed the drilling of seven gross (seven net) wells and completed eight gross (six net) wells in the Marcellus Shale and Utica Shale plays. These eight gross (six net) completed wells are currently flowing to sales through the Eureka Hunter Gas Gathering System. Our net production in the fourth quarter of 2013 attributable to Triad Hunter, LLC’s operations was approximately 37.6 Mcfe/d.
As mentioned above, our 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 in early February 2014 and tested at a peak rate of 32.5 MMcf of natural gas per day. The
well continues to flow to sales points through the Eureka Hunter Gas Gathering System with the amount of frac water continuing to decrease since the commencement of initial sales.
Our first Marcellus Shale well drilled on the Stalder Pad, the Stalder #2MH, is awaiting the start of completion operations, which we expect to commence in March 2014. The Stalder #2MH was drilled and cased to a true vertical depth of 6,070 feet with a 5,474 foot horizontal lateral. We expect the production from this well to be very liquids rich.
On our Farley Pad located in Washington County, Ohio, we 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. We have commenced drilling another Utica Shale well on the Farley Pad, the Farley #1304H. We have commenced drilling the vertical section of this well and anticipate reaching a true vertical depth of 7,885 feet, and completing the drilling of a 5,500 foot horizontal lateral, in late March 2014. Following the drilling of the Farley #1304H, we will begin fracture stimulation of these two new Farley wells in mid-March 2014 and expect to report initial production test rates in May 2014 following an approximate 30-day resting period. We are in the advanced stages of negotiating new take-away capacity with a third-party midstream company and expect to be ready to flow production of all the wells on the Farley Pad to sales following the resting period.
On our WVDNR Pad located in Wetzel County, West Virginia, we have drilled and are 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. We have fracture stimulated eight of the proposed 20 stages on each of the three wells. During the last several weeks, we have experienced substantial completion delays in this region primarily due to the effects of extreme cold weather conditions. We expect to finish fracture stimulating the three WVDNR wells over the next 7 to10 days, and anticipate production from the wells to begin to flow to sales in mid-March 2014.
On our Stewart Winland Pad located in Tyler County, West Virginia, we have 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. We skid the drilling rig and commenced the drilling of another Marcellus Shale well, the Stewart Winland #1302, on this pad. We expect to drill one additional Marcellus Shale well and one Utica Shale well on this pad. We expect to report initial production test rates from the four wells on the Stewart Winland Pad during mid-Summer 2014. We are in the process of making several midstream upgrades at both our Collins and Spencer Pads in Tyler County, West Virginia to adequately handle the expected additional liquids production. We expect to complete these production equipment changes in March or April 2014. As a result, we do not expect to encounter any liquids infrastructure issues associated with the initial production from the four wells on our Stewart Winland Pad.
Southern Appalachian Basin Properties
We have classified our southern Appalachian Basin properties located primarily in Kentucky and Tennessee as assets held for sale and the associated operations are reflected as discontinued operations in our financial statements. We anticipate completing the divestiture of such assets in the second half of 2014.
As of January 31, 2014, our southern Appalachian Basin properties included approximately 258,918 net acres, primarily in Kentucky. Our primary production from the southern Appalachian Basin properties comes from the Devonian Shale formation and the Mississippian Weir sandstone.
Our southern Appalachian properties also include (i) a non-operating interest in a coal bed methane project in the Arkoma Basin in Arkansas and Oklahoma, (ii) certain non-operated projects in West Virginia and Virginia and (iii) an operating interest in a New Albany Shale field in western Kentucky known as Haley’s Mill.
Williston Basin Properties
We refer to our properties in North Dakota, which are located in the Williston Basin, as our Williston Basin U.S. properties and our properties in Canada, which are located in the Williston Basin in Saskatchewan and in certain other formations in Alberta, as our Williston Hunter Canada properties.
We established our initial presence in the Bakken/Three Forks Sanish formations in North Dakota with an acquisition in May 2011 and have expanded our presence in the Bakken Shale through subsequent acquisitions. We recently sold certain non-core properties in North Dakota. See “-Our Significant Recent Developments-Sale of Non-Core North Dakota Assets.” As of January 31, 2014, our Williston Basin U.S. properties included approximately 102,869 net acres in the Bakken/Three Forks Sanish formations in North Dakota. Our Williston Basin U.S. acreage is located in Divide County, North Dakota.
As of January 31, 2014, we had drilled and completed approximately 298 gross (98.1 net) wells on our Bakken/Three Forks Sanish properties, including 255 gross (61 net) wells in the Bakken/Three Forks Sanish in North Dakota and 43 gross (37.1 net) wells in the Bakken/Three Forks Sanish in Saskatchewan. Of these wells, approximately 70 gross (21 net) wells in the Bakken/Three Forks
Sanish in North Dakota, and approximately six gross (4.2 net) wells in the Bakken/Three Forks Sanish in Saskatchewan, were completed in 2013 and through January 31, 2014. As of January 31, 2014, we operated 52 of our Bakken/Three Forks Sanish wells, including nine wells in the Bakken/Three Forks Sanish in North Dakota and 43 wells in the Bakken/Three Forks Sanish in Saskatchewan. As of December 31, 2013, proved reserves attributable to our Williston Basin properties were 20.8 MMBoe, of which 94% were oil and natural gas liquids and 44% were classified as proved developed producing. As of December 31, 2013, these proved reserves had a PV-10 value of $400 million.
Our 2014 capital expenditure budget includes approximately $50 million of capital expenditures in the Williston Basin/Bakken Shale in North Dakota. We expect these capital expenditures to relate primarily to the drilling of wells in which we participate as a non-operated working interest owner. We anticipate these wells will include approximately 20 gross wells located primarily in the Ambrose Field in Divide County, North Dakota.
The Williston Basin is spread across North Dakota, Montana and parts of southern Canada with the U.S. portion of the basin encompassing approximately 143,000 square miles. The basin produces oil and natural gas from numerous producing horizons, including the Madison, Bakken, Three Forks Sanish and Red River formations. The Bakken formation is a Devonian age shale. The North Dakota Geological Survey and Oil and Gas Division estimates that the Bakken formation is capable of generating between 271 and 500 billion Bbl of oil. The Bakken formation underlies portions of North Dakota and Montana and southern Canada and is generally found at vertical depths of 9,000 to 10,500 feet. Below the Lower Bakken Shale lies the Three Forks Sanish formations, which have also proved to contain highly productive reservoir rock. The Three Forks Sanish formations typically consist of interbedded dolomites and shale with local development of a discontinuous sandy member at the top, known as the Sanish sand. Economic crude oil development and production from the Bakken/Three Forks Sanish reservoirs are made possible through the combination of advanced horizontal drilling and fracture stimulation technology. Horizontal wells in these formations are typically drilled on 640 acre or 1,280 acre spacing with horizontal laterals extending 4,500 to 9,500 feet into the reservoir. Ultimately, a spacing unit may be developed with up to four horizontal wells in each formation. Fracture stimulation techniques generally utilize multi-stage mechanically diverted stimulations.
Williston Basin U.S. Properties
Bakken/Three Forks Sanish Properties. As of January 31, 2014, our Williston Basin U.S. properties included approximately 102,869 net acres in the Bakken/Three Forks/Sanish formations in the Williston Basin in North Dakota located in Divide County, North Dakota. As of January 31, 2014, our Bakken/Three Forks Sanish properties in North Dakota included approximately 255 gross (61 net) productive wells, and we were operating 9 of these gross wells. As of January 31, 2014, 4 horizontal wells (1.4 net) were awaiting completion, 5 wells (1.4 net) were being drilled and 3 drilling rigs were operating on our Bakken/Three Forks Sanish properties in North Dakota.
Oneok Gas Gathering Arrangement. In 2012, we entered into a gas purchase agreement with Oneok Inc., or Oneok, pursuant to which Oneok is currently constructing a natural gas gathering system and related facilities in North Dakota for the gathering and processing by Oneok of associated natural gas production, including the associated natural gas production from certain of our oil properties in Divide County, North Dakota dedicated by us to Oneok for this purpose. Pursuant to this arrangement, Oneok will purchase our natural gas and natural gas liquids production from the dedicated properties, and we will be responsible for certain well tie-in and electrical power costs associated with the Oneok system and certain minimum yearly gas sale volume requirements. The sale of our natural gas and natural gas liquids production to Oneok pursuant to this arrangement allows us to realize revenues from our natural gas stream in the Divide County area. Oneok has completed the construction of the compressor station, 12-inch high-pressure discharge line and northern-most east/west gathering pipeline in Divide County. The Oneok system is complete and operational and we commenced tying in and flowing production in certain of our Divide County properties beginning in 2013. We also anticipate delivering certain of our Saskatchewan associated natural gas production into the Oneok system.
A significant amount of the associated natural gas produced from oil properties in certain regions of North Dakota is currently being flared or otherwise not marketed because of the lack of available gas gathering and processing infrastructure in these regions. Current and anticipated future North Dakota state regulations on gas flaring restrict and may further restrict, and may possibly prohibit, oil production in North Dakota as to which associated natural gas is flared rather than gathered. We expect that our arrangement with Oneok will permit us to continue to produce crude oil from our properties in Divide County, North Dakota in compliance with these existing or future state regulations.
The following table contains certain information regarding our Bakken/Three Forks Sanish horizontal wells drilled or completed in 2013.
Williston Hunter Canada Properties
We have classified our Williston Hunter Canada properties as assets held for sale and the associated operations are reflected as discontinued operations in our financial statements. We anticipate completing the divestiture of such assets in the second quarter of 2014.
As of January 31, 2014, our Williston Hunter Canada properties included approximately 49,588 net acres in the Tableland Field in the Williston Basin in Saskatchewan and approximately 26,812 net acres in Alberta. As of January 31, 2014, our Williston Hunter Canada properties included approximately 87 gross (77.9 net) productive oil and natural gas wells, 98% of which we operate.
Saskatchewan. The Tableland Field properties target sweet light oil from the Bakken/Three Forks Sanish formations. At January 31, 2014, we had approximately 49,588 net acres of largely contiguous land that is prospective for Bakken/Three Forks Sanish oil in the Tableland Field. As of January 31, 2014, we had 43 producing oil wells (37.1 net) in the Tableland Field.
Alberta. Our Alberta properties target shallow natural gas and sweet light oil from the Enchant Second White Specks formation and the Kiskatinaw formation. At January 31, 2014, we had approximately 26,812 net acres in Alberta. At January 31, 2014, we had 4 producing oil wells (2.7 net) in Alberta.
Other Upstream Properties
The Company owns certain other scattered miscellaneous oil and gas properties in Texas and Louisiana. We have not allocated any significant capital to these assets for 2014.
Midstream Operations
Eureka Hunter Gas Gathering System
We acquired assets in 2010 that included gas gathering systems and pipeline rights-of-way in West Virginia and Ohio. We have developed and continue to develop these assets into our Eureka Hunter Gas Gathering System, which helps support our existing and anticipated future Marcellus Shale and Utica Shale acreage positions, as well as the expanding gathering needs of third-party producers. As of January 31, 2014, the Eureka Hunter Gas Gathering System consisted of over 100 miles of 20-inch and 16-inch high-pressure steel pipe with an estimated 350 MMcf/d of initial throughput capacity, of which approximately 86 miles is currently active, located in northwestern West Virginia and southeastern Ohio. The Eureka Hunter Gas Gathering System and associated rights-of-way run through Pleasants, Tyler, Ritchie, Wetzel, Marion, Harrison, Doddridge, Lewis and Monongalia Counties in West Virginia and Washington County, Ohio, in certain liquids rich portions of the Marcellus Shale and Utica Shale. The first completed six-mile section of the Eureka Hunter Gas Gathering System was turned to sales in December 2010.
In 2012, we completed the construction of our Pursley lateral section of the pipeline up to the Ohio River, which is a 20-inch lateral section of pipeline extending approximately 19 miles northerly through Tyler and Wetzel Counties, West Virginia, extending to the Ohio River, near Monroe County, Ohio. In January 2013, we successfully bored under the Ohio River to continue the construction of the lateral into Ohio.
In the fourth quarter of 2012, we completed the construction of our Lewis-Wetzel lateral, which is a 20-inch lateral section of pipeline extending approximately seven and one quarter miles originating near the eastern end of the mainline extending northerly through the Wetzel Wildlife Refuge in Wetzel County, West Virginia and terminating at our Eureka Carbide Facility, near the community of Carbide in Wetzel County.
We completed the initial construction of the Eureka Carbide Facility in 2012. This facility includes (a) an 8-inch low-pressure liquids gathering section of pipeline extending approximately two and one third miles for gathering wellhead produced condensate and liquids from wells located in the Lewis Wetzel Wildlife area, (b) a 12-inch low-pressure gas gathering section of pipeline extending approximately two and one third miles for gathering gas production from wells located in the Lewis Wetzel Wildlife area and (c) equipment utilized to handle and stabilize liquids extracted from the pipeline during routine pigging operations as well as liquids gathered by the Lewis Wetzel condensate gathering system. We are currently adding new mainline compression equipment at the facility, to handle expected additional volume demand and reduce line pressure for producers. The Eureka Carbide Facility facilitates our gathering of production from producing wells of us and Stone Energy in Wetzel County, West Virginia.
In the fourth quarter of 2012, we completed the construction of our Mobley lateral section of the pipeline, which is a 20-inch lateral section extending approximately eight miles originating at the Eureka Carbide Facility extending easterly and terminating at the inlet of the Mobley Processing Plant in Wetzel County, West Virginia, in order to provide access for gas processing at the plant.
In 2012, we began construction of our Doddridge lateral section of the pipeline, which is a 16-inch lateral section of pipeline extending southerly from the mainline into northwest Doddridge County, West Virginia. As of January 31, 2014, we had completed approximately three miles of the Doddridge lateral.
In 2012, we began construction of our Ritchie lateral section of the pipeline, which is a 16-inch lateral section of pipeline extending southerly from the western end of the mainline into northwest Richie County, West Virginia. As of January 31, 2014, we had completed approximately 14 miles of the Ritchie lateral.
In December 2013, we completed our Tippens lateral section of the pipeline which is a 20-inch lateral section that extends approximately 11 miles west-northwesterly from our Ohio River crossing near Sardis, Ohio, allowing for the gathering of dry Utica Shale gas production from multiple well pads, including our Stalder pad. We continue to construct the pipeline further into Ohio to support the continued development of our Marcellus Shale and Utica Shale acreage in Ohio, as well as acreage of third party producers.
We have budgeted approximately $90 million (net to our majority interest) for Eureka Hunter Gas Gathering System projects in 2014. We anticipate these funds will be utilized primarily for pipeline construction projects in Ohio and West Virginia, including the completion of a separate lateral section that will extend approximately eight miles northerly and will run parallel to the Ohio River terminating near our Ormet, Ohio area of operations. We also plan to construct our Crescent lateral section of the pipeline, which will consist of approximately 16 miles of 20-inch pipeline for gathering dry Utica Shale gas production extending from the
terminus of the Tippens lateral northeasterly toward Clarington, Ohio. Near Clarington, Ohio, we plan to construct a natural gas compressor station and an interconnection with Rockies Express Pipeline along with other pipeline interconnections including with Texas Eastern Transmission Company and Dominion Transmission in the same general vicinity. In addition, we plan to construct a separate pipeline system for gathering liquids rich gas production from our Eureka Hunter Gas Gathering System at our Ormet well pad northerly to interconnect with a third party pipeline for ultimate delivery of liquids rich gas to the third party's plant for processing.
Other projects for 2014 include the completion of the Ritchie lateral which will add approximately 12 miles of 16-inch gathering pipeline terminating approximately three miles southeast of Cairo, West Virginia and approximately seven miles of 24-inch residue gas line extending from the tailgate of the Mobley Processing Plant to interconnect with the Columbia Gas Pipeline near Smithville, West Virginia.
Mobley Processing Plant
In late 2011, we entered into certain midstream services agreements with MarkWest, pursuant to which MarkWest agreed to provide long-term gas processing and related services for natural gas produced by both us and other producers and gathered through our Eureka Hunter Gas Gathering System. In December 2012, following the startup of MarkWest’s Mobley Processing Plant in Wetzel County, West Virginia, we began flowing natural gas production through the Eureka Hunter Gas Gathering System for processing at the Mobley Processing Plant. We have supplied and expect to continue to supply the Mobley Processing Plant with both Company and third-party natural gas produced primarily from the Marcellus Shale formation. MarkWest also provides natural gas liquids handling and fractionation services for Mobley Processing Plant products at its nearby fractionation facility. These agreements with MarkWest allow us to offer third-party producers in the Marcellus Shale not only gas gathering services through our Eureka Hunter Gas Gathering System, but also access to natural gas processing at the Mobley Processing Plant. Also, our ability to process our natural gas at the Mobley Processing Plant has provided and is expected to continue to provide us with an uplift in the realized price for our liquids-rich gas stream. Effective as of December 2013, we have committed to approximately 190,000 Mcf per day of the processing capacity at the Mobley Processing Plant. In April 2014, that volume will be reduced to 140,000 Mcf per day as we will release 50,000 Mcf per day of processing to a third party producer committed to gathering volumes through the Eureka Hunter Gas Gathering System.
In September 2013, the Mobley Processing Plant was temporarily shut down due to a break in a MarkWest natural gas liquids pipeline caused by a landslide in northern Wetzel County, which temporarily impacted our gas gathering operations and resulted in the temporary shut-in by us of approximately 20,000 Mcfe per day of natural gas production from certain of our Marcellus Shale acreage. The facility resumed operations in mid-October 2013, and we restarted our delivery of natural gas volumes to the Mobley Processing Plant. As of February 16, 2014, we were flowing approximately 171,000 MMbtus of natural gas per day through the Eureka Hunter Gas Gathering System. We gathered 3.2 Bcf of gas during January 2014 with a peak day of approximately 170,000 MMBtu of natural gas delivered to the Mobley Processing Plant on January 5, 2014. During the first six months of 2014, we expect to bring on significant volumes from us and third party producers with production connected to the Eureka Hunter Gas Gathering System.
Natural Gas Treating and Processing
We are a full service provider for the natural gas treating and processing needs of producers and midstream companies. We currently conduct treating and processing operations in Texas, Louisiana, Oklahoma and West Virginia and anticipate possible future operations in Arkansas, Mississippi and Ohio. As of January 31, 2014, we owned approximately 50 natural gas treating and processing plants in varying sizes and capacities designed to remove carbon dioxide, or CO2, and hydrogen sulfide, or H2S, from the natural gas stream. Our services also include the installation and maintenance of Joule-Thomson, or JT, plants, which are refrigeration plants designed to remove hydrocarbon liquids from the natural gas stream for dew point control (so that the residue gas meets pipeline specifications) and to upgrade the liquids for processing and marketing. We also offer full turnkey services including the installation, operation and maintenance of facilities. Our customers include small, independent producers, as well as large, publicly-traded companies. Currently, we are building small and medium-size gas treating and processing equipment to meet current and anticipated producer demand.
Other Gas Gathering and Processing
Gas Gathering. Natural gas production from our southern Appalachian Basin properties is delivered and sold through gas gathering facilities owned by Seminole Energy Services, L.L.C. We operate these gathering facilities, which are located in southeastern Kentucky, northeastern Tennessee and western Virginia. We have gas gathering, gas sales and gas gathering facilities operating agreements with Seminole Energy and affiliates, or Seminole Energy. The Seminole Energy agreements provide us with long-term operating rights and firm capacity rights for daily delivery of up to 30,000 Mcf of controlled gas through Seminole Energy’s Appalachia gathering system, which interconnects with Spectra Energy Partners’ East Tennessee Interstate pipeline network at Rogersville, Tennessee. This ensures continued deliverability from our connected fields, representing over 90% of our southern Appalachian natural gas production, to major East Coast natural gas markets.
Gas Processing. Eureka Hunter Pipeline owns a 50% interest in a liquids extraction plant in Rogersville, Tennessee, used for the processing of natural gas delivered through Seminole Energy’s gathering system. The Rogersville processing plant extracts natural gas liquids at levels enabling us to flow dry pipeline quality natural gas into the interstate network. The Rogersville processing plant is currently configured for throughput at rates up to 25,000 Mcf per day, which can be increased to accommodate production growth and relief of constrained regional supplies. The Rogersville processing plant is co-owned and is operated by Seminole Energy. Gas processing fees are volume dependent and are shared with Seminole Energy.
Restructuring of the Seminole Energy Agreements. Our agreements with Seminole Energy referred to above were restructured in connection with a global settlement of certain legal proceedings which we and Seminole Energy entered into in January 2014. The restructured agreements resulted in the following: (i) we obtained a substantial reduction in the gas gathering rates we pay for the natural gas production owned or controlled by us which is gathered by Seminole Energy's Appalachia gathering system; (ii) the parties agreed to construct a mechanical enhancement of the Rogersville processing plant, designed to recover less ethane and more propane from the natural gas delivered to and processed at the plant (and to credit us for certain costs of the enhancement otherwise payable by us as part owner of the plant, in exchange for certain contract rights assigned by us to Seminole Energy and based on certain other terms of the restructuring); (iii) the parties agreed to reduce and extend our contractual horizontal well drilling obligations in the Appalachian Basin owed to Seminole Energy; (iv) the parties agreed to the modification of (a) the natural gas processing rates we pay for processing gas at the Rogersville plant, (b) the allocation to us of natural gas liquids recovered from gas processed at the Rogersville plant, (c) the allocation to us of the costs of blend stock necessary to blend with the natural gas liquids produced from the Rogersville plant for purposes of transportation of the natural gas liquids to fractionators and (d) certain deductions to the natural gas liquids purchase price we pay for the purchase by Seminole Energy of our natural gas liquids produced from the Rogersville plant; and (v) the sale by Seminole Energy to us of Seminole Energy’s 50% interest in a natural gas gathering trunk line and treatment facility located in southwestern Muhlenberg County, Kentucky, which had previously been owned equally by Seminole Energy and us.
As a result of the restructuring effected by the settlement agreement, we expect to realize operational savings estimated at approximately $250,000 per month, certain components of which savings will occur over time, depending on the timing of implementation or completion of certain of the benefits provided to us by the restructuring. In addition, as a result of the restructuring, as of December 31, 2013, we have realized an increase of approximately 20% in the PV-10 value of that portion of our estimated total proved reserves attributable to our oil and gas properties in the Appalachian Basin affected by the restructuring, compared to the estimated PV-10 value of those reserves as of December 31, 2013, calculated by us without taking into account the effects of the restructuring.
Oil Field Services
We own and operate portable, trailer-mounted drilling rigs capable of drilling to depths of between 6,000 to 19,000 feet, which are used primarily for vertical section (top-hole) air drilling in the Appalachian Basin. The drilling rigs are used primarily for our Appalachian Basin operations and to provide drilling services to third parties. At January 31, 2014, our operating fleet consisted of five Schramm T200XD drilling rigs and one Schramm T500XD drilling rig. The Schramm T500XD rig is a portable, robotic drilling rig capable of drilling to depths (both vertically and horizontally) of up to 19,000 feet. This rig can be used to drill the horizontal sections of our Marcellus Shale and Utica Shale wells.
The T200XD drilling rigs primarily drill the top-holes of the Company's and third parties' Marcellus Shale and Utica Shale wells in preparation for larger drilling rigs, which drill the horizontal sections of the wells. This style of drilling has proved to reduce overall drilling costs, by minimizing mobilization and demobilization charges and significantly decreasing the overall time to drill horizontal wells on each pad site.
At January 31, 2014, four of the Schramm T200XD drilling rigs were under contract to a large producer in the Appalachian Basin area for the top-hole drilling of multiple wells through December 2014; one Schramm T200XD drilling rig was under contract to an independent producer in the Appalachian Basin, and will also be utilized by us for our top-hole drilling program; and the Schramm T500XD drilling rig was under contract to our subsidiary for our Marcellus Shale and Utica Shale drilling program. All these contracts are term contracts.
Marketing and Pricing
General
We derive revenue principally from the sale of oil and natural gas. As a result, our revenues are determined, to a large degree, by prevailing prices for crude oil and natural gas. We sell our oil and natural gas on the open market at prevailing market prices. The market price for oil and natural gas is dictated by supply and demand, and we cannot accurately predict or control the price we may receive for our oil and natural gas.
The Company generally markets its U.S. and Canadian oil and natural gas production under “month-to-month” or “spot” contracts.
We also derive revenue from our midstream operations.
Marketing of U.S. Production
We market crude oil produced from our Company-operated properties in North Dakota through a marketing and distribution firm under “month-to-month” or “spot” contracts, pursuant to which we receive spot market prices for the production. The crude oil is produced to tanks and then trucked to market. The crude oil produced from our third-party operated properties in North Dakota is sold by the operator along with the other well production. The production is typically transported to market by rail.
We generally sell our natural gas production on “month-to-month” or “spot” pricing contracts to a variety of buyers, including large marketing companies, local distribution companies and industrial customers. We diversify our markets to help reduce buyer credit risk and to ensure steady daily deliveries of our natural gas production. As natural gas production increases in our core operating areas, especially in the Appalachian Basin region, we believe that we and other producers in these areas will find it increasingly important to find markets that have the ability to move natural gas volumes through an increasingly capacity-constrained infrastructure.
Our natural gas liquids (other than ethane, when and if extracted) extracted and fractionated by MarkWest through its Mobley Processing Plant and related fractionation facility are marketed by MarkWest at prevailing market prices. We will be responsible for the marketing of such ethane, if and when extracted, depending on when the Mobley Processing Plant goes into ethane recovery mode. We expect that several markets will be available at that time for ethane sales.
Marketing of Canadian Production
Our oil production in Alberta and Saskatchewan is sold through an international crude oil marketing firm. Our oil production is mostly 38 - 42 degrees API gravity and is considered “sweet” since it contains only a small percentage of sulfur. Typically, clean oil is hauled from our facilities to a truck terminal where it enters the North American pipeline system and is sold to purchasers at monthly spot prices. The majority of our oil production is sold at a bench mark price at Cromer, Canada and adjusted for equalization and all applicable transportation charges to Cromer. We have begun to ship some of our oil production from our Saskatchewan properties by rail, and we receive a price for this production similar to the benchmark price at Cromer after adjustments.
Our Canadian natural gas production is sold through a marketing consulting firm. We currently sell gas from our Alberta properties to a buyer at “spot” natural gas prices less transportation, fuel and measurement variance costs.
We sell a small amount of natural gas liquids extracted from some of our Alberta natural gas production to the processing plant operator at current spot prices.
Marketing of Midstream Services
We market our gathering services to area producers primarily through “one on one” industry contacts generated through general industry knowledge and new contacts made through participation in industry conferences, as well as by tracking drilling permits. Our business development team monitors exploration efforts within reach of the Eureka Hunter Gas Gathering System and is in regular contact with companies that may benefit from the gathering services offered by us.
We market our gas treatment plants and services in very much the same manner as our gathering services. Much of our gas treatment business growth comes from existing customers seeking additional plants and services. New business is generated by the our marketing team by regularly visiting with producers that have new or expanded drilling and production operations in those areas served by our gas treatment business, by tracking drilling permits and through other producer referrals. We also expand our presence by participating in industry conferences and trade shows and by helping to sponsor industry events that benefit charities and local community needs in our areas of operations.
Pricing
Our revenues, cash flows, profitability and future rate of growth depend substantially upon prevailing prices for oil and natural gas. Prices also affect the amount of cash flow available for capital expenditures and our ability to borrow money or raise additional capital. Lower prices may also adversely affect the value of our reserves and make it uneconomic for us to commence or continue drilling for crude oil and natural gas. Historically, the prices received for oil and natural gas have fluctuated widely. Among the factors that can cause these fluctuations are:
•
uncertainty in the global economy;
•
changes in global supply and demand for oil and natural gas;
•
the condition of the United States, Canadian and global economies;
•
the actions of certain foreign countries;
•
the price and quantity of imports of foreign oil and liquid natural gas;
•
political conditions, including embargoes, war or civil unrest in or affecting oil producing activities of certain countries;
•
the level of United States and global oil and natural gas exploration and production activity;
•
the level of United States and global oil and natural gas inventories;
•
production or pricing decisions made by the Organization of Petroleum Exporting Countries;
•
weather conditions;
•
technological advances affecting energy consumption or production; and
•
the price and availability of alternative fuels.
Derivatives
We use commodity derivatives instruments, which we refer to as derivative contracts or derivatives, to reduce our exposure to oil and natural gas price fluctuations and to help ensure that we have adequate cash flow to fund our debt service costs, preferred stock dividend payments and capital expenditures. From time to time, we may enter into futures contracts, collars and basis swap agreements, as well as fixed price physical delivery contracts; however, it is our preference to utilize derivatives strategies that provide downside commodity price protection without unduly limiting our revenue potential in an environment of rising commodity prices. We use derivatives primarily to manage price risks and returns on certain acquisitions and drilling programs. Our policy is to use derivatives to cover an appropriate portion of our production at prices we deem attractive.
Derivatives may expose us to risk of significant financial loss in certain situations, including circumstances where:
•
our production and/or sales of oil and natural gas are less than expected;
•
payments owed under a derivative contract come due prior to receipt of the covered month’s production revenue; or
•
the counterparty to the derivative contract defaults on its contract obligations.
In addition, derivative contracts we may enter into may limit the benefit we would receive from increases in the prices of oil and natural gas; if, for example, the increase in prices extends above the applicable ceiling under the derivative contract. Also, derivative contracts we may enter into may not adequately protect us from declines in the prices of oil and natural gas; if, for example, the decline in price does not extend below the applicable floor under the derivative contract.
Furthermore, should we choose not to engage in derivatives transactions in the future (to the extent we are not otherwise obligated to do so under our credit facilities), or we are unable to engage in such transactions due to a cross-default under a debt agreement, we may be adversely affected by volatility in oil and natural gas prices.
As of December 31, 2013, we had the following derivatives in place:
________________________________
(1) A collar is a sold call and a purchased put. Some collars are "costless" collars with the premiums netting to approximately zero.
(2) These three-way collars are a combination of three options: a sold call, a purchased put and a sold put.
Drilling Partnerships
Prior to our acquisition of NGAS Resources, Inc., or NGAS, in April 2011, NGAS had, from 1992 through 2010, sponsored approximately 38 private drilling partnerships for accredited investors to participate in certain of its drilling initiatives. Generally, under these NGAS drilling partnerships, proceeds from the private placement of interests in each investment partnership, together with an NGAS capital contribution, were contributed to a separate joint venture or “program” that NGAS formed with that partnership to conduct the drilling operations.
In December 2011, we completed a sponsored drilling partnership, Energy Hunter Partners 2011-A, Ltd., raising approximately $12.9 million from accredited investors. In December 2012, we completed another sponsored drilling partnership, Energy Hunter Partners 2012-A Drilling & Production Fund, Ltd., raising approximately $20.3 million from accredited investors.
These two drilling partnerships were structured to allow the investors to participate with us in certain Company drilling initiatives in certain operating regions of the Company, including unconventional resource plays. The drilling partnership participates in the designated project wells through a joint venture operating partnership, referred to as the program, with our Company, which serves as the managing general partner of both the drilling partnership and the program. Proceeds from the private placement of interests in the drilling partnership, together with our capital contributions, are contributed to the program to fund the program’s share of drilling and completion costs of the project wells. Generally, interests in the program are shared proportionately until distributions to the drilling partnership reach a certain percentage of its investment in the program (or in individual wells), after which we will earn an additional reversionary interest in the program, the amount of which depends on the timing of such payout. The program participates in the drilling and completion of the project wells on a "cost plus" basis.
We may sponsor additional drilling and/or income partnership or partnerships to participate in Company drilling initiatives. Our sponsored programs and any future sponsored programs are designed to enable us to accelerate the development of our properties without relinquishing control over drilling and operating decisions, while also enabling us to hold valuable acreage for future development.
Reserves
Our oil and natural gas properties are primarily located in (i) the Appalachian Basin in West Virginia, Ohio and Kentucky, with substantial acreage in the Marcellus Shale and Utica Shale areas in West Virginia and Ohio; and (ii) the Williston Basin in North Dakota and Canada. Cawley, Gillespie & Associates, Inc. (“CG&A”), independent petroleum consultants, has estimated our oil and natural gas reserves and the present value of future net revenues therefrom as of December 31, 2013. These estimates were determined based on prices for the twelve-month period ended December 31, 2013, and lease operating expenses as of August 31, 2013. Since January 1, 2013, we have not filed, nor were we required to file, any reports concerning our oil and gas reserves with any federal authority or agency, other than the SEC. There are numerous uncertainties inherent in estimating quantities of proved oil and gas reserves, and estimates of reserve quantities and values must be viewed as being subject to significant change as more data about the properties become available.
Proved Reserves
At December 31, 2013, we held certain Eagle Ford Shale and Pearsall Shale assets that we retained when we sold most of our Eagle Ford Shale properties in April 2013. We sold substantially all of these remaining Eagle Ford Shale and Pearsall Shale assets in January 2014. See “-Our Significant Recent Developments-Sale of Remaining Eagle Ford Shale and Pearsall Shale Assets" below and "Note 19 - Subsequent Events" in the notes to our consolidated financial statements included in this report. The reserve information presented below includes reserves attributable to these January 2014 divested assets, as well as reserves attributable to our southern Appalachian Basin and Canadian assets held for sale.
The following table sets forth our estimated proved reserves quantities as defined in Rule 4.10(a) of Regulation S-X and Item 1200 of Regulation S-K promulgated by the SEC, as of December 31, 2013.
_______________
(1)
Represents the present value, discounted at 10% per annum, or PV-10, of estimated future cash flows before income tax of our estimated proved reserves. The estimated future cash flows were determined based on proved reserve quantities and the periods in which they are expected to be developed and produced based on prevailing economic conditions. With respect to the PV-10 value in the table above, the estimated future production is priced based on the 12-month un-weighted arithmetic average of the first-day-of-the-month price for the period January through December 2013, using $96.78 per Bbl and $3.67 per MMBtu and adjusted by lease for transportation fees and regional price differentials. Management believes that the presentation of the non-GAAP financial measure of PV-10 provides useful information to investors because it is widely used by professional analysts and sophisticated investors in evaluating oil and natural gas companies. See “Non-GAAP Measures; Reconciliations” below.
All of our reserves are located within the continental U.S. and Canada. Reserve estimates are inherently imprecise and remain subject to revisions based on production history, results of additional exploration and development, prices of oil and natural gas and other factors. Please read “Item 1A.
Item 1A.
RISK FACTORS
The factors described below should be considered carefully in evaluating our Company. The occurrence of one or more of these events or circumstances could materially and adversely affect our business, prospects, financial condition, results of operations and cash flows.
Risks Related to Our Business
We have a history of losses and cannot assure you that we will be profitable in the foreseeable future.
Since we entered the oil and gas business in April 2005 through December 31, 2013, we had incurred an accumulated deficit of $586.4 million. If we fail to eventually generate profits from our operations, we will not be able to sustain our business. We may never report profitable operations or generate sufficient revenue to maintain our Company as a going concern.
We have acquired a number of properties since June 2009 and, consequently, a large amount of our focus has been on assimilating the properties, operations and personnel we have acquired into our organization. Accordingly, we do not have a significant operating history upon which to judge our business strategy, our management team or our current operations.
Volatility in oil and natural gas prices may adversely affect our business, financial condition or results of operations and our ability to meet our capital expenditure obligations and financial commitments.
The prices we receive for our oil and natural gas production heavily influence our revenue, profitability, access to capital and future rate of growth. Oil and natural gas are commodities, and therefore their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil and natural gas have been extremely volatile. These markets will likely continue to be volatile in the future. The prices we receive for our production, and the levels of our daily production, depend on numerous factors beyond our control. These factors include, but are not limited to, the following:
•
the current uncertainty in the global economy;
•
changes in global supply and demand for oil and natural gas;
•
the condition of the U.S., Canadian and global economies;
•
the actions of certain foreign countries;
•
the price and quantity of imports of foreign oil and natural gas;
•
political conditions, including embargoes, war or civil unrest in or affecting other oil producing activities of certain countries;
•
the level of global oil and natural gas exploration and production activity;
•
the level of global oil and natural gas inventories;
•
production or pricing decisions made by the Organization of Petroleum Exporting Countries, or OPEC;
•
weather conditions;
•
technological advances affecting energy consumption; and
•
the price and availability of alternative fuels.
Lower oil and natural gas prices may not only decrease our revenues on a per-unit basis, but also may reduce the amount of oil and natural gas that we can produce economically in the future. Higher operating costs associated with any of our oil or natural gas fields will make our profitability more sensitive to oil or natural gas price declines. A sustained decline in oil or natural gas prices may materially and adversely affect our future business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures.
Drilling for and producing oil and natural gas are high risk activities with many uncertainties that could adversely affect our business, financial condition and results of operations.
Our future success will depend on the success of our exploitation, exploration, development and production activities. Our oil and natural gas exploration and production activities are subject to numerous risks beyond our control, including the risk that drilling will not result in commercially viable oil or natural gas production. Our decisions to purchase, explore, develop or otherwise exploit prospects or properties will depend in part on the evaluation of data obtained through geophysical and geological analysis, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations. Our costs of drilling, completing and operating wells are often uncertain before drilling commences. Overruns in budgeted expenditures are common risks that can make a particular project uneconomical. Further, our future business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures could be materially and adversely affected by any factor that may curtail, delay or cancel drilling, including the following:
•
delays imposed by or resulting from compliance with regulatory requirements;
•
unusual or unexpected geological formations;
•
pressure or irregularities in geological formations;
•
shortages of or delays in obtaining equipment and qualified personnel;
•
equipment malfunctions, failures or accidents;
•
unexpected operational events and drilling conditions;
•
pipe or cement failures;
•
casing collapses;
•
lost or damaged oilfield drilling and service tools;
•
loss of drilling fluid circulation;
•
uncontrollable flows of oil, natural gas and fluids;
•
fires and natural disasters;
•
environmental hazards, such as natural gas leaks, oil spills, pipeline ruptures and discharges of toxic gases;
•
adverse weather conditions;
•
reductions in oil and natural gas prices;
•
oil and natural gas property title problems; and
•
market limitations for oil and natural gas.
If any of these factors were to occur with respect to a particular field, we could lose all or a part of our investment in the field, or we could fail to realize the expected benefits from the field, either of which could materially and adversely affect our revenue and profitability.
Prospects that we decide to drill may not yield oil or natural gas in commercially viable quantities.
Our prospects are in various stages of evaluation and development. There is no way to predict with certainty in advance of drilling and testing whether any particular prospect will yield oil or natural gas in sufficient quantities to recover drilling or completion costs or to be economically viable, particularly in light of the current economic environment. The use of seismic data and other technologies, and the study of producing fields in the same area, will not enable us to know conclusively before drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in commercially viable quantities. Moreover, the analogies we draw from available data from other wells, more fully explored prospects or producing fields may not be applicable to our drilling prospects.
We have limited or relatively limited experience in drilling wells to the Marcellus Shale, Utica Shale and Bakken Shale/Three Forks Sanish formations and limited information regarding reserves and decline rates in these areas. Wells drilled to these areas are more expensive and more susceptible to mechanical problems in drilling and completion techniques than wells in conventional areas.
We have limited or relatively limited experience in the drilling and completion of Marcellus Shale, Utica Shale, and Bakken Shale/Three Forks Sanish formation wells, including limited horizontal drilling and completion experience. Other operators in these plays may have significantly more experience in the drilling and completion of these wells, including the drilling and completion of horizontal wells. In addition, we have limited information with respect to the ultimate recoverable reserves and production decline rates in these areas due to their limited histories. The wells drilled in Marcellus Shale, Utica Shale and Bakken Shale/Three Forks Sanish formations are primarily horizontal and require more artificial stimulation, which makes them more expensive to drill and complete. The wells also are more susceptible to mechanical problems associated with the drilling and completion of the wells, such as casing collapse and lost equipment in the wellbore due to the length of the lateral portions of these unconventional wells. The fracturing of these formations will be more extensive and complicated than fracturing geological formations in conventional areas of operation.
Our core properties are geographically concentrated, making us disproportionately vulnerable to risks associated with operating in our core areas of operation.
Our core properties are geographically concentrated. As of January 31, 2014, our core oil and natural gas reserves and operations are primarily located in West Virginia, Ohio and North Dakota. As a result of this concentration, we may be disproportionately exposed to the impact of events or circumstances in these areas such as regional supply and demand factors, delays or interruptions
of production from wells caused by governmental regulation, gathering, processing or transportation capacity constraints, market limitations, or interruption of the gathering, processing or transportation of oil, natural gas or natural gas liquids.
Our estimated proved reserves are based on many assumptions that may turn out to be inaccurate. Any significant inaccuracies in these reserve estimates or underlying assumptions may materially affect the quantities and present value of our reserves.
Estimates of oil and natural gas reserves are inherently imprecise. The process of estimating oil and natural gas reserves is complex. It requires interpretations of available technical data and many assumptions, including assumptions relating to economic factors. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present value of reserves. To prepare our proved reserve estimates, we must project production rates and the timing of development expenditures. We must also analyze available geological, geophysical, production and engineering data. The extent, quality and reliability of this data can vary. The process also requires economic assumptions about matters such as oil, natural gas and natural gas liquids prices, drilling and operating expenses, capital expenditures, taxes and availability of funds.
Actual future production, oil, natural gas and natural gas liquids prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves most likely will vary from our estimates. Any significant variance could materially affect the estimated quantities and present value of our reserves. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil, natural gas and natural gas liquids prices and other factors, many of which are beyond our control.
The present value of future net revenues from our proved reserves will not necessarily be the same as the current market value of our estimated oil and natural gas reserves.
You should not assume that the present value of future net revenues from our proved reserves is the current market value of our estimated oil and natural gas reserves. As required by SEC rules and regulations, we based the estimated discounted future net revenues from proved reserves as of December 31, 2013 on the unweighted arithmetic average of the first-day-of-the-month price for the preceding twelve months without giving effect to derivative transactions as well as operating and development costs being incurred at the end of the reporting period. Consequently, it may not reflect the prices ordinarily received or that will be received for oil and gas production because of seasonal price fluctuations or other varying market conditions, nor may it reflect the actual costs that will be required to produce or develop the oil and gas properties. Accordingly, estimates included herein of future net cash flows may be materially different from the future net cash flows that are ultimately received. In addition, the ten percent discount factor, which is required by the SEC to be used in calculating discounted future net cash flows for reporting purposes, may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and gas industry in general. Therefore, the estimates of discounted future net cash flows, Standardized Measure or PV-10 in this report should not be construed as accurate estimates of the current market value of our proved reserves. Actual future net revenues from our oil and natural gas properties will be affected by factors such as:
•
actual prices we receive for oil and natural gas;
•
actual cost of development and production expenditures;
•
the amount and timing of actual production; and
•
changes in governmental regulations or taxation.
Actual future prices and costs may differ materially from those used in the present value estimates included in this annual report.
Unless we replace our oil and natural gas reserves, our reserves and production will decline, which would adversely affect our business, financial condition and results of operations.
Producing oil and natural gas reservoirs generally are characterized by declining production rates that vary depending on reservoir characteristics and other factors. Our future oil and natural gas reserves and production, and therefore our cash flow and income, are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves. We may not be able to develop, find or acquire additional reserves to replace our current and future production at acceptable costs, which would adversely affect our business, financial condition and results of operations.
Our exploration, development and midstream operations require substantial capital, and we may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a loss of properties and a decline in our oil and natural gas reserves.
The oil and natural gas industry is very capital intensive. We make and expect to continue to make substantial capital expenditures in our business and operations for the exploration for, and development, production, gathering, processing and acquisition of, oil and natural gas reserves and production. To date, we have financed capital expenditures primarily with proceeds from bank borrowings, cash generated by operations, proceeds from non-core asset sales and proceeds from public (including "at-the-market", or ATM) offerings of our preferred stock, private offerings in 2012 of our senior notes, the private equity commitment relating to our midstream operations and, to a lesser extent, public (including years-past ATM) offerings of our common stock. However, as a result of our late SEC filings in the first half of 2013, we are unable to conduct ATM offerings of our equity securities, until we again become eligible
to use the SEC's short-form registration statement on Form S-3, and our ability to access the capital markets is therefore currently restricted.
We intend to finance our future capital expenditures with a combination of internally-generated cash flow, capital market related funding, anticipated borrowing capacity under our revolving credit facility associated with anticipated borrowing base increases, anticipated borrowings under Eureka Hunter Pipeline’s two existing credit facilities (or under an expected new senior secured credit facility for Eureka Hunter Pipeline, currently being negotiated, that would replace the two existing credit facilities) and proceeds from non-core asset sales. However, our cash flow from operations and access to capital is subject to a number of variables, including:
•
our proved reserves;
•
the amount of oil and natural gas we are able to produce from our wells;
•
the prices at which oil, natural gas and natural gas liquids are sold;
•
our ability to acquire, locate and produce new reserves; and
•
our ability to obtain commitments from third-party producers for the gathering of their natural gas production through our Eureka Hunter Gas Gathering System and for the treating of their natural gas production by our natural gas treating operations.
If our revenues decrease as a result of lower oil and natural gas prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels. We may need to seek additional financing in the future. The issuance of additional debt may require that a portion of our cash flows provided by operating activities be used for the payment of principal and interest on our debt, thereby reducing our ability to use cash flows to fund working capital, capital expenditures and acquisitions. The issuance of additional equity securities could have a dilutive effect on the value of our common stock. In addition, we may not be able to obtain debt or equity financing on terms favorable to us, or at all, depending on market conditions. The failure to obtain additional financing could result in a curtailment of our operations relating to exploration and development of our prospects, which in turn could lead to a possible loss of properties and a decline in our oil and natural gas reserves, or could prevent us from expanding, maintaining and operating our pipeline facilities.
Our indebtedness could adversely affect our financial condition and our ability to operate our business.
As of January 31, 2014, our total outstanding indebtedness was approximately $898.9 million. This indebtedness consisted primarily of borrowings under our revolving credit facility, our senior notes and borrowings under Eureka Hunter Pipeline’s term loan credit facility. Our principal debt facilities are described under the “Management’s Discussion and Analysis of Financial Condition and Results of Operations” section of this annual report.
We expect to incur additional debt from time to time, and such borrowings may be substantial. Our debt could have material adverse consequences to us, including the following:
•
it may be difficult for us to satisfy our obligations, including debt service requirements under our credit and other debt agreements;
•
our ability to obtain additional financing for working capital, capital expenditures, debt service requirements and other general corporate purposes may be impaired;
•
a significant portion of our cash flow is committed to payments on our debt, which will reduce the funds available to us for other purposes, such as future capital expenditures, acquisitions and general working capital;
•
we are more vulnerable to price fluctuations and to economic downturns and adverse industry conditions and our flexibility to plan for, or react to, changes in our business or industry is more limited; and
•
our ability to capitalize on business opportunities, and to react to competitive pressures, as compared to others in our industry, may be limited.
Our failure to service any such debt or to comply with the applicable debt covenants could result in a default under the related debt agreement, and under any other debt agreement or any commodity derivative contract under which such default is a cross-default, which could result in the acceleration of the payment of such debt, termination of the lenders' commitments to make further loans to us, loss of our ownership interests in the secured properties, early termination of the commodity derivative contract (and an early termination payment obligation) and/or otherwise materially adversely affect our business, financial condition and results of operations.
Restrictive covenants in our credit facilities and the indenture governing our senior notes may restrict our ability to finance future operations or capital needs, or to engage in, expand or pursue our business strategies.
The credit agreement governing our revolving credit facility and the indenture governing our senior notes contain certain covenants that, among other things, restrict our ability to, with certain exceptions:
•
incur indebtedness and issue preferred stock;
•
grant liens on our assets;
•
make certain restricted payments, including payment of dividends on our outstanding common and preferred stock;
•
change the nature of our business;
•
acquire or make expenditures for oil and gas properties outside of the U.S. and Canada;
•
acquire certain assets or businesses or make certain asset sales;
•
dispose of all or substantially all our assets or enter into mergers, consolidations or similar transactions;
•
make investments, loans or advances;
•
enter into transactions with affiliates;
•
create new subsidiaries; and
•
enter into certain derivatives transactions.
The credit agreement governing our revolving credit facility also requires us to satisfy certain financial covenants, including maintaining:
(i) a ratio of consolidated current assets to consolidated current liabilities of not less than 1.0 to 1.0 as of the last day of any fiscal quarter (which 1.0 to 1.0 financial covenant ratio was waived for the quarter ended December 31, 2013, as a result of our compliance with a less restrictive ratio for that quarter);
(ii) a ratio of EBITDAX (as defined in the Credit Agreement) for the trailing four fiscal quarter period then ended to Interest Expense (as defined in the Credit Agreement) for such period of not less than (A) 2.00 to 1.00 for the fiscal quarter ending December 31, 2013, (B) 2.25 to 1.00 for the fiscal quarter ending March 31, 2014 and (C) 2.50 to 1.00 for the fiscal quarter ending June 30, 2014 and for each fiscal quarter ending thereafter; provided that solely for calculating such ratio for the fiscal quarter ending December 31, 2013, EBITDAX and Interest Expense for that fiscal quarter shall be calculated on an actual basis without giving effect to any pro forma adjustments;
(iii) beginning with the fiscal quarter ending June 30, 2014, a ratio of total debt to EBITDAX for the trailing four fiscal quarter period then ended of not more than (A) 4.50 to 1.0 for the fiscal quarters ending June 30, 2014 and September 30, 2014 and (B) 4.25 to 1.0 for the fiscal quarter ending December 31, 2014 and for each fiscal quarter ending thereafter; and
(iv) as of the last day of any fiscal quarter period ending through March 31, 2014, a ratio of total debt (less the outstanding principal amount of the Company’s 9.750% Senior Notes due 2020) to EBITDAX for the trailing four fiscal quarter period then ended of not more than 2.00 to 1.00.
Eureka Hunter Pipeline’s revolving and term loan credit facilities also require Eureka Hunter Pipeline and its subsidiaries to comply with certain covenants, including financial covenants.
Our compliance with these provisions may affect our ability to react to changes in market or industry conditions, take advantage of business opportunities we believe to be desirable, obtain future financing, fund needed capital expenditures for exploration and development, finance acquisitions, equipment purchases and other expenditures, or withstand a future downturn in our business. Our ability to comply with these covenants may be affected by events beyond our control, and any material deviations from our forecasts could require us to seek waivers or amendments of covenants or alternative sources of financing or reduce our expenditures. We cannot assure you that such waivers, amendments or alternative financings could be obtained or, if obtainable or obtained, would be on terms acceptable or favorable to us. If market, industry or other economic conditions deteriorate, our ability to comply with these covenants may be impaired.
Our principal debt agreements are described under the “Management’s Discussion and Analysis of Financial Condition and Results of Operations” section of this annual report.
Failure to remediate certain previously reported weaknesses in our internal controls could adversely affect our ability to obtain borrowings and raise capital.
The Company reported fourteen material weaknesses in our internal controls as of December 31, 2012. During 2013, due to significant remediation efforts made by management, the number of material weaknesses has been reduced to three. We are working to remediate the remaining three material weaknesses, which are (1) the Company did not maintain effective controls over the intraperiod allocation of income taxes; (2) the Company did not maintain effective controls over timely preparation and review of account reconciliations; and (3) as a result of the aggregation of deficiencies, the Company determined that it did not maintain effective controls over property accounting with respect to the accuracy and completeness of property records and related information. We have implemented, and will continue to implement, measures we believe have effectively addressed, or will effectively address, all our previously reported material weaknesses, including the remaining weaknesses. However, despite our remediation efforts, any failure to adequately
address any of these weaknesses, or other potential weaknesses, could adversely affect the accuracy of our financial statements, our compliance with our reporting obligations under the Exchange Act and our compliance with our debt covenants, and therefore our ability to obtain borrowings and access the capital markets to provide required liquidity.
Our failure to timely file certain periodic reports with the SEC limits our access to the public markets to raise debt or equity capital.
We did not file within the time frame required by the SEC our annual report on Form 10-K for the year ended December 31, 2012 , our quarterly report on Form 10-Q for the quarter ended March 31, 2013 and certain pro forma financial information regarding our April 2013 Eagle Ford properties sale (as part of the Form 8-K we filed with the SEC on April 30, 2013 reporting the sale). We became current with our SEC reporting obligations on July 12, 2013; however, until twelve months after the date on which we became current, we will be ineligible to use abbreviated and less costly SEC filings, such as the SEC’s Form S-3 registration statement, to register our securities for sale. Further, during such period, we will be unable to use our existing shelf registration statement on Form S-3 or conduct “at-the-market”, or ATM, offerings of our equity securities, which ATM offerings we had conducted on a regular basis with respect to our preferred stock prior to our late SEC filings. We may use Form S-1 to register a sale of our securities to raise capital or complete acquisitions, but doing so would likely increase transaction costs and adversely impact our ability to raise capital or complete acquisitions in an expeditious manner. Therefore, because of our late SEC filings, we may be limited in our ability to access the public markets to raise debt or equity capital, which could prevent us from pursuing transactions or implementing business strategies that would be beneficial to our business.
A pending SEC investigation and pending stockholder litigation may divert the attention of management and other important resources, may expose us to negative publicity and could have a material adverse effect on our business, financial condition, results of operations and cash flows.
As further described in “Item 3. Legal Proceedings,” on April 26, 2013, we were advised by the staff of the SEC Enforcement Division that the SEC had commenced an inquiry into matters disclosed in certain of our SEC filings and press releases, as well as the sufficiency of our internal controls and our decisions to change auditors from Hein & Associates LLP to PricewaterhouseCoopers LLP, or PwC, and from PwC to BDO USA, LLP, among other matters. This investigation is ongoing and we are cooperating with the SEC in connection with these matters. We may incur significant professional fees and other costs in responding to the SEC investigation. If the SEC were to conclude that enforcement action is appropriate, we could be required to pay substantial civil penalties and fines. The SEC also could impose other sanctions against us or certain of our current and/or former directors and officers. Any of these events could have a material adverse effect on our business, financial condition, results of operations or cash flows. Further, there is a risk that we may have to restate our historical consolidated financial statements, amend prior filings with the SEC or take other actions not currently contemplated in connection with the SEC investigation.
As also further described in “Item 3. Legal Proceedings,” several putative stockholders class action complaints and putative stockholders derivative complaints have been filed against us and/or certain of our directors and officers. The putative stockholder class action complaints have been consolidated into a single action pending in the Southern District of New York. All of the stockholder derivative cases filed to date have been dismissed, although it is possible that additional cases could be filed. We have incurred and may continue to incur significant professional fees and other costs defending the lawsuits. Depending on the outcome of these lawsuits, we could be required to pay one or more settlements or judgments, which could have a material adverse effect on our financial condition. In addition, our board of directors, management and employees may spend a substantial amount of time on pending litigation, diverting a significant amount of resources and attention that would otherwise be directed toward our operations and implementation of our business strategy, all of which could materially adversely affect our business, financial condition, results of operations or cash flows.
Our indemnification obligations and limitations of our directors' and officers' liability insurance may have a material adverse effect on our financial condition, results of operations and cash flows. Under Delaware law, our certificate of incorporation and bylaws and certain indemnification agreements to which we are a party, we have an obligation to indemnify, or we have otherwise agreed to indemnify, certain of our directors and officers with respect to current and future investigations and litigation, including the matters discussed in “Item 3. Legal Proceedings.” In connection with some of these pending matters, we are required to, or we have otherwise agreed to, advance legal fees and related expenses to certain of our directors and officers and expect to do so while these matters are pending. Certain of these obligations may not be “covered matters” under our directors' and officers' liability insurance, or there may be insufficient coverage available. Further, in the event the directors and officers are ultimately determined to not be entitled to indemnification, we may be unable to recover any amounts we previously advanced to them.
We cannot provide any assurances that the above-described pending claims, or claims yet to arise, will not exceed the limits of our insurance policies, that such claims are covered by the terms of our insurance policies or that our insurance carrier will be able to cover our claims. The insurers also may seek to deny or limit coverage in some or all of these matters. Furthermore, the insurers could become insolvent and be unable to fulfill their obligation to defend, pay or reimburse us for insured claims. Due to these coverage limitations, we may incur significant unreimbursed costs, including costs to satisfy our indemnification obligations, which may have a material adverse effect on our business, financial condition, results of operations or cash flows.
As a result of the outstanding SEC investigation and stockholder litigation, we have been the subject of negative publicity. We believe this negative publicity has adversely affected, and may continue to adversely affect, our stock price and may harm our reputation and our relationships with current and future investors, lenders, customers, suppliers, business partners and employees. As a result, our business, financial condition, results of operations or cash flows may be materially adversely affected.
A prolonged credit crisis would likely materially affect our liquidity, business and financial condition that we cannot predict.
Liquidity is essential to our business. Our liquidity could be substantially negatively affected by an inability to obtain capital in the long-term or short-term debt or equity capital markets or an inability to access bank financing. A prolonged credit crisis, such as the 2008-2009 financial crisis, and related turmoil in the global financial system would likely materially affect our liquidity, business and financial condition. The economic situation could also adversely affect the collectability of our trade receivables or performance by our suppliers and cause our commodity hedging arrangements to be ineffective if our counterparties are unable to perform their obligations or seek bankruptcy protection.
Future economic conditions in the United States, Canada and global markets may have a material adverse impact on our business and financial condition that we currently cannot predict.
The United States, Canadian and other world economies are slowly recovering from the economic recession that began in 2008. While economic growth has resumed, it remains modest and the timing of an economic recovery is uncertain. There are likely to be significant long-term effects resulting from the recession and credit market crisis, including a future global economic growth rate that is slower than what was experienced in the years preceding the recession. Unemployment rates remain very high and businesses and consumer confidence levels have not yet fully recovered to pre-recession levels. In addition, more volatility may occur before a sustainable, yet lower, growth rate is achieved. Global economic growth drives demand for energy from all sources, including for oil and natural gas. A lower future economic growth rate will result in decreased demand for our crude oil and natural gas production as well as lower commodity prices, which will reduce our cash flows from operations and our profitability.
If our access to oil and gas markets is restricted, it could negatively impact our production, our income and ultimately our ability to retain our leases. Our ability to sell natural gas and/or receive market prices for our natural gas may be adversely affected by pipeline gathering and transportation system capacity constraints.
Market conditions or the restriction in the availability of satisfactory oil and natural gas transportation arrangements may hinder our access to oil and natural gas markets or delay our production. The availability of a ready market for our oil and natural gas production depends on a number of factors, including the demand for and supply of oil and natural gas and the proximity of reserves to transportation infrastructure. Our ability to market our production depends in substantial part on the availability and capacity of pipeline gathering and transportation systems, processing facilities, terminals and rail and truck transportation owned and operated by third parties. Our failure to obtain such services on acceptable terms could materially harm our business. Our productive properties may be located in areas with limited or no access to pipelines, thereby necessitating delivery by other means, such as trucking, or requiring compression facilities. Such restrictions on our ability to sell our oil or natural gas may have several adverse effects, including higher transportation costs, fewer potential purchasers (thereby potentially resulting in a lower selling price) or, in the event we were unable to market and sustain production from a particular lease for an extended time, possibly causing us to lose a lease due to lack of production.
The amount of oil and natural gas being produced by us and others could exceed the capacity of the various gathering and intrastate or interstate transportation pipelines currently available in these areas. If this occurs, it will be necessary for new pipelines and gathering systems to be built. Because of the current economic climate, certain pipeline projects that are or may be planned for the Marcellus Shale, Utica Shale and Bakken Shale areas may not occur for lack of financing. In addition, capital constraints could limit our ability to build or expand gathering systems, such as our Eureka Hunter Gas Gathering System, necessary to gather our gas to deliver to interstate pipelines. In such event, we might have to shut in our wells awaiting a pipeline connection or capacity and/or sell natural gas production at significantly lower prices than those quoted on NYMEX or than we currently project for these specific regions, which would adversely affect our results of operations.
A portion of our natural gas and oil production in any region may be interrupted, or shut in, from time to time for numerous reasons, including as a result of weather conditions, accidents, loss of pipeline or gathering system access, field labor issues or strikes, or we might voluntarily curtail production in response to market conditions. If a substantial amount of our production is interrupted at the same time, it could temporarily adversely affect our cash flow.
We depend on a relatively small number of purchasers for a substantial portion of our revenue. The inability of one or more of our purchasers to meet their obligations may adversely affect our financial results.
We derive a significant amount of our revenue from a relatively small number of purchasers of our production. Our inability to continue to provide services to key customers, if not offset by additional sales to our other customers, could adversely affect our financial condition and results of operations. These companies may not provide the same level of our revenue in the future for a variety of reasons, including their lack of funding, a strategic shift on their part in moving to different geographic areas in which we do not operate or our failure to meet their performance criteria. The loss of all or a significant part of this revenue would adversely affect our financial condition and results of operations.
Shortages of equipment, services and qualified personnel could reduce our cash flow and adversely affect results of operations.
The demand for qualified and experienced field personnel to drill wells and conduct field operations, geologists, geophysicists, engineers, pipeline operators, oil and natural gas marketers and other professionals in the oil and natural gas industry can fluctuate significantly, often in correlation with oil and natural gas prices and activity levels in certain regions where we are active, causing periodic shortages. During periods of high oil and gas prices, we have experienced shortages of equipment, including drilling rigs and completion equipment, as demand for rigs and equipment has increased along with higher commodity prices and increased activity levels. In addition, there is currently a shortage of hydraulic fracturing and wastewater disposal capacity in many of the areas in which we operate. Higher oil and natural gas prices generally stimulate increased demand and result in increased prices for drilling rigs, crews and associated supplies, oilfield equipment and services, pipe and other midstream services equipment and qualified personnel in exploration, production and midstream operations. These types of shortages or price increases could significantly decrease our profit margin, cash flow and operating results and/or restrict or delay our ability to drill wells, construct gathering pipelines and conduct other operations that we currently have planned or budgeted, causing us to miss our forecasts and projections.
We are dependent upon contractor, consultant and partnering arrangements.
We had a total of approximately 445 full-time employees as of January 31, 2014. Despite this number of employees, we expect that we will continue to require the services of independent contractors and consultants to perform various services, including professional services such as reservoir engineering, land, legal, environmental, accounting and tax services. We will also pursue alliances with partners in the areas of geological and geophysical services and prospect generation, evaluation and leasing. Our dependence on contractors, consultants and third-party service providers creates a number of risks, including but not limited to the possibility that such third parties may not be available to us as and when needed, and the risk that we may not be able to properly control the timing and quality of work conducted with respect to our projects.
If we experience significant delays in obtaining the services of such third parties or poor performance by such parties, our results of operations could be materially adversely affected.
Our business may suffer if we lose key personnel.
Our operations depend on the continuing efforts of our executive officers, including specifically Gary C. Evans, our chairman and chief executive officer, and other senior management. Our business or prospects could be adversely affected if any of these persons do not continue in their management role with us and we are unable to attract and retain qualified replacements. Additionally, we do not presently carry key person life insurance for any of our executive officers or senior management.
We cannot control activities on properties that we do not operate and so are unable to control their proper operation and profitability.
We do not operate all the properties in which we have an ownership interest. As a result, we have limited ability to exercise influence over, and control the risks associated with, the operations of these non-operated properties. The failure of an operator of our wells to adequately perform operations, an operator’s breach of the applicable agreements or an operator’s failure to act in ways that are in our best interests could reduce our production, revenues and reserves. The success and timing of our drilling and development activities on properties operated by others therefore depend upon a number of factors outside of our control, including:
•
the nature and timing of the operator’s drilling and other activities;
•
the timing and amount of required capital expenditures;
•
the operator’s geological and engineering expertise and financial resources;
•
the approval of other participants in drilling wells; and
•
the operator’s selection of suitable technology.
Competition in the oil and natural gas industry is intense, which may adversely affect our ability to compete.
We operate in a highly competitive environment for acquiring properties, exploiting mineral leases, marketing oil and natural gas, treating and gathering third-party natural gas production and securing trained personnel. Many of our competitors possess and employ financial, technical and personnel resources substantially greater than ours, which can be particularly important in the areas in which we operate. Those companies may be able to pay more for productive oil and natural gas properties and exploratory prospects, evaluate, bid for and purchase a greater number of properties and prospects and establish and maintain more diversified and expansive midstream services than our financial or personnel resources permit. Our ability to acquire additional prospects and to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in an efficient manner even in a highly competitive environment. We may not be able to compete successfully in the future in acquiring prospective reserves, developing reserves, marketing hydrocarbons, offering midstream services, attracting and retaining quality personnel and raising additional capital.
The use of geoscience, petro-physical and engineering analyses and other technical or operating data to evaluate drilling prospects is uncertain and does not guarantee drilling success or recovery of economically producible reserves.
Our decisions to explore, develop and acquire prospects or properties targeting the Marcellus Shale, Utica Shale and Bakken Shale depend on data obtained through geoscientific, petro-physical and engineering analyses, the results of which can be uncertain. Even when properly used and interpreted, data from whole cores, regional well log analyses and 2-D and 3-D seismic only assist our technical team in identifying hydrocarbon indicators and subsurface structures and estimating hydrocarbons in place. They do not allow us to know conclusively the amount of hydrocarbons in place and if those hydrocarbons are producible economically. In addition, the use of advanced drilling and completion technologies for the development of our unconventional resources, such as horizontal drilling and multi-stage fracture stimulations, requires greater expenditures than traditional development drilling strategies. Our ability to commercially recover and produce the hydrocarbons that we believe are in place and attributable to our properties will depend on the effective use of advanced drilling and completion techniques, the scope of our drilling program (which will be directly affected by the availability of capital), drilling and production costs, availability of drilling and completion services and equipment, drilling results, lease expirations, regulatory approval and geological and mechanical factors affecting recovery rates. Our estimates of unproved reserves, estimated ultimate recoveries per well, hydrocarbons in place and resource potential may change significantly as development of our oil and gas assets provides additional data.
We rely on information technology and any failure, inadequacy, interruption or security lapse of that technology could harm our ability to effectively operate our business.
In the ordinary course of our business, we use information technology to maintain, analyze and process, to varying degrees, our property information, reserve data, operating records (including amounts paid or payable to suppliers, working interest owners, royalty holders and others), drilling partnership records (including amounts paid or payable to limited partners and others), gas gathering, processing and transmission records, oil and gas marketing records and general accounting, legal, tax, corporate and similar records. The secure maintenance of this information is critical to our business. Our ability to conduct our business may be impaired if our information technology resources fail or are compromised or damaged, whether due to a virus, intentional penetration or disruption by a third party, hardware or software corruption or failure or error, service provider error or failure, natural disaster, intentional or unintentional personnel actions or other causes. A significant disruption in the functioning of these resources could adversely impact our ability to access, analyze and process information, conduct operations in a normal and efficient manner and timely and accurately manage our accounts receivable and accounts payable, among other business processes, which could disrupt our operations, adversely affect our reputation and require us to incur significant expense to address and remediate or otherwise resolve these kinds of issues. The release of confidential business information also may subject us to liability, which could expose us to significant expense and have a material adverse effect on our financial results, stock price and reputation. Portions of our information technology infrastructure also may experience interruptions, delays, cessations of service or errors in connection with systems integration or migration work that takes place from time to time. We may not be successful in implementing new systems and transitioning data, which could cause business disruptions, result in increased expenses and divert the attention of management and key information technology resources.
New technologies may cause our current exploration, development and drilling methods to become obsolete.
The oil and gas industry is subject to rapid and significant advancements in technology, including the introduction of new products and services using new technologies. As competitors use or develop new technologies, we may be placed at a competitive disadvantage, and competitive pressures may force us to implement new technologies at a substantial cost. In addition, competitors may have greater financial, technical and personnel resources that allow them to enjoy technological advantages and may in the future allow them to implement new technologies before we can. One or more of the technologies that we currently use or that we may implement in the future may become obsolete. We cannot be certain that we will be able to implement new technologies on a timely basis or at a cost that is acceptable to us. If we are unable to maintain technological advancements consistent with industry standards, our operations and financial condition may be adversely affected.
NGAS conducted part of its operations through private drilling partnerships, and, following our acquisition of NGAS in April 2011, we sponsored two private drilling partnerships, which subject us to additional risks that could have a material adverse effect on our financial position and results of operations.
NGAS conducted a portion of its operations through private drilling partnerships with third parties. Following our acquisition of NGAS, we, as sponsor, completed two private drilling partnerships. Under our partnership structure, proceeds from the private placement of interests in each investment partnership, together with the sponsor’s capital contribution, are contributed to a separate joint venture or “program” that the sponsor forms with that partnership to conduct drilling or property operations. These NGAS historical drilling partnerships and our sponsored drilling partnerships expose us to additional risks that could negatively affect our financial condition and results of operations. These additional risks include risks relating to regulatory requirements relating to the sale of interests in the investment partnerships, risks relating to the governmental regulation of Energy Hunter Securities, Inc., our wholly-owned broker-dealer subsidiary, risks relating to potential challenges to tax positions taken by the investment partnerships, risks relating to disagreements with partners in the investment partnerships and risks relating to our general liability , in our capacity as general partner of the investment partnerships and program partnerships.
We may incur substantial losses and be subject to substantial liability claims as a result of our oil and natural gas operations, and we may not have enough insurance to cover all of the risks that we may ultimately face.
We maintain insurance coverage against some, but not all, potential losses to protect against the risks we foresee. For example, we maintain (1) comprehensive general liability insurance, (2) employer’s liability and workers' compensation insurance, (3) automobile liability insurance, (4) environmental insurance, (5) property insurance, (6) directors' and officers' insurance, (7) control of well insurance, (8) pollution insurance and (9) umbrella/excess liability insurance. We do not carry business interruption insurance. We may elect not to carry, or may cease to carry, certain types or amounts of insurance if our management believes that the cost of available insurance is excessive relative to the risks presented. In addition, it is not possible to insure fully against pollution and environmental risks.
We are not insured against all risks. Losses and liabilities arising from uninsured and under insured events could materially and adversely affect our business, financial condition, results of operations and cash flows. Our oil and natural gas exploration and production activities are subject to all of the operating risks associated with drilling for and producing oil and natural gas, including the possibility of:
•
environmental hazards, such as uncontrollable flows of oil, natural gas, brine, well fluids, toxic gas or other pollution into the environment, including groundwater and shoreline contamination;
•
abnormally pressured formations;
•
mechanical difficulties, such as stuck oil field drilling and service tools and casing collapses;
•
fires and explosions;
•
personal injuries and death; and
•
natural disasters.
Our midstream activities are subject to all of the operating risks associated with constructing, operating and maintaining pipelines and related equipment and natural gas treating equipment, including the possibility of pipeline leaks, breaks and ruptures, pipeline damage due to natural hazards, such as ground movement and weather, equipment failures, explosions, fires, accidents and personal injuries and death.
Any of these risks could adversely affect our ability to conduct operations or result in substantial losses to us. If a significant accident or other event occurs and is not fully covered by insurance, then that accident or other event could adversely affect our business, financial condition, results of operations and cash flows.
We may incur losses as a result of title deficiencies.
We purchase and acquire from third parties or directly from the mineral fee owners certain oil and gas leasehold interests and other real property interests upon which we will perform our drilling and exploration activities. The existence of a title deficiency can significantly devalue an acquired interest or render a lease worthless and can adversely affect our results of operations and financial condition. As is customary in the oil and gas industry, we generally rely upon the judgment of oil and gas lease brokers or internal or independent landmen who perform the field work in examining records in the appropriate governmental offices and abstract facilities before attempting to acquire or place under lease a specific mineral interest and before drilling a well on a leased tract. The failure of title may not be discovered until after a well is drilled, in which case we may lose the lease and the right to produce all or a portion of the minerals under the property.
Product price derivative contracts may expose us to potential financial loss.
To reduce our exposure to fluctuations in the prices of oil and natural gas, we currently and will likely continue to enter into derivative contracts to economically hedge a portion of our oil and natural gas production. Derivative contracts expose us to risk of financial loss in some circumstances, including when:
•
production is less than expected;
•
the counterparty to the derivative contract defaults on its contract obligations; or
•
there is a change in the expected differential between the underlying price in the derivative contract and actual prices received.
In addition, these derivative contracts may limit the benefit we would receive from increases in the prices for oil and natural gas. Under the terms of our revolving credit facility, the percentage of our total production volumes with respect to which we are allowed to enter into derivative contracts is limited, and we therefore retain the risk of a price decrease for our remaining production volumes.
Also, our failure to service our debt or to comply with our debt covenants could result in a default under the applicable debt agreement, and therefore a default under any of our derivative contracts under which such debt default is a cross-default, which could result in
the early termination of the derivative contracts (and early termination payment obligations) and/or otherwise materially adversely affect our business, financial condition and results of operations.
Information as to our derivatives activities is set forth under "Management's Discussion and Analysis of Financial Condition and Results of Operations-Critical Accounting Policies and Estimates-Derivative Instruments and Commodity Derivative Activities", "Item 7A. Quantitative and Qualitative Disclosures About Market Risk", and in the notes to our financial statements.
Write-downs of the carrying values of our oil and natural gas properties could occur if oil and gas prices decline or if we have substantial downward adjustments to our estimated proved reserves, increases in our estimates of development costs or deterioration in our drilling results. Because our properties currently serve, and will likely continue to serve, as collateral for advances under our existing and future credit facilities, a write-down in the carrying values of our properties could require us to repay debt earlier than we would otherwise be required. It is likely that the cumulative effect of a write-down could also negatively impact the value of our securities, including our common and preferred stock and our notes.
We account for our crude oil and natural gas exploration and development activities using the successful efforts method of accounting. Under this method, costs of productive exploratory wells, developmental dry holes and productive wells and undeveloped leases are capitalized. Oil and gas lease acquisition costs are also capitalized. Exploration costs, including personnel costs, certain geological and geophysical expenses and delay rentals for oil and gas leases, are charged to expense as incurred. Exploratory drilling costs are initially capitalized, but charged to expense if and when the well is determined not to have found reserves in commercial quantities.
The application of the successful efforts method of accounting requires managerial judgment to determine the proper classification of wells designated as developmental or exploratory, which will ultimately determine the proper accounting treatment of the costs incurred. The results from a drilling operation can take considerable time to analyze and the determination that commercial reserves have been discovered requires both judgment and industry experience. Wells may be completed that are assumed to be productive but may actually deliver oil and gas in quantities insufficient to be economic, which may result in the abandonment of the wells at a later date. Future wells are drilled that target geological structures that are both developmental and exploratory in nature. A subsequent allocation of costs is then required to properly account for the results. The evaluation of oil and gas leasehold acquisition costs requires judgment to estimate the fair value of these costs with reference to drilling activity in a given area.
The capitalized costs of our oil and gas properties may not exceed the estimated future net cash flows from our properties. If capitalized costs exceed future cash flows, we write down the costs of the properties to our estimate of fair value. Any such charge will not affect our cash flow from operating activities, but will reduce our earnings and shareholders’ equity. When evaluating our properties, we are required to test for potential write-downs at the lowest level for which identifiable cash flows are largely independent of the cash flows of other assets, which is typically on a field by field basis.
During the year ended December 31, 2013, the Company recognized $115.5 million, including discontinued operations, in exploration expense which includes leasehold impairment and expiration expense related to leases in the Williston and Appalachian Basin regions. Additionally, we recorded proved impairments of $88.5 million, including discontinued operation, for the year ended December 31, 2013, due to changes in production estimates and lease operating costs indicating potential impairment of our Williston and Appalachian Basin proved properties, and the resulting provision for reduction to the carrying value of these properties to their estimated fair values.
We review our oil and gas properties for impairment annually or whenever events and circumstances indicate a decline in the recoverability of their carrying value. Once incurred, a write-down of oil and gas properties is not reversible at a later date even if oil or gas prices subsequently increase. Given the complexities associated with oil and gas reserve estimates and the history of price volatility in the oil and gas markets, events may arise that would require us to record further impairments of the book values associated with oil and gas properties. Accordingly, there is a risk that we will be required to further write down the carrying value of our oil and gas properties, which would reduce our earnings and shareholders’ equity.
Eureka Hunter Holdings has the right, subject to certain conditions, to obtain equity financing from Ridgeline Midstream Holdings, LLC, or Ridgeline, an affiliate of ArcLight Capital Partners, LLC, or ArcLight, but if the conditions to any future purchases of preferred units of Eureka Hunter Holdings in connection with the Ridgeline investment are not met, then Eureka Hunter Holdings will not be able to obtain additional funds from Ridgeline, which may adversely affect the operations of Eureka Hunter Pipeline and its subsidiaries.
Pursuant to the Series A Convertible Preferred Unit Purchase Agreement among Magnum Hunter, Eureka Hunter Holdings and Ridgeline, referred to as the Unit Purchase Agreement, Ridgeline committed, subject to certain conditions, to purchase up to $200 million of preferred units of Eureka Hunter Holdings. As of January 31, 2014, Eureka Hunter Holdings had sold preferred units to Ridgeline for an aggregate purchase price of $187.8 million, and, as permitted by the Amended and Restated Limited Liability Company Agreement of Eureka Hunter Holdings, referred to as the EHH Operating Agreement, had issued additional pay-in-kind preferred units to Ridgeline in lieu of approximately $11.9 million of cash distributions otherwise owed to Ridgeline in respect of its outstanding preferred units.
Eureka Hunter Holdings’ ability to obtain additional funds from Ridgeline is subject to the satisfaction of certain conditions to Ridgeline’s obligation to purchase preferred units as set forth in the Unit Purchase Agreement. These conditions include, among
others, that (1) the proceeds be used for certain approved capital expenditures, midstream growth projects and/or acquisitions (or for any other purposes agreed to by Ridgeline) and (2) no defaults or material adverse events have occurred. If these conditions are not met, then Eureka Hunter Holdings will not be able to obtain additional funds from Ridgeline. In such event, the business, financial condition and results of operations of Eureka Hunter Pipeline and its subsidiaries may be adversely affected.
There are restrictive covenants, mandatory distribution requirements and other provisions in the Ridgeline investment documents that may restrict our ability to pursue our business strategies with respect to our midstream operations.
The EHH Operating Agreement contains certain covenants that, among other things, restrict the ability of Eureka Hunter Holdings and its subsidiaries to, with certain exceptions:
•
incur funded indebtedness, whether direct or contingent;
•
issue additional equity interests;
•
pay distributions to its owners, or repurchase or redeem any of its equity securities;
•
make any material acquisitions, dispositions or divestitures; or
•
enter into a sale, merger, consolidation or other change of control transaction.
Under the EHH Operating Agreement, the holders of preferred units of Eureka Hunter Holdings are entitled to receive an annual distribution of 8%, payable quarterly. Through and including the quarter ended March 31, 2013, the board of directors of Eureka Hunter Holdings could elect to pay up to 75% of any such distribution in kind (i.e., in additional preferred units), in lieu of cash. For the quarter ending June 30, 2013 through and including the quarter ending March 31, 2014, the board of directors of Eureka Hunter Holdings may elect to pay up to 50% of any such distribution in kind. Thereafter, all distributions to Ridgeline relating to the preferred units will be paid solely in cash.
In addition to the required quarterly distributions of accrued preferred return on the preferred units, the EHH Operating Agreement also (1) gives Eureka Hunter Holdings the right, at any time on or after the fifth anniversary of the closing of the initial Ridgeline investment, to redeem all, but not less than all, of the outstanding preferred units, and (2) gives Ridgeline the right, at any time on or after the eighth anniversary of the closing of the initial Ridgeline investment, to require Eureka Hunter Holdings to redeem all, but not less than all, of the outstanding preferred units. If Eureka Hunter Holdings fails to meet its redemption obligations under clause (2) above, then Ridgeline will have the right to assume control of the board of directors of Eureka Hunter Holdings and, at its option, to cause Eureka Hunter Holdings and/or its other owners to enter into a sale, merger or other disposition of Eureka Hunter Holdings or its assets (on terms acceptable to Ridgeline).
Further, pursuant to the terms of the EHH Operating Agreement, the number and composition of the board of directors of Eureka Hunter Holdings may change over time based on Ridgeline’s percentage ownership interest in Eureka Hunter Holdings (after taking into account any additional purchases of preferred units) or the failure of Eureka Hunter Holdings to satisfy certain performance goals by the third anniversary of the closing of the initial Ridgeline investment (or as of any anniversary after such date). The board of directors of Eureka Hunter Holdings is currently composed of a majority of members appointed by Magnum Hunter. Subject to the rights described above, the board of directors of Eureka Hunter Holdings may in the future be composed of an equal number of directors appointed by Magnum Hunter and Ridgeline or, in certain cases, of a majority of directors appointed by Ridgeline.
The EHH Operating Agreement originally contained a requirement that Ridgeline have an exclusive first right to fund up to 100% of Eureka Hunter Holdings’ funding requirements, subject to certain exceptions. On March 7, 2013, Magnum Hunter and Ridgeline entered into an amendment to the EHH Operating Agreement which, among other things, provides Magnum Hunter a right to make additional capital contributions to Eureka Hunter Holdings in conjunction with or alongside additional capital contributions from Ridgeline. Accordingly, Magnum Hunter contributed $30 million to Eureka Hunter Holdings on March 7, 2013, followed by Ridgeline contributing $20 million during April 2013. Further, the agreement (as amended) provides that the next $70.5 million of additional capital contributions ($40.0 million of which had been paid as of January 31, 2014) must be made 60% by Magnum Hunter and 40% by Ridgeline in order for each party to maintain its existing ownership percentage interest in Eureka Hunter Holdings.
If a change of control of Magnum Hunter occurs at any time prior to a qualified public offering (as defined in the EHH Operating Agreement) of Eureka Hunter Holdings, Ridgeline will have the right under the terms of the EHH Operating Agreement to purchase sufficient additional preferred units in Eureka Hunter Holdings so that it holds up to 51.0% of the equity ownership of Eureka Hunter Holdings.
The EHH Operating Agreement also contains (1) preferred unit conversion rights in favor of Ridgeline, whereby it may convert its preferred units into common units of Eureka Hunter Holdings, (2) transfer restrictions on Magnum Hunter’s ownership interests in Eureka Hunter Holdings (subject to certain exceptions), (3) certain pre-emptive rights, rights of first refusal and co-sale rights in favor of Ridgeline and (4) certain Securities Act registration rights in favor of Ridgeline.
These restrictive covenants, mandatory distribution requirements and other provisions in the Ridgeline investment documents may restrict our ability to pursue our business strategies with respect to our midstream operations.
We are subject to complex federal, state, local and foreign laws and regulations, including environmental laws, which could adversely affect our business.
Exploration for and development, exploitation, production, processing, gathering, transportation and sale of oil and natural gas in the United States and Canada are subject to extensive federal, state, local and foreign laws and regulations, including complex tax laws and environmental laws and regulations. Existing laws or regulations, as currently interpreted or reinterpreted in the future, or future laws, regulations or incremental taxes and fees, could harm our business, results of operations and financial condition. We may be required to make large expenditures to comply with environmental and other governmental regulations. Energy Hunter Securities, Inc., one of our wholly-owned subsidiaries, is also subject to the rules and regulations promulgated by the Financial Industry Regulatory Authority in connection with its broker-dealer activities relating to our private drilling and/or income partnership programs.
Matters subject to regulation include oil and gas production and saltwater disposal operations and our processing, handling and disposal of hazardous materials, such as hydrocarbons and naturally occurring radioactive materials, discharge permits for drilling operations, spacing of wells, environmental protection and taxation. We could incur significant costs as a result of violations of or liabilities under environmental or other laws, including third-party claims for personal injuries and property damage, reclamation costs, remediation and clean-up costs resulting from oil spills and pipeline leaks and ruptures and discharges of hazardous materials, fines and sanctions, and other environmental damages.
Our Canadian operations subject us to foreign laws and regulations and additional operating risks, including currency fluctuations, which could impact our financial position and results of operations.
Our operations in Canada expose us to a foreign regulatory environment and risks from foreign operations. Some of these additional risks include, but are not limited to:
•
increases in governmental royalties;
•
application of new tax laws (including host-country export, excise and income taxes and U.S. taxes on foreign operations);
•
currency restrictions and exchange rate fluctuations;
•
legal and governmental regulatory requirements;
•
difficulties and costs of staffing and managing international operations; and
•
possible language and cultural differences.
Our Canadian operations also may be adversely affected by the laws and policies of the United States affecting foreign trade, taxation and investment. In addition, if a dispute arises with respect to our foreign operations, we may be subject to the exclusive jurisdiction of foreign courts or may not be successful in subjecting foreign persons to the jurisdiction of the courts of the United States.
Our current Eureka Hunter Gas Gathering System operations and the expected future expansion of these operations subject us to additional governmental regulations.
We are currently continuing the construction of our Eureka Hunter Gas Gathering System, which provides or is expected to provide gas gathering services primarily in support of our Company-owned properties as well as other upstream producers’ operations in West Virginia and Ohio. We have completed certain sections of the pipeline and anticipate further expansion of the pipeline in the future, which expansion will be determined by various factors, including the prospects for commitments for gathering services from third-party producers, the availability of gas processing facilities, obtainment of rights-of-way, securing regulatory and governmental approvals, resolving any land management issues, completion of pipeline construction and connecting the pipeline to the producing sources of natural gas.
The construction, operation and maintenance of the Eureka Hunter Gas Gathering System involve numerous regulatory, environmental, political and legal uncertainties beyond our control and require the expenditure of significant amounts of capital. There can be no assurance that our pipeline construction projects will be completed on schedule or at the budgeted cost, or at all. The operations of our gathering system are also subject to stringent and complex federal, state and local environmental laws and regulations. These laws and regulations can restrict or impact our business activities in many ways, including restricting the manner in which we dispose of substances, requiring remedial action to remove or mitigate contamination, and requiring capital expenditures to comply with control requirements. Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial requirements and the issuance of orders enjoining future operations. Certain environmental statutes impose strict, joint and several liability for costs required to clean up and restore sites where substances and wastes have been disposed or otherwise released. Moreover, there exists the possibility that landowners and other third parties will file claims for personal injury and property damage allegedly caused by the release of substances or wastes into the environment.
There is inherent risk of the incurrence of environmental costs and liabilities in our business due to our handling of natural gas and other petroleum products, air emissions related to our operations, historical industry operations including releases of substances into the environment and waste disposal practices. For example, an accidental release from the Eureka Hunter Gas Gathering System could subject us to substantial liabilities arising from environmental cleanup, restoration costs and natural resource damages, claims made by landowners and other third parties for personal injury and property damage, and fines or penalties for related violations of environmental laws or regulations. Moreover, the possibility exists that stricter laws, regulations or enforcement policies could significantly increase our compliance costs and the cost of any remediation that may become necessary. We may not be able to recover some or any of these costs from insurance.
Certain U.S. federal income tax deductions currently available with respect to oil and natural gas exploration and development may be eliminated as a result of future legislation.
Congress has recently considered, is considering, and may continue to consider, legislation that, if adopted in its proposed or similar form, would deprive some companies involved in oil and natural gas exploration and production activities of certain U.S. federal income tax incentives and deductions currently available to such companies. These changes include, but are not limited to, (1) the repeal of the percentage depletion allowance for oil and natural gas properties, (2) the elimination of current deductions for intangible drilling and development costs, (3) the elimination of the deduction for certain domestic production activities, and (4) an extension of the amortization period for certain geological and geophysical expenditures.
It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could become effective and whether such changes may apply retroactively. Although we are unable to predict whether any of these or other proposals will ultimately be enacted, the passage of any legislation as a result of these proposals or any other similar changes in U.S. federal income tax laws could eliminate or postpone certain tax deductions that are currently available to us, and any such change could negatively affect our financial condition and results of operations.
Our ability to use net operating loss carry-forwards to offset future taxable income may be subject to certain limitations.
At December 31, 2013, we had net operating loss carry-forwards of approximately $400 million that expire in varying amounts through 2033. However, changes in the ownership of our stock (including certain transactions involving our stock that are outside of our control) could cause an “ownership change” within the meaning of Section 382 of the Internal Revenue Code of 1986, as amended, referred to as the Internal Revenue Code, which may significantly limit our ability to utilize our net operating loss carry-forwards. To the extent an ownership change has occurred or were to occur in the future, it is possible that the limitations imposed on our ability to use pre-ownership change losses could cause a significant net increase in our U.S. federal income tax liability and could cause U.S. federal income taxes to be paid earlier than otherwise would be paid if such limitations were not in effect.
Federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.
Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, sand and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production. We commonly use hydraulic fracturing as part of our operations. Hydraulic fracturing typically is regulated by state oil and natural gas commissions, but the EPA has asserted federal regulatory authority pursuant to the Safe Drinking Water Act over certain hydraulic fracturing activities involving the use of diesel. In addition, legislation has been introduced before Congress to provide for federal regulation of hydraulic fracturing under the Safe Drinking Water Act and to require disclosure of the chemicals used in the hydraulic fracturing process. Several states are also considering implementing, and some states, including Texas, have implemented, new regulations pertaining to hydraulic fracturing, including the disclosure of chemicals used in connection therewith. For example, Texas recently enacted a law that requires hydraulic fracturing operators to disclose the chemicals used in the fracturing process on a well-by-well basis. Further, various municipalities in several states, including Pennsylvania, West Virginia and Ohio, have passed ordinances which seek to prohibit hydraulic fracturing. We believe that we follow applicable standard industry practices and legal requirements for groundwater protection in our hydraulic fracturing activities. Nonetheless, if new or more stringent federal, state or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development or production activities, and perhaps even be precluded from drilling wells.
In addition, certain governmental reviews are either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices, and a committee of the U.S. House of Representatives has conducted an investigation of hydraulic fracturing practices. The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, with final results expected to be released in late 2014. Moreover, the EPA is developing effluent limitations for the treatment and discharge of wastewater resulting from hydraulic fracturing activities and plans to propose these standards by 2014. Other governmental agencies, including the U.S. Department of Energy and the U.S. Department of the Interior, are evaluating various other aspects of hydraulic fracturing. These ongoing or proposed studies, depending on their degree of pursuit and any
meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the federal Safe Drinking Water Act or other regulatory mechanisms.
In April 2012, the EPA issued regulations specifically applicable to the oil and gas industry that will require operators to significantly reduce volatile organic compounds, or VOC, emissions from natural gas wells that are hydraulically fractured through the use of “green completions” to capture natural gas that would otherwise escape into the air. The EPA also issued regulations that establish standards for VOC emissions from several types of equipment at natural gas well sites, including storage tanks, compressors, dehydrators and pneumatic controllers, as well as natural gas gathering and boosting stations, processing plants, and compressor stations. In March 2013, the EPA proposed updates to these VOC performance standards to clarify the requirements for storage tanks used in crude oil and natural gas production.
To our knowledge, there has been no contamination of potable drinking water, or citations or lawsuits claiming such contamination, arising from our hydraulic fracturing operations. We do not have insurance policies in effect that are intended to provide coverage for losses solely related to hydraulic fracturing operations; however, we believe our general liability and excess liability insurance policies would cover third-party claims related to hydraulic fracturing operations and associated legal expenses in accordance with, and subject to, the terms of such policies.
Climate change legislation or regulations restricting emissions of “greenhouse gases” could result in increased operating costs and reduced demand for the oil, natural gas and natural gas liquids that we produce.
In December 2009, the EPA published its findings that emissions of greenhouse gases, or GHGs, present a danger to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth's atmosphere and other climatic conditions. Based on these findings, in 2010 the EPA adopted two sets of regulations that restrict emissions of GHGs under existing provisions of the federal Clean Air Act, including one that requires a reduction in emissions of GHGs from motor vehicles and another that requires certain construction and operating permit reviews for GHG emissions from certain large stationary sources. The stationary source final rule addresses the permitting of GHG emissions from stationary sources under the Clean Air Act Prevention of Significant Deterioration, or PSD, construction and Title V operating permit programs, pursuant to which these permit programs have been “tailored” to apply to certain stationary sources of GHG emissions in a multi-step process, with the largest sources first subject to permitting. In addition, EPA adopted rules requiring the monitoring and reporting of GHGs from certain sources, including, among others, onshore and offshore oil and natural gas production facilities. We are evaluating whether GHG emissions from our operations are subject to the GHG emissions reporting rule and expect to be able to comply with any applicable reporting obligations.
Also, Congress has from time to time considered legislation to reduce emissions of GHGs, and almost one-half of the states already have taken legal measures to reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. The adoption of any legislation or regulations that requires reporting of GHGs or otherwise restricts emissions of GHGs from our equipment and operations could require us to incur significant added costs to reduce emissions of GHGs or could adversely affect demand for the oil, natural gas and natural gas liquids we produce.
Finally, some scientists have concluded that increasing concentrations of GHGs in the earth’s atmosphere may produce climate change that could have significant physical effect, such as increased frequency and severity of storms, droughts and floods and other climatic events. If such effects were to occur, they could have an adverse effect on our assets and operations.
We must obtain governmental permits and approvals for our operations, which can be a costly and time consuming process, which may result in delays and restrictions on our operations.
Regulatory authorities exercise considerable discretion in the timing and scope of specific permit issuance. Requirements imposed by these authorities may be costly and time consuming and may result in delays in the commencement or continuation of our exploration, development or production operations or our midstream operations. For example, we are often required to prepare and present to federal, state, local or foreign authorities data pertaining to the effect or impact that proposed exploration for or development or production of oil or natural gas, pipeline construction, natural gas compression, treating or processing facilities or equipment and other associated equipment may have on the environment. Further, the public may comment on and otherwise engage in the permitting process, including through intervention in the courts. Accordingly, the permits we need may not be issued, or if issued, may not be issued in a timely fashion, or may involve requirements that restrict our ability to conduct our operations or to do so profitably.
Our operations expose us to substantial costs and liabilities with respect to environmental matters.
Our oil and natural gas operations are subject to stringent federal, state, local and foreign laws and regulations governing the release of materials into the environment or otherwise relating to environmental protection. These laws and regulations may require the acquisition of a permit before drilling or midstream construction activities commence, restrict the types, quantities and concentration of substances that can be released into the environment in connection with our drilling and production activities, limit or prohibit drilling or pipeline construction activities on certain lands lying within wilderness, wetlands and other protected areas, and impose substantial liabilities for pollution that may result from our operations. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of investigatory or remedial obligations or injunctive relief. Under existing environmental laws and regulations, we could be held strictly liable for the removal or remediation of previously released materials or property contamination regardless of whether the release resulted from our operations, or our operations were in compliance with all applicable laws at the time they were performed. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent or costly waste handling, storage, transport, disposal or cleanup requirements could require us to make significant expenditures to maintain compliance, and may otherwise have a material adverse effect on our competitive position, financial condition and results of operations.
Derivatives reform could have an adverse impact on our ability to hedge risks associated with our business.
The Dodd-Frank Wall Street Reform and Consumer Protection Act, or Dodd-Frank, which was enacted in 2010, established a framework for the comprehensive regulation of the derivatives markets, including the swaps markets. Since the enactment of Dodd-Frank, the Commodity Futures Trading Commission, or CFTC, and the SEC have adopted regulations to implement this new regulatory regime, and continue to propose and adopt regulations, with the phase-in likely to continue for at least the next year. Among other things, entities that enter into derivatives will be subject to position limits for certain futures, options and swaps (under a pending regulatory proposal), and are currently subject to recordkeeping and reporting requirements. There are also possible credit support requirements stemming from regulations that have not yet been finalized in their entirety. Although Dodd-Frank favors mandatory exchange trading and clearing, entities that enter into over-the-counter swaps to mitigate commercial risk, such as Magnum Hunter, may be exempt from the clearing mandate where their positions qualify for exemption under existing CFTC regulations. Whether we are required to post collateral with respect to our derivative transactions will depend on our counterparty type, final rules to be adopted by the CFTC, SEC and the bank regulators, and how our activities fit within those rules. Many entities, including our counterparties, are now subject to significantly increased regulatory oversight which may in the future include minimum capital requirements. These changes could materially alter the terms of our derivative contracts, reduce the availability of derivatives to protect against the risks we encounter, reduce our ability to monetize or restructure existing derivative contracts and increase our exposure to less creditworthy counterparties. If we are required to post cash or other collateral with respect to our derivative positions, we could be required to divert resources (including cash) away from our core businesses, which could limit our ability to execute strategic hedges and thereby result in increased commodity price uncertainty and volatility in our cash flow. Although it is difficult to predict the aggregate effect of the new regulatory regime, the new regime could increase our costs, limit our ability to protect against risks and reduce liquidity, all of which could impact our cash flows and results of operations.
We pursue acquisitions as part of our growth strategy and there are risks in connection with acquisitions.
Our growth has been attributable in part to acquisitions of producing properties and undeveloped acreage, either directly as asset acquisitions or indirectly through the acquisition of companies. We expect to continue to evaluate and, where appropriate, pursue acquisition opportunities on terms we consider favorable. However, we cannot assure you that suitable acquisition candidates will be identified in the future, or that we will be able to finance such acquisitions on favorable terms. In addition, we compete against other companies for acquisitions, and we cannot assure you that we will successfully acquire any material property interests. Further, we cannot assure you that future acquisitions by us will be integrated successfully into our operations or will be profitable.
The successful acquisition of producing properties and undeveloped acreage requires an assessment of numerous factors, some of which are beyond our control, including, without limitation:
•
estimated recoverable reserves;
•
exploration and development potential;
•
future oil and natural gas prices;
•
operating costs; and
•
potential environmental and other liabilities.
In connection with such an assessment, we perform a review of the subject properties that we believe to be generally consistent with industry practices. The resulting assessments are inexact and their accuracy uncertain, and such a review may not reveal all existing or potential problems, nor will it necessarily permit us to become sufficiently familiar with the properties to fully assess their merits and deficiencies within the time frame required to complete the transactions. Inspections may not always be performed on every well or of every property, and structural and environmental problems are not necessarily observable even when an inspection is made.
Additionally, significant acquisitions can change the nature of our operations and business depending upon the character of the acquired properties, which may be substantially different in operating and geologic characteristics, geographic location or regulatory environment than our existing properties. While our core current operations are primarily focused in the West Virginia, Ohio and North Dakota regions, we may pursue acquisitions of properties located in other geographic areas.
Our recent acquisitions and any future acquisitions may not be successful, may substantially increase our indebtedness and contingent liabilities and may create integration difficulties.
As part of our business strategy, we have acquired and intend to continue to acquire businesses or assets we believe complement our existing core operations and business plans. We may not be able to successfully integrate these acquisitions into our existing operations or achieve the desired profitability from such acquisitions. These acquisitions may require substantial capital expenditures and the incurrence of additional indebtedness which may change significantly our capitalization and results of operations. Further, these acquisitions could result in:
•
post-closing discovery of material undisclosed liabilities of the acquired business or assets, title or other defects with respect to acquired assets, discrepancies or errors in furnished financial statements or other information or breaches of representations made by the sellers;
•
the unexpected loss of key employees or customers from acquired businesses;
•
difficulties resulting from our integration of the operations, systems and management of the acquired business; and
•
an unexpected diversion of our management’s attention from other operations.
If acquisitions are unsuccessful or result in unanticipated events, such as the post-closing discovery of the matters described above, or if we are unable to successfully integrate acquisitions into our existing operations, such acquisitions could adversely affect our financial condition, results of operations and cash flow. The process of integrating our operations could cause an interruption of, or loss of momentum in, the activities of our business. Members of our management may be required to devote considerable amounts of time to this integration process, which will decrease the time they will have to manage our existing business. If management is not able to effectively manage the integration process, or if any significant business activities are interrupted as a result of the integration process, our business could suffer.
There are risks in connection with dispositions we have made and intend to pursue.
We have made and continue to pursue dispositions of assets and properties, both to increase our cash position (or reduce our indebtedness) and to redirect our resources toward our core operations or for other purposes, either through asset sales or the sale of stock of one or more of our subsidiaries. We continue to pursue dispositions of non-core assets. However, we cannot assure you that suitable disposition opportunities will be identified in the future, or that we will be able to complete such dispositions on favorable terms. Further, we cannot assure you that our use of the net proceeds from such dispositions will result in improved results of operations.
As with a successful acquisition, the successful disposition of assets and properties requires an assessment of numerous factors, some of which are beyond our control, including, without limitation:
•
estimated recoverable reserves;
•
exploration and development potential;
•
future oil and natural gas prices;
•
operating costs;
•
potential seller indemnification obligations;
•
the creditworthiness of the buyer; and
•
potential environmental and other liabilities.
In connection with such an assessment, we perform a review of the subject properties that we believe to be generally consistent with industry practices. The resulting assessments are inexact and their accuracy uncertain, and such a review may not reveal all existing or potential benefits associated with a property, nor will it necessarily permit us to become sufficiently familiar with the properties to fully assess their merits and deficiencies within the time frame required to complete the transactions. Additionally, significant dispositions can change the nature of our operations and business.
Risks Related to Our Common Stock
The price of our common stock has fluctuated substantially since it first became listed on a national securities exchange in August 2006 and may fluctuate substantially in the future.
Our common stock is traded on the New York Stock Exchange, or NYSE, under the symbol “MHR”. On February 19, 2014, the last reported sale price of our common stock, as reported on the NYSE, was $8.79 per share. The price of our common stock has fluctuated substantially since it first became listed on a national securities exchange in August 2006. From August 30, 2006 to January 31, 2014, the trading price at the close of the market (initially the American Stock Exchange and now the NYSE) of our common stock ranged from a low of $0.20 per share to a high of $8.73 per share. In addition, the stock market in general, and early stage public companies in particular, have experienced extreme price and volume fluctuations that have often been unrelated or disproportionate to the operating performance of such companies.
We expect our common stock to continue to be subject to fluctuations as a result of a variety of factors, including factors beyond our control. These factors include:
•
changes in oil and natural gas prices;
•
variations in quarterly drilling, production and operating results;
•
acquisitions and dispositions of assets;
•
results of our midstream operations;
•
changes in financial estimates by securities analysts;
•
changes in market valuations of comparable companies;
•
additions or departures of key personnel;
•
the level of our overall indebtedness;
•
future issuances of our common stock and related dilution to existing stockholders;
•
legal or regulatory proceedings or the threat thereof; and
•
the other risks and uncertainties described in this “Risk Factors” section and elsewhere in this annual report.
We may fail to meet the expectations of our stockholders or of securities analysts at some time in the future, and our stock price could decline as a result. Volatility or depressed market prices of our common stock could make it difficult for our stockholders to resell shares of our common stock when they want or at attractive prices.
The market for our common stock may not provide investors with sufficient liquidity or a market-based valuation of our common stock.
The volume of trading in our common stock may not always provide investors sufficient liquidity in the event they wish to sell large blocks of common stock. There can be no assurance that an active market for our common stock will be available for trading in large volumes. If we are unable to maintain or further develop an active market for our common stock, our stockholders may not be able to sell our common stock at prices they consider to be fair or at times that are convenient for them, or at all.
We will likely issue additional common stock in the future, which would dilute the holdings of our existing stockholders.
In the future we may issue additional securities up to our total authorized and unissued amounts, including shares of our common stock or securities convertible into or exchangeable or exercisable for our common stock, resulting in the dilution of the ownership interests of our stockholders. We are currently authorized under our certificate of incorporation to issue up to 350,000,000 shares of common stock and up to 10,000,000 shares of preferred stock with such designations, preferences and rights as may be determined by our board of directors.
As of December 31, 2013, there were 171,494,071 shares of our common stock outstanding, 4,000,000 shares of our non-convertible Series C Cumulative Perpetual Preferred Stock, or Series C Preferred Stock, outstanding, 4,424,889 shares of our non-convertible Series D Cumulative Preferred Stock, or Series D Preferred Stock, outstanding and 3,721,556 Depositary Shares representing 3,722 shares of our Series E Cumulative Convertible Preferred Stock, or Series E Preferred Stock, outstanding.
We may issue additional shares of our common stock or securities convertible into or exchangeable or exercisable for our common stock in connection with hiring or retaining personnel, option or warrant exercises, future acquisitions or future placements of our securities for capital-raising or other business purposes.
Our certificate of incorporation and bylaws, and Delaware law, contain provisions that could make it more difficult for a third party to acquire us without the consent of our board of directors and our executive officers, who collectively beneficially owned approximately 5.5% of the outstanding shares of our common stock as of January 31, 2014.
Provisions in our certificate of incorporation and bylaws could have the effect of delaying or preventing a change of control of us and changes in our management. These provisions include the following:
•
the ability of our board of directors to issue shares of our common stock and preferred stock without stockholder approval;
•
the ability of our board of directors to make, alter, or repeal our bylaws without stockholder approval;
•
the requirement for advance notice of director nominations to our board of directors and for proposing other matters to be acted upon at stockholder meetings;
•
requiring that special meetings of stockholders be called only by our chairman, by a majority of our board of directors, by our chief executive officer or by stockholders holding shares in the aggregate entitled to cast not less than 10% of the votes at such meeting; and
•
allowing our directors, and not our stockholders, to fill vacancies on the board of directors, including vacancies resulting from removal of directors or enlargement of the board of directors.
In addition, we are subject to the provisions of Section 203 of the Delaware General Corporation Law. These provisions may prohibit large stockholders, in particular those owning 15% or more of our outstanding voting stock, from merging or combining with us.
As of January 31, 2014, our board of directors and executive officers collectively beneficially owned approximately 5.5% of the outstanding shares of our common stock. Although this is not a significant percentage of our outstanding common stock, these stockholders, acting together, may have the ability to exert influence over matters requiring stockholder approval, including the election of directors, any proposed merger, consolidation or sale of all or substantially all of our assets and certain other corporate matters and transactions.
The provisions in our certificate of incorporation and bylaws and of Delaware law, and any concentrated ownership of our common stock by our directors and executive officers, could discourage potential takeover attempts and could reduce the price that investors might be willing to pay for shares of our common stock.
Because we have no plans to pay dividends on our common stock, stockholders must look solely to appreciation in the market value of our common stock to realize a gain on their investments.
We do not anticipate paying any cash dividends on our common stock in the foreseeable future. We currently intend to retain future earnings, if any, to finance the expansion of our businesses. Our future dividend policy is within the discretion of our board of directors and will depend upon various factors, including our business, financial condition, results of operations, capital requirements and investment opportunities. In addition, our credit facilities and the indenture governing our senior notes limit the payment of dividends on our stock under certain circumstances without the prior written consent of the lenders or note holders. Accordingly, stockholders must look solely to appreciation in the market value of our common stock to realize a gain on their investment, which appreciation in value may never occur or may occur only from time to time and then only for limited periods of time.
We are able to issue shares of preferred stock with greater rights than our common stock.
Our certificate of incorporation authorizes our board of directors to issue one or more series of preferred stock and set the terms of the preferred stock without seeking any further approval from our common stockholders. Any preferred stock that is issued may rank ahead of our common stock in terms of dividend rights, liquidation rights and/or voting rights. The terms of such preferred stock may also require us to redeem the preferred stock at the option of the holders of the preferred stock or mandatorily at certain times or under certain circumstances. If we issue additional preferred stock, it may adversely affect the market price of our common stock.
Our assets are subject to liquidation preferences in favor of the holders of our preferred stock, which will impact the rights of holders of our common stock if we liquidate.
We have a significant number of shares outstanding of each of our Series C Preferred Stock, Series D Preferred Stock and Depositary Shares representing our Series E Preferred Stock. Under the certificates of designations of these series of preferred stock, if we liquidate, holders of our preferred stock (including the holders of the Depositary Shares) are entitled to receive payment of the stated liquidation preference of their shares, together with any accrued but unpaid dividends, before any payment is made to holders of our common stock.
Our outstanding warrants, stock options, stock appreciation rights and Depositary Shares, which are exercisable for or convertible into shares of our common stock, may be exercised or converted, which would dilute our existing common stockholders.
As of December 31, 2013, we had:
•
outstanding warrants that had an exercise price of (a) $19.04 per warrant share and a final maturity of November 2014 and were exercisable for an aggregate of 40,608 shares of our common stock and (b) $8.50 per warrant share and a final maturity of April 2016 and were exercisable for an aggregate of 17,030,707 shares of our common stock;
•
outstanding employee and director stock options and stock appreciation rights that had exercise prices ranging from $0.51 to $7.95 per share and covered an aggregate of 16,891,419 shares of our common stock (and of which an aggregate of 9,983,743 stock options and stock appreciation rights, or approximately 59%, were exercisable as of December 31, 2013 and of which an aggregate of 12,639,469 stock options and stock appreciation rights, or approximately 74.8%, had exercise prices below $7.31, the closing sales price of our common stock on the NYSE on December 31, 2013; and
•
outstanding Depositary Shares representing our Series E Preferred Stock that had a conversion price (based on stated liquidation preference plus accrued and unpaid dividends) of $8.50 per share of common stock and were exercisable for an aggregate of 10,945,753 shares of our common stock.
Any such exercise or conversion will be dilutive to the ownership interests of our existing stockholders.
The market price of our common stock could be adversely affected by sales of substantial amounts of our common stock and securities convertible into, or exchangeable or exercisable for, shares of our common stock in the public markets and the issuance of shares of common stock and securities convertible into, or exchangeable or exercisable for, shares of our common stock in future acquisitions.
Sales of a substantial number of shares of our common stock by us or by other parties in the public market, or the perception that such sales may occur, could cause the market price of our common stock to decline. In addition, the sale of such shares in the public market could impair our ability to raise capital through the sale of common stock or securities convertible into, or exchangeable or exercisable for, shares of common stock.
In addition, in the future, we may issue shares of our common stock and securities convertible into, or exchangeable or exercisable for, shares of our common stock in furtherance of our acquisitions and development of assets or businesses. If we use our shares for this purpose, the issuances could have a dilutive effect on the value of our common stock, depending on market conditions at the time of such an event, the price we pay, the value of the assets or business acquired and our success in exploiting the properties or integrating the businesses we acquire and other factors.
Item 1B.
Item 1B.
UNRESOLVED STAFF COMMENTS
None.
Item 2.
Item 2.
PROPERTIES
The information required by Item 2. is contained in “Item 1. Business.”
Item 3.
Item 3.
LEGAL PROCEEDINGS
Securities Cases
On April 23, 2013, Anthony Rosian, individually and on behalf of all other persons similarly situated, filed a class action complaint in the United States District Court, Southern District of New York, against the Company and certain of its officers, two of whom, at that time, also served as directors, and one of whom continues to serve as a director. On April 24, 2013, Horace Carvalho, individually and on behalf of all other persons similarly situated, filed a similar class action complaint in the United States District Court, Southern District of Texas, against the Company and certain of its officers. Several substantially similar putative class actions have been filed in the Southern District of New York and in the Southern District of Texas. All such cases are collectively referred to as the Securities Cases. The cases filed in the Southern District of Texas have since been dismissed, but the cases in the Southern District of New York have been consolidated and remain ongoing. The plaintiffs in the Securities Cases have filed a consolidated amended complaint alleging that the Company made certain false or misleading statements in its filings with the SEC, including statements related to the Company's internal and financial controls, the calculation of non-cash share-based compensation expense, the late filing of the Company's 2012 Form 10-K, the dismissal of Magnum Hunter's previous independent registered accounting firm, the Company’s characterization of the auditors’ position with respect to the dismissal, and other matters identified in the Company's April 16, 2013 Form 8-K, as amended. The consolidated amended complaint asserts claims under Sections 10(b) and 20 of the Exchange Act based on alleged false statements made regarding these issues throughout the alleged class period, as well as claims under Sections 11, 12, and 15 of the Securities Act based on alleged false statements and omissions regarding the Company’s internal controls made in connection with a public offering that Magnum Hunter completed on May 14, 2012. The consolidated amended complaint demands that the defendants pay unspecified damages to the class action plaintiffs, including damages allegedly caused by the decline in the Company's stock price between February 22, 2013 and April 22, 2013. The Company and the individual defendants intend to vigorously defend the Securities Cases. It is possible that additional investor lawsuits could be filed over these events.
On May 10, 2013, Steven Handshu filed a stockholder derivative suit in the 151st Judicial District Court of Harris County, Texas on behalf of the Company against the Company's directors and senior officers (the “Handshu Action”). On June 6, 2013, Zachariah Hanft filed another stockholder derivative suit in the Southern District of New York on behalf of the Company against the Company's directors and senior officers (the “Hanft Action”). On June 18, 2013, Mark Respler filed another stockholder derivative suit in the District of Delaware on behalf of the Company against the Company's directors and senior officers (the “Respler Action”). On June
27, 2013, Timothy Bassett filed another stockholder derivative suit in the Southern District of Texas on behalf of the Company against the Company's directors and senior officers. On September 16, 2013, Joseph Vitellone was substituted as plaintiff in the action filed by Mr. Bassett (the “Vitellone Action”). These suits are collectively referred to as the Derivative Cases. The Derivative Cases assert that the individual defendants unjustly enriched themselves and breached their fiduciary duties to the Company by publishing allegedly false and misleading statements to the Company's investors regarding the Company's business and financial position and results, and allegedly failing to maintain adequate internal controls. The complaints demand that the defendants pay unspecified damages to the Company, including damages allegedly sustained by the Company as a result of the alleged breaches of fiduciary duties by the defendants, as well as disgorgement of profits and benefits obtained by the defendants, and reasonable attorneys', accountants' and experts' fees and costs to the plaintiff. On December 13, 2013, the Handshu Action was dismissed for want of prosecution. On December 20, 2013, the United States District Court for the Southern District of Texas granted the Company’s motion to dismiss the Vitellone Action and entered a final judgment dismissing the case in its entirety. The court held that the plaintiff failed to allege particularized facts that would excuse them from making pre-suit demand on the Company’s Board of Directors as required by Delaware law. On January 21, 2014, the Hanft Action was dismissed with prejudice after the plaintiff in that action filed a voluntary motion for dismissal. On February 18, 2014, the District of Delaware granted the Company’s motion to dismiss the Respler Action on collateral estoppel grounds and closed the case. Accordingly, no stockholder derivative cases are currently pending against the Company’s officers and directors. It is possible, however, that additional stockholder derivative suits could be filed over these events.
In addition, the Company has received several demand letters from stockholders seeking books and records relating to the allegations in the Securities Cases and the Derivative Cases under Section 220 of the Delaware General Corporation Law. On September 17, 2013, Anthony Scavo, who is one of the stockholders that made a demand, filed a books and records action in the Delaware Court of Chancery pursuant to Section 220 of the Delaware General Corporation Law (the “Scavo Action”). The Scavo Action seeks various books and records relating to the claims in the Securities Cases and the Derivative Cases, as well as costs and attorneys’ fees. The Company has filed an answer in the Scavo Action. It is possible that additional similar actions may be filed and that similar stockholder demands could be made.
The Company also received an April 26, 2013 letter from the SEC stating that the SEC's Division of Enforcement was conducting an inquiry regarding the Company's internal controls, change in outside auditors and public statements to investors and asking the Company to preserve documents relating to these matters. The Company is complying with this request. On December 30, 2013, the Company received a document subpoena relating to the issues identified in the April 26, 2013 letter. The Company is producing documents in response to the subpoena. The SEC notified the Company that it also issued subpoenas for testimony from certain individuals.
Dux Litigation
On December 30, 2013, Dux Petroleum LLC, or Dux, sued Magnum Hunter Resources Corporation and a subsidiary, Triad Hunter, LLC, or Triad Hunter, in Dux Petroleum LLC v. Magnum Hunter Resources Corp. et al., Cause No. 2013-77283, in the District Court for Harris County, Texas-295th District.
The plaintiff, Dux, alleges that Magnum Hunter Resources Corporation and Triad Hunter tortiously interfered with brokerage contracts it had with co-defendants Black Rock Hunter LLC and V-M LLC related to oil and gas leases in the Marcellus Shale in Ohio, which it contends Triad Hunter ultimately purchased in the August 12, 2013 transaction with MNW. Dux also alleges that Magnum Hunter Resources Corporation and Triad Hunter are vicariously liable for fraud committed by the principals of co-defendant MNW from whom Triad Hunter purchased certain oil and gas leases; that Magnum Hunter Resources Corporation and Triad Hunter conspired with the other defendants to tortiously interfere with Dux’s contracts with co-defendants Black Rock Hunter LLC and V-M LLC; and that Magnum Hunter Resources Corporation and Triad Hunter aided and abetted breaches of fiduciary duty committed by Black Rock Hunter LLC and V-M LLC against Dux. Dux has also asserted an unjust enrichment claim against Magnum Hunter Resources Corporation and Triad Hunter. The principals of MNW, James Vuksic, Daniel Germain, Jr., and J. Douglas Mallet, are also co-defendants, as is a limited liability company registered in Ohio also called Dux Petroleum LLC. Dux has not made a specific monetary demand, but has requested treble damages, pre- and post-judgment interest, and costs and reasonable attorneys’ fees.
The Company believes that this lawsuit is without merit with respect to the claims asserted against it and intends to vigorously defend itself and is evaluating whether to assert potential counterclaims. The Company believes the liability, if any, ultimately incurred with respect to such lawsuit will not have a material adverse effect on its consolidated financial position, liquidity, capital resources or results of operations. However, the claims asserted in the lawsuit may impair our right to receive satisfactory title to the acreage; therefore, there may be delays on any future MNW closings until this matter is resolved.
Twin Hickory Litigation
On April 11, 2013, a flash fire occurred at Eureka Hunter Pipeline’s Twin Hickory site located in Tyler County, West Virginia. The incident occurred during a pigging operation at a natural gas receiving station. Two employees of third-party contractors received fatal injuries. Another employee of a third-party contractor was injured. In mid-February 2014, the estate of one of the deceased third-party contractor employees sued Eureka Hunter Pipeline and certain other parties in Karen S. Phipps v. Eureka Hunter Pipeline, LLC et al., Civil Action No. 14-C-41, in the Circuit Court of Ohio County, West Virginia. The plaintiff alleges that Eureka Hunter Pipeline and the other defendants engaged in certain negligent and reckless conduct which resulted in the wrongful death of the third-
party contractor employee. The plaintiff has demanded judgment for an unspecified amount of compensatory, general and punitive damages. A pre-suit settlement demand has also been received from another potential claimant. Investigation regarding the incident is ongoing. It is not possible to predict at this juncture the extent to which, if at all, Eureka Hunter Pipeline or any related entities will incur liability or damages because of this incident. However, we believe our insurance will be sufficient to cover any losses or liabilities we may incur as a result of this incident.
Eagle Ford Properties Sale Final Settlement
We and Penn Virginia have been unable to agree upon the final settlement of the adjustments to the cash portion of the purchase price for the sale of our Eagle Ford properties. As a result, and pursuant to the agreed-upon procedures set forth in the stock purchase agreement, the disagreement regarding the final settlement of the adjustment amounts has been submitted to arbitration. As of the date of filing of this annual report, we estimate that the final settlement of the adjustment amounts may result in an obligation to Penn Virginia ranging from $22 million to $33 million, net of taxes, but such estimate is subject to the final determination of the adjustment amounts by the arbitrator. See "Note 2 - Divestitures and Discontinued Operations".
Item 4.
Item 4.
MINE SAFETY DISCLOSURES
Not applicable.
PART II
Item 5.
Item 5.
MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Common Stock Trading Summary
Our common stock trades on the NYSE under the symbol “MHR.” The following table summarizes the high and low reported sales prices on days in which there were trades of our common stock on the NYSE for each quarterly period for the last two fiscal years. On February 19, 2014, the last reported sale price of our common stock, as reported on the NYSE, was $8.79 per share.
Holders
As of January 31, 2014, based on information from our transfer agent, American Stock Transfer and Trust Company, we had 302 holders of record of the outstanding shares of our common stock, which record holders included Cede & Co., as nominee of The Depository Trust and Clearing Corporation, or DTC. As of that same date, Cede & Co., as nominee of the DTC, was the sole holder of record of the outstanding shares of our Series C Preferred Stock, Series D Preferred Stock and Depositary Shares representing our Series E Preferred Stock. Cede & Co., as nominee of the DTC, holds securities, including our common and preferred stock and our Depositary Shares, on behalf of numerous direct and indirect beneficial owners.
Dividends
We have not paid any cash dividends on our common stock since our inception and do not contemplate paying cash dividends on our common stock in the foreseeable future. Also, we are restricted from declaring or paying any cash dividends on our common stock under our revolving credit facility and the indenture governing our senior notes. It is anticipated that earnings, if any, will be retained for the future operation of our business.
Securities Authorized for Issuance Under Equity Compensation Plans
The following table provides information with respect to shares of our common stock issuable under our equity compensation plans as of December 31, 2013:
The Company’s stock incentive plan provides for the grant of stock options, shares of restricted common stock, unrestricted shares of common stock, performance stock and stock appreciation rights. Awards under the stock incentive plan may be made to any employee, officer or director of the Company or any subsidiary or to consultants and advisors to the Company or any subsidiary. See "Note 9 - Share-Based Compensation" to our consolidated financial statements.
Share Performance Graph
The following performance graph and related information shall not be deemed “soliciting material” or to be “filed” with the SEC, nor shall such information be incorporated by reference into any future filings under the Securities Act or Exchange Act, except to the extent that the Company specifically incorporates it by reference into such filing.
The following graph illustrates changes over the five-year period ended December 31, 2013 in cumulative total stockholder return on our common stock as measured against the cumulative total return of the S&P 500 Index and the Dow Jones U.S. Exploration and Production Index. The results assume $100 was invested on December 31, 2008, and that dividends were reinvested.
COMPARISON OF 5 YEAR CUMULATIVE TOTAL RETURNS
Item 6.
Item 6.
SELECTED FINANCIAL DATA
The following selected consolidated financial data should be read in conjunction with the Company’s consolidated financial statements and related notes and “Item 7.
Item 7.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion is intended to assist you in understanding our results of operations and our financial condition. Our consolidated financial statements and the accompanying notes included elsewhere in this annual report contain additional information that should be referred to when reviewing this material. Statements in this discussion may be forward-looking. These forward-looking statements involve risks and uncertainties, which could cause actual results to differ from those expressed. See “Cautionary Notice Regarding Forward-Looking Statements” at the beginning of this annual report and “Risk Factors” for additional discussion of some of these factors and risks.
Business Overview
We are an independent oil and natural gas company engaged in the exploration for and the exploitation, acquisition, development and production of crude oil, natural gas and natural gas liquids resources in the United States. We are active in what we believe to be three of the most prolific unconventional shale resource plays in the United States, specifically, the Marcellus Shale in West Virginia and Ohio; the Utica Shale in southeastern Ohio and western West Virginia; and the Williston Basin/Bakken Shale in North Dakota. Our core oil and natural gas reserves and operations are primarily concentrated in West Virginia, Ohio and North Dakota. We are also engaged in midstream and oil field services operations, primarily in West Virginia and Ohio.
Our business strategy is to create significant value for our stockholders by growing reserves, production volumes and cash flow at an attractive rate of return through a combination of efficient development of our properties and strategic acquisitions and joint ventures, and to selectively monetize properties at opportune times and attractive prices. As part of our strategy:
•
We have approved a $400 million capital expenditure budget for fiscal year 2014, excluding acquisitions. We have allocated approximately $260 million in the Utica Shale and Marcellus Shale plays, approximately $50 million in the Williston Basin and approximately $90 million (net to our majority interest) for midstream operations. We expect this Appalachian-focused capital program to further drive our future production volumes and reserve additions and enable us to achieve our 2014 projected exit production rate of 35,000 Boe/d;
•
We have recently completed in excess of $500 million in divestitures, including sales of our Eagle Ford Shale properties in south Texas and certain non-core North Dakota properties (see “Business-Our Significant Recent Developments”);
•
We are actively marketing our southern Appalachian Basin properties located in Kentucky and Tennessee, which we refer to as Magnum Hunter Production, or MHP, and our Canadian properties located in Saskatchewan and Alberta pursuant to a plan to divest those assets adopted in September 2013. We anticipate completing the Canadian divestiture in the second quarter of 2014 and the southern Appalachian Basin divestiture in the second half of 2014. We have reclassified the associated assets and liabilities to assets and liabilities held for sale and the operations are reflected as discontinued operations for all periods presented. As a result, we have recorded an impairment expense (net) of $56.7 million relating to the discontinued operations which is recorded in income (loss) from discontinued operations and an expense (net) of $92.4 million to reflect the net assets at their estimated selling prices, less costs to sell, which is recorded in loss on disposal of discontinued operations; and
•
We have identified a number of other non-core U.S. upstream properties for possible divestiture in 2014 that we believe represent (together with the planned southern Appalachian Basin and Canada divestitures described above) in excess of $400 million in value.
As a result of our recent and planned divestitures, we are now strategically focused on our Marcellus Shale and Utica Shale plays in the Appalachian Basin in West Virginia and Ohio and our Bakken Shale play in the Williston Basin in North Dakota.
Our capital expenditure budget for fiscal year 2014 is currently (a) $310 million for our core upstream operations, consisting of approximately $260 million for the Marcellus and Utica Shales in West Virginia and Ohio and approximately $50 million for the Williston Basin/Bakken Shale in North Dakota, and (b) $90 million (net to our majority interest) for our midstream operations (excluding, in each case, any budgeted amounts for operations that may be acquired pursuant to acquisitions). We expect that the 2014 capital expenditure budget for our midstream operations will be funded by us and by the third-party equity and non-recourse debt facilities we have obtained for our midstream operations.
Our midstream operations are conducted through our majority-owned subsidiary, Eureka Hunter Holdings. Eureka Hunter Pipeline, a subsidiary of Eureka Hunter Holdings, owns and operates our Eureka Hunter Gas Gathering System. We are also engaged in the business of leasing natural gas treating pants to third-party producers in Texas and other states. We have obtained financing for our midstream operations through an equity purchase commitment from an unaffiliated third party, which also gives us the right to make capital contributions in conjunction with or alongside the capital contributions from the third party, and two separate credit facilities on a non-recourse basis to Magnum Hunter Resources Corporation.
Our midstream pipeline is a strategic asset to the development and delineation of our acreage position in the both the Utica Shale and Marcellus Shale plays. We believe that we have a competitive advantage by being vertically integrated and maintaining control of our natural gas gathering activities. From time to time, we have discussions with strategic companies in our core area of operations and may pursue joint ventures or other strategic transactions with respect to this asset.
Our oil field services operations consist of the ownership and operation of six drilling rigs that are used primarily for vertical section (top-hole) air drilling in the Appalachian Basin for us and third parties. Our fleet of rigs includes a robotic walking drilling rig that can also drill the horizontal sections of wells in the shale plays where we are active. This drilling rig was designed especially for pad drilling with its unique footprint and capability to walk and rotate without being dismantled.
Summary of Principal Upstream Properties
Appalachian Basin
As of December 31, 2013, our Appalachian Basin properties included approximately 531,590 gross (461,341 net) acres, located primarily in the Marcellus Shale, Utica Shale and southern Appalachian Basin. At December 31, 2013, proved reserves attributable to our Appalachian Basin properties were 53.4 MMBoe on an SEC basis, of which 26% were oil and liquids and 57% were classified as proved developed producing. As of December 31, 2013, our Appalachian Basin properties included approximately 3,866 gross (2,745.6 net) productive wells, of which we operated approximately 83%.
Williston Basin
As of December 31, 2013, our Williston Basin properties included approximately 418,716 gross (180,153 net) acres. As of December 31, 2013, proved reserves attributable to our Williston Basin properties were 20.8 MMBoe on an SEC basis, of which 94% were oil and natural gas liquids and 44% were classified as proved developed producing. As of December 31, 2013, our Williston Basin properties included approximately 342 gross (138.8 net) productive wells, of which we operated approximately 27%.
Summary of Midstream Operations
As of December 31, 2013, our Eureka Hunter Gas Gathering System consisted of approximately 100 miles of 20-inch and 16-inch mainline, of which approximately 86 miles is currently active, located in northwestern West Virginia and crossing into Ohio, in the Marcellus Shale and Utica Shale.
Summary of Oil Field Services Operations
As of December 31, 2013, we owned and operated five Schramm T200XD drilling rigs and one Schramm T500XD drilling rig. The drilling rigs are used for our Appalachian Basin operations and to provide drilling services to third parties also in the Appalachia Basin. The Schramm T200XD drilling rigs primarily drill the top-holes of wells in preparation for larger drilling rigs, such as the Schramm T500XD, which drill the horizontal sections of the wells.
2013 Highlights and 2014 Outlook
Our activities in 2013 included significant divestitures in excess of $500 million, including sales of our Eagle Ford Shale properties in south Texas and certain non-core North Dakota properties. Following such divestitures, we reallocated our drilling capital expenditure program to focus on oil and liquids rich natural gas projects in the Marcellus Shale and Utica Shale and Williston Basin. As a result of this reallocation and focus on our core areas of operations:
•
Our production mix consisted of approximately 57% oil and liquids in the fourth quarter of 2013 compared to 44% oil and liquids in the fourth quarter of 2012.
•
Our production increased 27.2% from 7,740 Boe/d for 2012 to 9,844 Boe/d for 2013 as a result of acquisitions in 2012 as well as the continued success of our drilling programs in the Marcellus Shale and Williston Basin.
•
Our revenues from continuing operations increased 72.3%, or $82.9 million, to $197.6 million in 2013, compared to $114.7 million in 2012 primarily due to acquisitions in 2012 and an increased focus on oil and NGL production in the Marcellus Shale and Williston Basin.
We have approved a $400 million capital budget for fiscal year 2014, excluding acquisitions. The Company intends to spend approximately $260 million in the Utica Shale and Marcellus Shale plays, approximately $50 million in the Williston Basin and approximately $90 million (net to our majority interest) for midstream activities at Eureka Hunter Pipeline. The contemplated capital budget includes the acquisition of mineral leases in both the Utica Shale and Marcellus Shale plays.
The Company's drilling capital in 2014 will be primarily concentrated on the delineation and development of its combined 180,000 net mineral acres located in the Utica and Marcellus Shale plays of Ohio and West Virginia. Specifically, the Company's development plan will be to further delineate its acreage position located in Monroe, Noble, and Washington Counties, Ohio and in Tyler, Richie and Wetzel Counties, West Virginia. In the Appalachian Basin, we intend to operate two to three drilling rigs during 2014, and anticipate drilling approximately 25 gross (19 net) horizontal wells in the Utica Shale and Marcellus Shale
plays, with the wells coming online throughout the year. We expect to process our liquids rich gas production from the Utica Shale and Marcellus Shale plays at the Mobley Processing Plant (or other anticipated closer gas processing facilities) using our gathering capacity on our Eureka Hunter Gas Gathering System.
In the Williston Basin, we expect to participate predominantly as a non-operated working interest owner and drill approximately 15 to 20 gross (6 to 8 net) wells located primarily in the Ambrose Field in northwest Divide County, North Dakota. We believe this area has the potential for the highest rate of return in our current inventory of properties in the Williston Basin. We are focusing our efforts on developing the Three Forks Sanish and Middle Bakken zones in this area.
The 2014 capital budget of $400 million is expected to be funded from a combination of internally-generated cash flow, capital market related funding, anticipated borrowing capacity under our revolving credit facility associated with anticipated borrowing base increases, anticipated borrowings under Eureka Hunter Pipeline’s two existing credit facilities (or under an expected new senior secured credit facility for Eureka Hunter Pipeline, currently being negotiated, that would replace the two existing credit facilities) and proceeds from non-core asset sales. We have targeted non-core asset sales, which we believe represent in excess of $400 million in aggregate value, for possible divestiture in 2014. These potential divestitures would allow us to significantly expand our activities in our core areas of operations in the Utica and Marcellus Shale plays while improving our financial flexibility and balance sheet. It is possible that such sales could lead to us recognizing losses on disposal, and such losses could be significant.
Recent Events
Eagle Ford Properties Sale
On April 24, 2013, we sold our core properties in the oil window of the Eagle Ford Shale in Gonzales and Lavaca Counties, Texas to an affiliate of Penn Virginia for a total contract purchase price of $401 million, consisting of $361 million in cash (before customary purchase price adjustments) and $40 million in Penn Virginia common stock. At closing, we received $422.1 million in cash and stock, based on initial cash purchase price adjustments and the market price of the Penn Virginia common stock on the closing date. The cash portion of the purchase price is subject to final settlement of the purchase price adjustment amounts, and we estimate that the final adjustment will result in an obligation to Penn Virginia of $22 million to $33 million, net of taxes. See “Item 3. Legal Proceedings-Eagle Ford Properties Sale Final Settlement.” We used the cash portion of the purchase price to repay all then outstanding borrowings under our revolving credit facility and for general corporate purposes. The properties sold to Penn Virginia included approximately 19,000 net Eagle Ford Shale leasehold acres, and our operating and non-operating leasehold working interests in certain existing wells, in Gonzales and Lavaca Counties, Texas. The effective date of the transaction was January 1, 2013.
Sale of Non-Core North Dakota Assets
On September 27, 2013, we sold our non-operated working interests in certain oil and natural gas properties located in Burke County, North Dakota, to Oasis for a contract purchase price of $32.5 million in cash (before customary purchase price adjustments). The effective date of the transaction was July 1, 2013.
On December 30, 2013, we sold our North Dakota waterflood properties located in Burke, Renville, Bottineau and McHenry Counties, North Dakota to Enduro for a contract purchase price of $45 million in cash (before customary purchase price adjustments) and final determination of the customary adjustments to the purchase price will be made by the parties approximately 120 days after closing. The effective date of the transaction was September 1, 2013.
Sale of Remaining Eagle Ford Shale and Pearsall Shale Assets
On January 28, 2014, we sold substantially all of our remaining oil and natural gas properties in the Eagle Ford Shale and Pearsall Shale in south Texas to an affiliate of NSE for a total contract purchase price of $24.5 million, consisting of $15 million in cash (before customary purchase price adjustments) and $9.5 million in ordinary shares of NSE valued. The effective date of the transaction was December 1, 2013.
MNW Leasehold Acquisition
On August 12, 2013, we entered into an asset purchase agreement with MNW. MNW represents an informal association of various land owners, lessees of mineral acreage and sublessees of mineral acreage who own or have rights in mineral acreage located in Monroe, Noble and/or Washington Counties, Ohio. Pursuant to the agreement, we agreed to acquire from MNW up to 32,000 net mineral acres, including currently leased and subleased acreage, located in Monroe, Noble and/or Washington Counties, Ohio, over a period of time, in staggered closings, subject to the satisfaction of certain closing conditions, including our right to receive satisfactory title to the acreage. As of January 31, 2014, we had acquired 6,129 net acres pursuant to MNW closings. On December 30, 2013, a lawsuit was filed against us, MNW and others asserting certain claims relating to the acreage covered by our agreement with MNW. We believe the claims asserted against us in the lawsuit are without merit. However, the
claims asserted in the lawsuit may impair our right to receive satisfactory title to the acreage; therefore, any future MNW closings may be delayed until this matter is resolved. See “Item 3. Legal Proceedings-Dux Litigation.”
Expansion of Eureka Hunter Gas Gathering System
In 2013, we expanded our Eureka Hunter Gas Gathering System, completing the construction of approximately 22 miles of additional pipeline in Monroe County, Ohio, for a total of over 100 miles of completed pipeline at January 31, 2014. In January 2013, we extended our Pursley lateral section of the pipeline (which is a 20-inch lateral section extending north from our main line) under the Ohio River from Wetzel County, West Virginia into Monroe County, Ohio. In December 2013, we completed our Tippens lateral section of the pipeline, which is a 20-inch lateral section that extends approximately 11 miles west-northwesterly from our Ohio river crossing near Sardis, Ohio, allowing for the gathering of dry Utica Shale gas production from multiple well pads, including our Stalder pad. We continue to construct the pipeline further into Ohio to support the continued development of our Marcellus Shale and Utica Shale acreage in Ohio, as well as acreage of third party producers.
Equity Financings
We raised cash in the total amount of $50.8 million in net proceeds, after offering discounts, commissions and placement fees, but before other offering expenses, through equity transactions from January 1, 2013 through December 31, 2013. Those transactions included:
•
$9.6 million in net proceeds from issuances of our Series D Preferred Stock, at an average gross sales price of $44.39 per share;
•
$0.6 million in net proceeds from issuances of Depositary Shares representing our Series E Preferred Stock, at an average gross sales price of $24.24 per Depositary Share;
•
$35.3 million in net proceeds from issuances of Series A Preferred Units of Eureka Hunter Holdings; and
•
$5.4 million in net proceeds from issuances of our common stock upon exercise of stock options.
We may continue selling both preferred and common equity in the future depending on our working capital needs, capital expenditure program, acquisition activities, and the condition of the capital markets. Until August 2014, approximately twelve months after the date on which we became current with our SEC reporting obligations, we are ineligible to use abbreviated and less costly SEC filings, such as the SEC's Form S-3 registration statement, to register our securities for sale. Further, during such period, we will be unable to use our existing shelf registration statement on Form S-3 or conduct “at-the-market”, or ATM, offerings of our equity securities, which ATM offerings we had conducted on a regular basis with respect to our preferred stock prior to our late SEC filings. We may use Form S-1 to register a sale of our securities to raise capital or complete acquisitions, but doing so would likely increase transaction costs and adversely impact our ability to raise capital or complete acquisitions in an expeditious manner.
Results of Operations
Years ended December 31, 2013, 2012 and 2011
The following table sets forth summary information regarding oil, natural gas and natural gas liquids revenues, production, average product prices and average production costs and expenses for the last three fiscal years. The results of our Eagle Ford Shale operations, MHP operations and Canadian operations have been excluded from the amounts below because they are reflected as discontinued operations for all years presented. See the “Glossary of Oil and Natural Gas Terms” section of this annual report for explanations of the terms used below.
_________________
(1)
General and administrative expense includes: (i) acquisition related expenses of $2.8 million ($0.77 Boe) in 2013, $4.7 million ($1.66 Boe) in 2012, and $8.9 million ($7.47 Boe) in 2011; and (ii) non-cash stock compensation of $13.6 million ($3.79 Boe) in 2013, $15.7 million ($5.54 Boe) in 2012, and $25.1 million ($21.02 Boe) in 2011.
Years ended December 31, 2013 and 2012
Oil and natural gas production. Production increased by 26.8%, or 760 MBoe, to 3,593 MBoe for the year ended December 31, 2013 compared to 2,833 MBoe for the year ended December 31, 2012. Our average daily production was 9,844 Boe/d during 2013, representing an overall increase of 27.2%, or 2,104 Boe/d, compared to 7,740 Boe/d for 2012. The increase in production in 2013 compared to 2012 is primarily attributable to acquisitions during 2012 as well as organic growth through the Company’s expanded drilling program in the Williston and Appalachian Basins which focused mainly on oil and NGL. Production for 2013, on a Boe basis, was 52.0% oil and NGL and 48.0% natural gas compared to 34.0% oil and NGL and 66.0% natural gas for 2012. The increase in production during the year ended December 31, 2013 was offset by the shut-in of approximately 2,061 Boe/d of Marcellus Shale production. In January 2013, the Company experienced production shut-ins due to complications in bringing our production online after the Mobley Processing Plant was completed in late 2012. The Company experienced higher than expected NGL present in its Marcellus production which necessitated that Eureka Hunter Pipeline implement a pigging process on 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. The gathering issues related to the Marcellus production shut-in were resolved in May 2013. In addition, our production for the year ended December 31, 2013 was also adversely affected by the shut down of the Mobley Processing Plant from August 2013 to early October 2013 as a result of a break in a MarkWest natural gas liquids pipeline. The impact of the Mobley Processing Plant shut down resulted in a decrease in our daily production by approximately 1,917 Boe/d for the year ended December 31, 2013. The Company also experienced approximately 144 Boe/d of curtailments for the year ended December 31, 2013 at its Ormet Pad location as a result of the continued build out of midstream infrastructure and liquids handling equipment. These production shut-ins were largely natural gas and NGL, thus the impact on the Company's cash flow was substantially less than any reduction in our oil volumes.
Oil and natural gas sales. Oil and natural gas sales from continuing operations increased 72.3%, or $82.9 million, for the year ended December 31, 2013 to $197.6 million from $114.7 million for the year ended December 31, 2012. The increase in oil and gas sales principally resulted from increases in our oil and natural gas production as a result of acquisitions and expanded drilling completed throughout the year in our unconventional resource plays. The average price we received for our production increased from $40.47 Boe to $55.00 Boe, or 35.9% primarily due to higher natural gas prices. The $82.9 million increase in revenues comprised an increase of approximately $30.8 million attributable to increased production volumes of 760 MBoe, and an increase of $52.2 million due to an increase in price of $14.53 Boe produced. The prices we receive for our products are generally tied to commodity index prices. We periodically enter into commodity derivative contracts in an attempt to offset some of the variability in prices (see the discussion of commodity derivative activities below).
Other income. Other revenues, consisting primarily of regulated retail gas billing revenues from the Appalachian region of the U.S. Upstream segment, increased by $3.4 million for the year ended December 31, 2013.
Lease operating expense. Our lease operating expenses, or LOE, increased $27.1 million, or 101.1%, for the year ended December 31, 2013 to $54.0 million ($15.02 Boe) from $26.8 million ($9.47 Boe) for the year ended December 31, 2012. The increase in LOE attributable to increased LOE/Boe was $19.9 million, and the increase related to increased volume produced was $7.2 million. Of the increase in LOE/Boe costs, $6.4 million was related to higher LOE costs in the Appalachian Basin due in part to an increased percentage of our production as NGL which generally have higher LOE/Boe than natural gas due to higher processing fees, $5.8 million was due to higher Appalachian Basin gas transportation charges, and $1.3 million was due to increased non-recurring workover and well site reclamation costs. Other costs increasing LOE/Boe include $3.7 million from the Williston Basin higher contribution to total production from higher cost stripper and non-operated properties along with $3.1 million of Williston Basin electrification implementation costs.
Severance taxes. Our severance taxes and marketing increased by $9.9 million, or 125.6%, for the year ended December 31, 2013 to $17.7 million from $7.9 million for the year ended December 31, 2012. The increase in production taxes and marketing was due to the increase in oil and gas sales as explained above.
Exploration. We record unproved property impairments, lease expirations, geological and geophysical costs, and exploratory dry hole costs (if any) as exploration expense. We recorded $97.3 million of exploration expense for the year ended December 31, 2013, compared to $78.2 million for the year ended December 31, 2012. During 2013, the Company’s exploration expense was primarily attributable to $95.9 million of impairments and expirations, which included $89.1 million and $6.8 million associated with the Company’s unproved properties in the Williston and Appalachian Basins, respectively, and $1.4 million of geological and geophysical costs. The Williston Basin amount is primarily due to current and expected future lease expirations in the large acreage position we initially acquired, as a result of our focus changing to other areas. The significant components of the Company’s 2012 exploration expense included unproved acreage impairments of $59.2 million, $15.0 million and $1.4 million relating to leases that expired or were expected expire in the Williston Basin, Appalachian Basin and south Texas areas, respectively, and $2.6 million of geological and geophysical costs.
Impairment of proved oil and gas properties. We review for impairment all long-lived assets, including proved oil and gas properties accounted for under the successful efforts method of accounting, and reduce the carrying value of these properties to their estimated fair values. In 2013, we recognized proved property impairment charges of $10.0 million consisting primarily of
$8.5 million in the Williston Basin and $1.2 million in the Appalachian Basin, as compared to proved property impairment charges of $3.8 million in 2012, primarily in the Williston Basin. Our impairments in 2013 were due to changes in production estimates and lease operating costs.
Midstream and marketing revenue. Revenue from the midstream operations segment (which, in 2013 and 2012, consisted of Eureka Hunter Pipeline, Magnum Hunter Marketing, and TransTex Hunter operations) increased by $53.6 million, or 341.7%, for the year ended December 31, 2013 to $69.3 million from $15.7 million for the year ended December 31, 2012. The increase by the company was as follows: TransTex Hunter - $5.7 million; Eureka Hunter Pipeline - $11.2 million and Magnum Hunter Marketing - $36.7 million. TransTex Hunter revenues increased through strong internal growth and the full year impact of the acquisition of the TransTex Gas Services assets in April 2012. Eureka Hunter Pipeline revenue increased as the result of the volume of natural gas product gathered by our pipeline gathering system which connected to the Mobley Processing Plant in December 2012. Eureka Hunter Pipeline gathered approximately 27.9 million MMBtu in 2013 compared with approximately 10.0 million MMBtu in 2012. Magnum Hunter Marketing revenue increased as a direct result of its primary customers increased volume through the Eureka Hunter Pipeline Gathering System plus the add on uplift revenue related to NGL from the Mobley Processing Plant.
Midstream and marketing expense. Midstream segment expense increased $55.4 million or 318.1% to $72.8 million for the year ended December 31, 2013 from $17.4 million for the year ended December 31, 2012 due to the costs associated with the increases in revenue.
Oilfield services revenue. Oilfield services revenue increased by 58.8% or $8.0 million, for the year ended December 31, 2013 to $21.5 million from $13.6 million for the year ended December 31, 2012. This increase was primarily attributable to a combination of additional rigs in service and higher utilization of the existing fleet. During the year period ended December 31, 2013, our drilling rig revenue days increased from 712 to 1,484 as compared to the year ended December 31, 2012, primarily as a result of the addition of 3 rigs to our fleet.
Oil field services expense. Oil field services expense increased $9.2 million or 74.2% to $21.6 million for the year ended December 31, 2013 from $12.4 million for the year ended December 31, 2012 due to the addition of 3 rigs to our fleet.
Depletion, depreciation, amortization and accretion. Our depletion, depreciation, amortization and accretion expense, or DDA&A, increased $39.5 million, or 66.1% to $99.2 million for the year ended December 31, 2013 from $59.7 million for the year ended December 31, 2012 due to increased production in 2013 and increases in property, plant and equipment as a result of our capital expenditures program and acquisitions. Our DDA&A/Boe increased by $6.53 or 31.0%, to $27.61 Boe for the year ended December 31, 2013, compared to $21.08 Boe for the year ended December 31, 2012. The increase in DDA&A per Boe was primarily attributable to the higher ratio of oil production versus natural gas, a higher depreciation component to the total DD&A due to the continued expansion of our midstream asset base and production from new wells in the Williston Basin which historically have a higher rate per BOE than our other production areas.
General and administrative. Our general and administrative expenses, or G&A, increased $22.0 million, or 41.1% to $75.4 million ($20.99 Boe) for the year ended December 31, 2013 from $53.5 million ($18.87 Boe) for the year ended December 31, 2012. G&A expenses increased overall during 2013 due to expansion activities of the Company. Non-cash stock compensation totaled approximately $13.6 million ($3.79 Boe) for the year ended December 31, 2013 and $15.7 million ($5.54 Boe) for the year ended December 31, 2012. The decrease in non-cash stock compensation was caused by the issuance of higher cost options being issued in the prior year, and a number of options which became fully vested during the two year period. Also included in G&A for 2013 are acquisition-related costs of $2.8 million ($0.77 Boe) for the 2013 period, which were for legal, consulting and other charges principally related to the divestiture of our Eagle Ford Shale assets. G&A expenses in 2013 also include expenses associated with the remediation of material weaknesses in internal controls that were reported in December 2012 . In 2012, we had $4.7 million ($1.66 Boe) of acquisition-related costs related to the acquisition of assets from Baytex Energy USA, Ltd. and the acquisition of all of the capital stock of Viking International Resources Co, Inc.
Interest expense. Our interest expense increased by 40.3%, from $51.6 million for the year ended December 31, 2012 to $72.4 million for the year ended December 31, 2013. Our higher average debt level during 2013 primarily accounted for $23.4 million of the increase, and this was offset by $2.6 million of lower amortization of financing costs related to our senior notes, our revolving credit facility, Alpha Hunter Drilling’s outstanding term loan, Eureka Hunter Pipeline’s outstanding term loan and our now paid-off term loan. Interest on projects lasting six months or greater is capitalized. In 2013 and 2012, $2.6 million and $4.4 million of interest was capitalized, respectively. We did not capitalize interest in 2011.
Commodity and financial derivative activities. We record our open derivative instruments at fair value on our consolidated balance sheets as either current or long term assets or liabilities, depending on the timing of expected cash flows. We record all gains and losses on settled and open transactions on our consolidated statements of operations under the caption entitled “Gain (loss) on derivative contracts, net”. Our loss on settled transactions during 2013 was $8.2 million compared with a gain on settled transactions of $11.3 million in 2012. Our loss on open transactions in 2013 was $17.1 million compared with a gain on transactions in 2012 of $10.9 million.
Gains and losses on settled transactions are derived from the relative movement of oil and gas prices on the products we sell in relation to the range of prices in our derivative contracts for the respective years. As commodity prices increase, the fair value of the open portion of those positions decreases, and vice versa. As commodity prices decrease, the fair value of the open portion of those positions increases. We continue not to designate our derivative instruments as cash-flow hedges for 2013 and 2012.
At December 31, 2013, the Company had preferred stock embedded derivative liabilities resulting from certain conversion features, redemption options, and other features of our Series A Convertible Preferred Units of Eureka Hunter Holdings. See "Note 4 - Financial Instruments and Derivatives" and "Note 11 - Redeemable Preferred Stock". This contract resulted in an unrealized loss of $17.7 million in 2013. Also at December 31, 2013, the Company had an embedded derivative asset related to a convertible security, primarily due to the conversion feature of the promissory note received as partial consideration for the sale of Hunter Disposal, LLC. See "Note 4 - Financial Instruments and Derivatives", "Note 2 - Divestitures and Discontinued Operations" and "Note 16 - Related Party Transactions". An unrealized loss of $0.2 million is recorded for this contract in 2013. Both contracts originated in 2012 and have resulted in no cash outlays as of December 31, 2013.
The following table summarizes the gains and losses on settled and open transactions on change in fair value of our derivative contracts as of the dates indicated:
Deferred tax benefit The Company recorded a net deferred tax benefit at the applicable statutory rates of $70.3 million and $19.3 million during the years ended December 31, 2013 and 2012, respectively, as a result of the operating losses incurred on its continuing operations. The Company recorded less than its expected deferred tax benefit at statutory rates for both periods because of increases in its deferred tax asset valuation allowance.
Loss from continuing operations. We incurred net losses from continuing operations of $204.1 million and $119.7 million in 2013 and 2012, respectively. Our 2013 revenues increased $140.1 million to $280.4 million compared to $140.4 million in 2012. However, this increase was more than offset by increases in operating expenses. Our 2013 operating loss increased $76.6 million, to $184.8 million, compared to $108.2 million in 2012. The increase in the loss is principally due to an increase in loss on sales of assets of $44.0 million related to the sales of properties in North Dakota, an increase in exploration and abandonment expense of $19.1 million, related to the expiration of leases we chose not to develop, increased depreciation, depletion, amortization and accretion costs of $39.5 million, related to capital expenditures, including acquisitions, of $570.7 million and $1.1 billion in 2013 and 2012, respectively, and an increase in interest expense of $20.8 million related to increased borrowing, partially offset by a gain on derivative contracts of $25.3 million. In 2013, non-cash stock compensation expense decreased to $13.6 million from $15.7 million in 2012, and acquisition related expenses decreased to $2.8 million from $4.7 million in 2012.
Income (loss) from discontinued operations, net of tax. On February 17, 2012, we closed the sale of Hunter Disposal, LLC, previously a wholly owned subsidiary. We have reclassified $0.2 million of net operating income of the divested subsidiary to discontinued operations for the year ended 2012. We have also reclassified the gain on sale of $2.4 million to discontinued operations for the year ended December 31, 2012. On April 24, 2013, we closed on the sale of all of our ownership interest in a wholly-owned subsidiary, Eagle Ford Hunter, Inc. to Penn Virginia. In September 2013, the Company adopted a plan to divest all of its interests in its southern Appalachian Basin assets and its Canadian assets. The Company has reflected these operations as discontinued operations, net of taxes, for all periods presented. Tax benefit recognized as a result of discontinued operations was $3.3 million and $2.3 million for years ended December 31, 2013 and 2012, respectively.
Income (loss) from discontinued operations, net of tax was $71.1 million and $19.5 million for the years ended December 31, 2013 and 2012, respectively. The following table summarizes the income (loss) from discontinued operations as of the dates indicated:
Gain on disposal of discontinued operations, net of tax. Gain on disposal of discontinued operations was $52.0 million and $2.4 million for the years ended December 31, 2013 and 2012, respectively. The following table summarizes the gain on disposal of discontinued operations as of the dates indicated:
Net income (loss) attributable to non-controlling interest. Net loss attributable to non-controlling interest was $1.0 million in 2013 versus net income of $4.0 million in 2012. This represents 12.5% of the net income or loss incurred by our subsidiary, PRC Williston, LLC, and 1.9% and 2.5% at December 31, 2013 and 2012, respectively, of the net loss incurred by our subsidiary, Eureka Hunter Holdings. We record a non-controlling interest in the results of operations of PRC Williston, LLC because we are contractually obligated to make distributions to the holders of a non-controlling interest in this subsidiary whenever we make distributions to ourselves from this subsidiary.
Dividends on preferred stock. Dividends on our Series C, Series D, and Series E Preferred Stock and the Series A Convertible Preferred Units of Eureka Hunter Holdings were $56.7 million in 2013 versus $34.7 million in 2012. The Series E Preferred Stock had a stated value of $95.1 million and $94.4 million as of December 31, 2013 and 2012, respectively, and carries a cumulative dividend rate of 8.0% per annum. The Series D Preferred Stock had a stated value of $221.2 million and $210.4 million at December 31, 2013 and 2012, respectively, and carries a cumulative dividend rate of 8.0% per annum. The Series C Preferred Stock had a stated value of $100.0 million at December 31, 2013 and 2012, and carries a cumulative dividend rate of 10.25% per annum. The Series A Convertible Preferred Units of Eureka Hunter Holdings had a liquidation preference of $200.6 million and $167.4 million as of December 31, 2013 and 2012, respectively, and carry a cumulative dividend rate of 8.0% per annum.
Net loss attributable to common shareholders. Net loss attributable to common shareholders was $278.9 million in 2013 versus $167.4 million in 2012. Our net loss per common share, basic and diluted, was $1.64 per share in 2013 compared to $1.07 per share in 2012. Our weighted average shares outstanding increased by 14.3 million shares, or 9%, to approximately 170.1 million shares, principally as a result of the shares issued for cash which allowed us to procure financing for the Baytex acquisition. Our net loss per share from continuing operations was $1.53 per share for the year ended December 31, 2013, compared to a loss from continuing operations of $0.97 per share for the year ended December 31, 2012.
Years ended December 31, 2012 and 2011
Oil and natural gas production. Production from continued operations increased by 137.7%, or 1,641 MBoe, to 2,833 MBoe for the year ended December 31, 2012 from 1,192 MBoe for the year ended December 31, 2011. Production for 2012, on a Boe basis, was 34.0% oil and NGL and 66.0% natural gas compared to 36.1% oil and NGL and 63.9% natural gas for 2011. Our average daily production was 7,740 Boe/d during 2012 compared to 3,266 Boe/d for 2011 representing an overall increase of 137.0%, or 4,474 Boe/d. The increase in production in 2012 compared to 2011 is primarily attributable to acquisitions as well as organic growth as a result of the Company’s expanded drilling program.
Oil and gas sales. Oil and gas sales increased 95.2%, or $55.9 million, for the year ended December 31, 2012 to $114.7 million from $58.7 million for the year ended December 31, 2011. The increase in oil and gas sales principally resulted from increases in our oil and natural gas production as a result of acquisitions and new drilling completed throughout the year in the unconventional resource plays. The average price we received for our production decreased from $49.27 Boe to $40.47 Boe, or 17.9%. Of the $55.9 million increase in revenues, a decrease of approximately $24.9 million net was attributable to an increase in oil prices net with a decrease in gas prices, and $80.9 million was attributable to the increase in production volumes of 1,641 MBoe in 2012. The prices we receive for our products are generally tied to commodity index prices. We periodically enter into commodity derivative contracts in an attempt to offset some of the variability in prices (see the discussion of commodity derivative activities below).
Other income. Other revenues, consisting primarily of regulated retail gas billing revenues from the Appalachian region of the U.S. Upstream segment, increased by $238,000 for the year ended December 31, 2012.
Lease operating expense. Our lease operating expenses, or LOE, increased $11.8 million, or 79.0%, for the year ended December 31, 2012 to $26.8 million ($9.47 Boe) from $15.0 million ($12.58 Boe) for the year ended December 31, 2011. The increase in total LOE is attributable to increased volume produced, which accounted for an increase in cost of $20.6 million, reduced by lower cost per Boe produced, which offset the volume effect by $8.8 million. The decrease in overall LOE per Boe cost is due to the impact of the lower per Boe cost of the new production brought on line during 2012 through our ongoing drilling program in our unconventional resource plays.
Severance taxes and marketing. Our severance taxes and marketing increased by $2.5 million, or 47.1%, for the year ended December 31, 2012 to $7.9 million from $5.3 million for the year ended December 31, 2011. The increase in production taxes and marketing was due to the increased oil and gas sales as explained above.
Exploration. We record unproved property impairments, geological and geophysical costs, and dry hole costs (if any) as exploration expense. The significant components of the Company’s 2012 exploration expense included unproved acreage impairments of $59.2 million, $15.0 million and $1.4 million in the Williston Basin, Appalachian Basin and south Texas areas, respectively. The Williston Basin impairment is primarily due to the results to date in the large acreage position we initially acquired, which led us to focus on other areas, thereby letting certain acreage expire in that region. In 2011, we incurred impairment charges associated with our undeveloped acreage of $0.3 million and $0.8 million in our south Texas and Appalachian Basin regions, respectively, due to expiring acreage that we chose not to develop. We recorded $2.6 million of geological and geophysical exploration expense for the year ended December 31, 2012, compared to $1.5 million for the year ended December 31, 2011. We experienced higher geological and geophysical costs in 2012 as a result of the increased exploration activity.
Impairment of proved oil and gas properties. We review for impairment our long-lived assets to be held and used, including proved oil and gas properties accounted for under the successful efforts method of accounting. As a result of this review of the recoverability of the carrying value of our assets, we recorded an impairment of oil and gas properties of $3.8 million and $0 for 2012 and 2011, respectively.
Midstream and marketing revenue. Revenue from the midstream operations segment (which, in 2011 consisted solely of the Eureka Hunter Pipeline operations) increased by $13.7 million, or 688.5%, for the year ended December 31, 2012 to $15.7 million from $2.0 million for the year ended December 31, 2011. The increase in revenues is the result of TransTex Gas Services being acquired on April 2,2012 which had 2012 revenues of $7.0 million plus the increased volume of natural gas products gathered by the pipeline system, as Eureka Hunter Pipeline gathered approximately 10 million MMBtu in 2012 in conjunction with the corresponding growth of natural gas sold thru Magnum Hunter Marketing.
Midstream and marketing expense. Midstream and marketing expense increased $14.9 million or 593.4% to $17.4 million for the year ended December 31, 2012 from $2.5 million for the year ended December 31, 2011 due the acquisition of TransTex Gas Services in April 2012 plus the increased volume of natural gas products gathered by the Eureka Hunter Pipeline system in conjunction with the growth of natural gas sold thru Magnum Hunter Marketing.
Oilfield services revenue. Oilfield services revenue increased by 43.8%, or $4.1 million, for the year ended December 31, 2012 to $13.6 million from $9.4 million for the year ended December 31, 2011. Oilfield services revenues are comprised of drilling services from continuing operations.
Oil field services expense. Oil field services expense increased $3.1 million or 33.1% to $12.4 million for the year ended December 31, 2012 from $9.3 million for the year ended December 31, 2011 due to the costs associated with the increases in revenue.
Depletion, depreciation, amortization and accretion. Our depletion, depreciation, amortization and accretion expense, or DDA&A, increased $36.5 million, or 156.9% to $59.7 million for the year ended December 31, 2012 from $23.2 million for the year ended December 31, 2011 due to increases in property, plant and equipment as a result of our capital expenditures program and acquisitions, and increased production in 2012. Our DDA&A per Boe increased by $1.58, or 8.1%, to $21.08 per Boe for the year ended December 31, 2012, compared to $19.50 Boe for the year ended December 31, 2011. The increase in DDA&A per
Boe was primarily attributable to production from newer wells coming online during the year in the Marcellus Shale and Williston Basin at a higher cost to drill and complete than wells completed in prior years.
General and administrative. Our general and administrative expenses, or G&A, decreased $0.9 million, or 1.7%, to $53.5 million ($18.87 Boe) for the year ended December 31, 2012 from $54.4 million ($45.60 Boe) for the year ended December 31, 2011. G&A expenses increased overall during 2012 due to expansion activities of the Company. Non-cash stock compensation totaled approximately $15.7 million ($5.54 Boe) for the year ended December 31, 2012 and $25.1 million ($21.02 Boe) for the year ended December 31, 2011. The decrease in non-cash stock compensation was caused by the issuance of fewer stock options in total, and the stock options that were issued had longer vesting terms than the options issued during the prior year. Also included in G&A for 2012 are acquisition-related costs of $4.7 million ($1.66 Boe) for the 2012 period, which were for legal, consulting, and other charges principally related to the acquisition of assets from Baytex Energy USA, Ltd. and the acquisition of all of the capital stock of Viking International Resources Co., Inc. In 2011, we had $8.9 million ($7.47 Boe) of acquisition-related costs, which were for legal, consulting and other charges principally related to the acquisition of NuLoch Resources, Inc.
Interest expense, net. Our interest expense, net of interest income, increased $39.9 million, or 339.2%, to $51.6 million for the year ended December 31, 2012 from $11.8 million for the year ended December 31, 2011. Our higher average debt level during 2012 accounted for $31.7 million of the increase, the remaining $8.1 million is the result of the amortization of financing costs related to our senior notes, our revolving credit facility, Eureka Hunter Pipeline's outstanding term loan and our now paid-off term loan. Interest on projects lasting six months or greater is capitalized. In 2012, $4.4 million of interest was capitalized. We did not capitalize interest in 2011 or 2010.
Commodity and financial derivative activities. Our gain or loss from settled and open derivative contracts was a gain of $22.2 million and a loss of $6.3 million for the years ended December 31, 2012 and 2011, respectively. The following table summarizes the gains and losses on settled and open derivative contracts as of the dates indicated:
Deferred tax benefit. The Company recorded a net deferred tax benefit at the applicable statutory rates of $19.3 million and $2.9 million during the years ended December 31, 2012 and 2011, respectively, as a result of the operating losses incurred on its continuing operations. The Company recorded less than its expected deferred tax benefit at statutory rates for both periods because of increases in its deferred tax asset valuation allowance.
Loss from continuing operations. We incurred net losses from continuing operations of $119.7 million and $56.8 million in 2012 and 2011, respectively, for an increase of $62.8 million in loss, or 110.6%. Our 2012 revenues increased $73.9 million to $140.4 million compared to $66.5 million in 2011. However, this increase was more than offset by increases in operating expenses. Our 2012 operating loss increased $66.6 million, to $108.2 million, compared to $41.6 million in 2011. The increase in the loss is principally due to an increase in exploration and abandonment expense of $75.6 million, related to the expiration of leases we chose not to develop, increased depreciation, depletion, amortization and accretion costs of $36.5 million related to capital expenditures of $1.1 billion and $370.5 million in 2012 and 2011, respectively, and an increase in interest expense of $39.9 million related to increased borrowing, partially offset by a gain on derivative contracts of $22.2 million. In 2012, non-cash stock compensation expense decreased to $15.7 million from $25.1 million in 2011, and acquisition related expenses decreased to $4.7 million from $8.9 million in 2011.
Income from discontinued operations. On February 17, 2012, we closed the sale of Hunter Disposal, LLC, previously a wholly owned subsidiary. We have reclassified $0.2 million and $1.9 million of income of the divested subsidiary to discontinued operations during the years ended December 31, 2012 and 2011, respectively. We have also reclassified the gain on sale of $2.4 million to discontinued operations for the year ended December 31, 2012.
On April 24, 2013, we closed on the sale of all of our ownership interest in a wholly-owned subsidiary, Eagle Ford Hunter, Inc. to Penn Virginia. In September 2013, the Company adopted a plan to divest all of its interests in its southern Appalachian Basin assets and its Canadian assets. The Company has reflected these operations as discontinued operations, net of taxes, for all periods presented. We have reclassified $19.7 million and $21.5 million of net operating loss of these divested subsidiaries to discontinued operations for the years ended December 31, 2012 and 2011, respectively.
Income (loss) from discontinued operations, net of tax was $19.5 million and $19.6 million for the years ended December 31, 2012 and 2011, respectively. The following table summarizes the income (loss) from discontinued operations as of the dates indicated:
Gain on disposal of discontinued operations, net of tax. Gain on disposal of discontinued operations was $2.4 million, resulting from the sale of Hunter Disposal, and none for the years ended December 31, 2012 and 2011, respectively.
Net loss (income) attributable to non-controlling interest. Net loss attributable to non-controlling interest was $4.0 million in 2012 versus net income of $0.2 million in 2011. This represents 12.5% of the net income or loss incurred by our subsidiary, PRC Williston, LLC and 2.5% of the net loss incurred by our subsidiary, Eureka Hunter Holdings. We record a non-controlling interest in the results of operations of PRC Williston, LLC because we are contractually obligated to make distributions to the holders of a non-controlling interest in this subsidiary whenever we make distributions to ourselves from the subsidiary.
Dividends on preferred stock. Dividends on our Series C, Series D, and Series E Preferred Stock and the Series A Convertible Preferred Units of Eureka Hunter Holdings were $34.7 million in 2012 versus $14.0 million in 2011. The Series E Preferred Stock had a stated value of $94.4 million and none outstanding as of December 31, 2012 and 2011, respectively, and carries a cumulative dividend rate of 8.0% per annum. The Series D Preferred Stock had a stated value of $210.4 million and $71.9 million at December 31, 2012 and 2011, respectively, and carries a cumulative dividend rate of 8.0% per annum. The Series C Preferred Stock had a stated value of $100.0 million at December 31, 2012 and 2011, respectively, and carries a cumulative dividend rate of 10.25% per annum. The Series A Convertible Preferred Units of Eureka Hunter Holdings had a liquidation preference of $167.4 million and zero as of December 31, 2012 and 2011, respectively, and carry a cumulative dividend rate of 8.0% per annum.
Net loss attributable to common shareholders. Net loss attributable to common shareholders was $167.4 million in 2012 versus $90.7 million in 2011. Our net loss per common share, basic and diluted, was $1.07 per share in 2012 compared to $0.80 per share in 2011. Our weighted average shares outstanding increased by 42.6 million shares, or 37.6%, to approximately 155.7 million shares, principally as a result of the shares issued for cash which allowed us procure financing for the Baytex Energy assets acquisition. Our net loss per share from continuing operations was $0.96 per share for the year ended December 31, 2012, compared to a loss from continuing operations of $0.63 per share for the year ended December 31, 2011.
Liquidity and Capital Resources
We generally rely on cash generated from operations, borrowings under our revolving credit facility and, to the extent that credit and capital market conditions will allow, future public and private equity and debt offerings to satisfy our liquidity needs. Our ability to fund planned capital expenditures and to make acquisitions depends upon our future operating performance, availability of borrowings under our revolving credit facility, and more broadly, the availability of equity and debt financing, which is affected by prevailing economic conditions in our industry and financial, business and other factors, some of which are beyond our control. We cannot predict whether additional liquidity from equity or debt financings beyond our revolving credit facility will be available or available on terms acceptable to us, or at all, in the foreseeable future.
Our cash flow from operations is driven by commodity prices and production volumes and the effect of commodity derivatives. Prices for oil and natural gas are affected by national and international economic and political environments, national and global supply and demand for hydrocarbons, seasonal influences of weather and other factors beyond our control. Our working capital is significantly influenced by changes in commodity prices, and significant declines in prices will cause a decrease in our production volumes and exploration and development expenditures. Cash flows from operations are primarily used to fund exploration and development of our oil and gas properties.
We utilize our credit agreements to fund a portion of our operating and capital needs. The Company had $218.0 million of outstanding debt and letters of credit totaling $7.2 million under our revolving credit facility at December 31, 2013, with available borrowing capacity at that date of $17.3 million.
As of December 31, 2013, we were in compliance with all of our covenants, as amended or waived, contained in our credit agreements as described in "Note 8 - Long-Term Debt".
We believe the combination of (i) cash on hand, (ii) cash flow generated from the expected success of prior capital development projects, (iii) capital market related funding, (iv) borrowing capacity available under our credit facilities, and (v) anticipated sales of non-core assets will provide sufficient means to conduct our operations, meet our contractual obligations, including our debt covenant requirements, as amended, and complete our budgeted capital expenditure program for the remainder of 2014.
For the year ended December 31, 2013, our primary sources of cash were from operating activities, proceeds from asset sales, and cash on hand at the beginning of the year. We utilized $111.7 million of cash provided by operating activities, $57.6 million of cash on hand, $506.3 million of proceeds from the sale of assets, $374.0 million of borrowings under our revolving credit facility and other debt agreements, and $35.3 million from the issuance of Series A Preferred Units of Eureka Hunter Holdings to fund our acquisitions and drilling program, repay debt, and pay $40.6 million in dividends on our preferred stock.
For the year ended December 31, 2012, our primary sources of cash were from financing activities and cash on hand at the beginning of the year. Approximately $596.9 million of cash was provided by senior note issuances, along with $546.0 million of borrowings under our revolving credit facility and other debt agreements, while we repaid $542.7 million outstanding under our revolving credit facility and other debt agreements, for the year ended December 31, 2012. During such year, we funded our acquisitions and drilling program, repaid debt under our revolving credit facility and paid deferred financing costs related to such facility using net proceeds of $149.7 million from the issuance of Series A Preferred Units of Eureka Hunter Holdings; net proceeds of $148.2 million from our issuance of common stock; net proceeds of $122.4 million from our issuance of Series D Preferred Stock; net proceeds of $22.2 million from our issuance of Depositary Shares evidencing our Series E Preferred Stock; $57.6 million of cash on hand; and $2.9 million of proceeds from the sale of assets.
For the year ended December 31, 2011, our primary sources of cash were from financing activities, proceeds from asset sales and cash on hand at the beginning of the year. Approximately $116.3 million of cash from sales of common and preferred stock and the proceeds from exercises of warrants, along with $493.9 million of borrowings under our revolving credit facility, $8.7 million of proceeds from sale of assets, and $14.9 million of cash on hand, were used to fund our acquisitions and drilling program, repay debt under our revolving credit facility, and pay deferred financing costs related to our credit facility.
The following table summarizes our sources and uses of cash for the periods noted:
We define liquidity as funds available under our revolving credit facility plus year-end cash and cash equivalents, excluding amounts held by our unrestricted subsidiaries under our revolving credit facility, which was $8.0 million and $36.3 million at December 31, 2013 and 2012, respectively. At December 31, 2013, we had $218.0 million in long-term debt outstanding under our revolving credit facility, compared to $225.0 million in long-term debt outstanding under this facility at December 31, 2012.
The following table summarizes our liquidity position at December 31, 2013 compared to December 31, 2012:
Factors that will affect our liquidity in 2014 include proceeds from the planned divestitures of our southern Appalachian Basin operations and our Canadian operations, payments to Penn Virginia in settlement of purchase price adjustments, and expected increases in operating cash flows on our remaining assets as a result of the successful results of our 2013 drilling program and acquisitions. On December 31, 2013, the Company’s borrowing base under our revolving credit facility was $242.5 million. With respect to the effect of our late SEC filings on liquidity, see "Effect of Late SEC Filings on Liquidity and Capital Resources."
We intend to fund 2014 capital expenditures, excluding any acquisitions, from a combination of internally-generated cash flows, capital market related funding, borrowings under our revolving credit facility, an anticipated new Eureka Hunter Pipeline senior secured credit facility in the process of negotiation, and proceeds from non-core asset sales. As of December 31, 2013, we had $17.3 million available to borrow under our revolving credit facility. At December 31, 2013, the Company was in compliance with covenants under this credit facility, as amended or waived, as described in "Note 8 - Long-Term Debt".
Operating Activities
Net cash provided by operating activities for the years ended December 31, 2013, 2012 and 2011 was $111.7 million, $58.0 million and $33.8 million, respectively. The increases in net cash provided by operating activities were primarily due to increases in oil and gas sales in each year and derivative gains on settled transactions in 2012. In 2012, cash flow provided by operating activities included net income of $2.6 million from discontinued operations, which included the gain of $2.2 million. These discontinued operations will not have a material impact on future cash flows from operating activities.
Investing Activities
Our cash used in investing activities for the year ended December 31, 2013 was $127.9 million, principally from acquisition and drilling activities. We used $24.5 million in cash for our Utica Shale property acquisition, and $607.0 million in cash for drilling and other capital expenditures under our 2013 capital expenditures budget. Also during the year ended December 31, 2013, we received $506.3 million in cash proceeds, net of working capital adjustments, from the sales of our Eagle Ford properties and certain North Dakota non-core properties.
Net cash used in investing activities during 2012 was $1.0 billion, as compared to net cash used in investing activities of $361.7 million during 2011. The increase in net cash flow used in investing activities during 2012, as compared to 2011, is primarily due to (i) a $366.3 million increase in cash paid for acquisition of assets (primarily attributable to our acquisition of assets from Baytex Energy and our acquisition of the stock of Viking International Resources Co., Inc.), (ii) a $276.7 million increase in additions to oil and gas properties associated with the Company's capital programs, and (iii) the $4.5 million decrease in proceeds received from the sale of assets. During the year ended December 31, 2012, the Company's investing activities were funded by net cash provided by operating activities, cash on hand, borrowings under long-term debt, and issuances of preferred shares.
Capital expenditures of $291.9 million in 2011 were comprised of (i) $267.5 million for capital expenditures under our 2011 capital expenditures budget, (ii) $78.5 million for acquisitions of assets (primarily related to the NGAS acquisition), and (iii) proceeds from the sale of assets of $8.7 million.
Financing Activities
As a result of our failure to file our 2012 Form 10-K and First Quarter 2013 Form 10-Q within the time frames required by the SEC, we may be limited in our ability to access the public markets to raise debt or equity capital, which could prevent us from pursuing transactions or implementing business strategies that would be beneficial to our business. Until we have timely filed all our required SEC reports for a period of twelve months, we will be ineligible to use abbreviated and less costly SEC filings, such as the SEC's Form S-3 registration statement, to register our securities for sale. Further, during such period, we will be unable to use our existing shelf registration statement on Form S-3 or conduct ATM offerings of our equity securities, which ATM offerings we had conducted on a regular basis with respect to our preferred stock prior to our delinquent SEC filings. We may use Form S-1 to register a sale of our securities to raise capital or complete acquisitions, but doing so would likely increase transaction costs and adversely impact our ability to raise capital or complete acquisitions in an expeditious manner. We expect to remain timely with respect to our SEC reports, and, if so, we will become a Form S-3 eligible issuer again in August 2014.
Net cash provided by financing activities was $0.7 million, $996.4 million and $342.2 million during 2013, 2012, and 2011 respectively. During 2013 the significant components of financing activities included $374.0 million borrowings under our credit facilities and other debt agreements, and proceeds of $10.1 million from the sale of preferred shares, and $5.4 million from the exercise of common stock options and warrants. Also during 2013, we repaid $380.9 million of amounts outstanding under our revolving credit facility, paid dividends of $40.6 million and used cash of $1.2 million for payment of deferred financing costs.
During 2012, the significant components of financing activities included (i) $596.9 million of in net proceeds from the issuance of our senior notes, (ii) $546.0 million in net proceeds on borrowings on debt, and (iii) the issuance of 7,590,000 shares of the Series A Preferred Units of Eureka Hunter Holdings for net proceeds of $149.7 million, 35,000,000 shares of common stock for net proceeds of $148.2 million, 2,771,263 shares of our Series D Preferred Stock for net proceeds of $122.4 million, and 1,000 shares of our Series E Preferred Stock for net proceeds of $22.2 million, and (iv) $2.3 million from the exercises of stock options and warrants. These items were partially offset by cash used in financing activities of $26.8 million to pay dividends, $20.3 million in deferred financing costs, and $1.8 million to settle a contingency related to the the acquisition of Viking International Resources Co., Inc., after which 70 shares of our Series E Preferred Stock placed in escrow were released and included in treasury shares.
During 2011 the significant components of financing activities included $493.9 million borrowings under our credit facilities and other debt agreements, and proceeds of $94.8 million from the sale of preferred shares, $13.9 million from the sale of common stock, and $7.6 million from the exercise of common stock options and warrants. Also during 2011, we repaid $242.5 million of amounts outstanding under our revolving credit facility, paid dividends of $14.0 million and used cash of $11.6 million for payment of deferred financing costs.
As of December 31, 2013, we had $600 million aggregate principal amount of our senior notes outstanding. In connection with the May and December 2012 offerings of the senior notes, we entered into registration rights agreements pursuant to which we agreed to complete, by May 16, 2013, a registered exchange offer of the senior notes for the same principal amount of a new issue of senior notes with substantially identical terms, except the new senior notes would be registered and generally freely transferable under the Securities Act. We completed the registered exchange offer in November 2013. As a result of our failure to complete the exchange offer for our senior notes by May 16, 2013, we paid penalty interest on the senior notes from May 16, 2013 until the completion of the exchange offer in November 2013.
Equity and Debt Financings
We raised substantial cash in the total amount of $50.8 million in net proceeds, after offering discounts, commissions and placement fees, but before other offering expenses, through equity and debt transactions from January 1, 2013 through January 31, 2014. Those transactions included:
•
$9.6 million in net proceeds from issuances of our Series D Preferred Stock, at an average gross sales price of $44.39 per share;
•
$0.6 million in net proceeds from issuances of Depositary Shares representing our Series E Preferred Stock, at an average gross sales price of $24.24 per Depositary Share;
•
$35.3 million in net proceeds from issuances of Series A Preferred Units of Eureka Hunter Holdings, and
•
$5.4 million in net proceeds from the exercise of common stock warrants and options.
We plan to continue raising both preferred and common equity in the future depending on our working capital needs, capital expenditure program, acquisition activities, the condition of the capital markets and our ability to access the capital markets given the restrictions on our capital raising activities resulting from our late SEC filings. See "Effect of Late SEC Filings on Liquidity and Capital Resources."
2014 Capital Expenditures Budget
The following table summarizes our estimated capital expenditures (excluding acquisitions) for 2014. We intend to fund 2014 capital expenditures, excluding any acquisitions, from a combination of internally-generated cash flows, capital market related funding, borrowings under our revolving credit facility, an expected new Eureka Hunter Pipeline senior secured credit facility in the process of negotiation, and proceeds from non-core asset sales.
________________________________
(1)Expected to be financed through equity and debt facilities that are non-recourse to Magnum Hunter, and Company capital contributions.
Our capital expenditure budget for 2014 is subject to change depending upon a number of factors, including economic and industry conditions at the time of drilling, prevailing and anticipated prices for oil and gas, the results of our development and exploration efforts, the availability of sufficient capital resources for drilling prospects, our financial results, the availability of leases on reasonable terms and our ability to obtain permits for the drilling locations.
Credit Facilities
Revolving Credit Facility
On December 13, 2013, we entered into a Third Amended and Restated Credit Agreement, or the Credit Agreement, by and among us, Bank of Montreal, as Administrative Agent, the lenders party thereto and the agents party thereto. The Credit Agreement amended and restated that certain Second Amended and Restated Credit Agreement, dated as of April 13, 2011, by and among such parties, as amended, or the Prior Credit Agreement. The terms of the Credit Agreement are substantially similar to the Prior Credit Agreement.
The Credit Agreement provides for an asset-based, senior secured revolving credit facility maturing April 13, 2016, referred to as our revolving credit facility. As of December 31, 2013 the borrowing base under our revolving credit facility was $242.5 million. Our revolving credit facility is governed by a semi-annual borrowing base redetermination derived from our proved crude oil and natural gas reserves, and based on such redeterminations, the borrowing base may be decreased or increased up to a maximum commitment level of $750 million. The borrowing base is subject to such periodic redeterminations commencing May 1, 2014.
The terms of the Credit Agreement provide that our revolving credit facility may be used for loans, and subject to a $10,000,000 sublimit, letters of credit. The Credit Agreement provides for a commitment fee of 0.5% of the unused portion of the borrowing base and commitments under our revolving credit facility.
Borrowings under our revolving credit facility will, at our election, bear interest at either (i) an alternate base rate (“ ABR”) equal to the highest of (A) the Prime Rate (as defined in the Credit Agreement) in effect on such day, (B) the Federal Funds Effective Rate (as defined in the Credit Agreement) in effect on such day, plus 0.5% per annum, and (C) the LIBO Rate (as defined in the Credit Agreement) for a one month interest period on such day, plus 1.00% or (ii) the Adjusted LIBO Rate (as defined in the Credit Agreement) for one, two, three, six or twelve months (as we may elect), plus, in each of the cases described in clauses (i) and (ii), an applicable margin ranging from 1.5% to 2.25% for ABR loans and from 2.5% to 3.25% for Adjusted LIBO Rate loans. Overdue amounts shall bear interest at a rate equal to 2.00% per annum plus the rate applicable to ABR loans.
The Credit Agreement contains negative covenants that, among other things, restrict our ability and our restricted subsidiaries’ ability to, with certain exceptions, (i) incur indebtedness, (ii) grant liens, (iii) make certain payments, (iv) change the nature of our or its business, (v) dispose of all or substantially all of our or its assets or enter into mergers, consolidations or similar transactions, (vi) make investments, loans or advances, (vii) pay dividends, unless certain conditions are met, and with respect to the payment of dividends on preferred stock, subject to (A) no Event of Default (as defined in the Credit Agreement) existing, (B) after giving effect to any such preferred stock dividend payment, the Company maintaining availability under the borrowing base in an amount greater than the greater of (x) 2.50% percent of the borrowing base then in effect or (y) $5,000,000 and (C) a “basket” of $45,000,000 per year, and (viii) enter into transactions with affiliates.
In addition, the Credit Agreement requires us and our restricted subsidiaries to satisfy certain financial covenants, including maintaining:
(i) a ratio of consolidated current assets to consolidated current liabilities of not less than 1.0 to 1.0 as of the last day of any fiscal quarter (which 1.0 to 1.0 financial covenant ratio was waived for the quarter ended December 31, 2013, as a result of our compliance with a less restrictive ratio for that quarter);
(ii) a ratio of EBITDAX (as defined in the Credit Agreement) for the trailing four fiscal quarter period then ended to Interest Expense (as defined in the Credit Agreement) for such period of not less than (A) 2.00 to 1.00 for the fiscal quarter ending December 31, 2013, (B) 2.25 to 1.00 for the fiscal quarter ending March 31, 2014 and (C) 2.50 to 1.00 for the fiscal quarter ending June 30, 2014 and for each fiscal quarter ending thereafter; provided that solely for calculating such ratio for the fiscal quarter ending December 31, 2013, EBITDAX and Interest Expense for that fiscal quarter shall be calculated on an actual basis without giving effect to any pro forma adjustments;
(iii) beginning with the fiscal quarter ending June 30, 2014, a ratio of total debt to EBITDAX for the trailing four fiscal quarter period then ended of not more than (A) 4.50 to 1.0 for the fiscal quarters ending June 30, 2014 and September 30, 2014 and (B) 4.25 to 1.0 for the fiscal quarter ending December 31, 2014 and for each fiscal quarter ending thereafter; and
(iv) as of the last day of any fiscal quarter period ending through March 31, 2014, a ratio of total debt (less the outstanding principal amount of the Company’s 9.750% Senior Notes due 2020) to EBITDAX for the trailing four fiscal quarter period then ended of not more than 2.00 to 1.00.
At December 31, 2013, we were in compliance with all of our covenants, as amended or waived, contained in our revolving credit facility.
Our obligations under the Credit Agreement may be accelerated upon the occurrence of an Event of Default. Events of Default include customary events for a financing agreement of this type, including, without limitation, payment defaults, defaults in the performance of affirmative or negative covenants, the inaccuracy of representations and warranties, bankruptcy or related defaults, defaults relating to judgments and the occurrence of a Change of Control (as defined in the Credit Agreement), subject, in certain circumstances, to certain cure periods.
Subject to certain permitted liens, our revolving credit facility is secured by the grant of a first priority lien on all or substantially all of our assets and the assets of our restricted subsidiaries, including, without limitation, a lien on no less than 80% of the value of the proved oil and gas properties of us and our restricted subsidiaries. In connection with the Credit Agreement, we and our restricted subsidiaries also entered into customary ancillary agreements and arrangements, which among other things, provide that the revolving credit facility is unconditionally guaranteed by such restricted subsidiaries.
Eureka Hunter Pipeline Credit Facilities
On August 16, 2011, Eureka Hunter Pipeline, a wholly-owned subsidiary of Eureka Hunter Holdings, a majority-owned subsidiary of the Company, entered into (i) a First Lien Credit Agreement, referred to as the Eureka Hunter Pipeline Revolver or the revolver, by and among Eureka Hunter Pipeline, the lenders party thereto from time to time, and SunTrust Bank, as administrative agent, and (ii) a Second Lien Term Loan Agreement, referred to as the Eureka Hunter Pipeline Term Loan or the term loan, by and among Eureka Hunter Pipeline, PennantPark Investment Corporation, or PennantPark, and the other lenders party thereto from time to time, and U.S. Bank National Association, as collateral agent (the Eureka Hunter Pipeline Revolver and the Eureka Hunter Pipeline Term Loan are collectively referred to as the Eureka Hunter Pipeline Credit Facilities).
The Eureka Hunter Pipeline Revolver provides for a revolving credit facility in an aggregate principal amount of up to $100 million (with an initial committed amount of $25 million), secured by a first lien on substantially all of the assets of Eureka Hunter Pipeline. The Eureka Hunter Pipeline Term Loan provides for a $50 million term loan, secured by a second lien on substantially all of the assets of Eureka Hunter Pipeline. The entire $50 million of the term loan must be drawn before any portion of the revolver is drawn. The revolver has a maturity date of August 16, 2016, and the term loan has a maturity date of August 16, 2018.
As of December 31, 2013, Eureka Hunter Pipeline had drawn the entire $50 million of the term loan, but was not yet eligible to draw any portion of the revolver. Both the revolver and the term loan are non-recourse to Magnum Hunter.
The terms of the Eureka Hunter Pipeline Revolver provide that the revolver may be used for (i) revolving loans, (ii) swing-line loans in an aggregate amount of up to $5 million at any one time outstanding or (iii) letters of credit in an aggregate amount of up to $5 million at any one time outstanding. The revolver provides for a commitment fee of 0.5% per annum based on the unused portion of the commitment under the revolver.
Borrowings under the revolver will, at Eureka Hunter Pipeline’s election, bear interest at:
•
a base rate equal to the highest of (A) the prime lending rate announced from time to time by the Administrative Agent, (B) the then-effective Federal Funds Rate (as defined in the Eureka Hunter Pipeline Revolver) plus 0.5% per
annum, or (C) the Adjusted LIBO Rate (as defined in the Eureka Hunter Pipeline Revolver) for a one-month interest period on such day plus 1.0% per annum, plus an applicable margin ranging from 1.25% to 2.25%; or
•
the Adjusted LIBO Rate, plus an applicable margin ranging from 2.25% to 3.25%.
Borrowings under the term loan will bear interest at 12.50% per annum in cash (increasing to 13.50% on and at all times when Eureka Hunter Pipeline and its subsidiaries incur indebtedness (other than the term loan) in excess of $1 million).
If an event of default occurs under either the revolver or the term loan, the applicable lenders may increase the interest rate then in effect by an additional 2.0% per annum for the period that the default exists under the revolver or term loan, respectively.
The Eureka Hunter Pipeline Credit Facilities contain negative covenants that, among other things, restrict the ability of Eureka Hunter Pipeline and its subsidiaries to, with certain exceptions: (1) incur indebtedness; (2) grant liens; (3) dispose of all or substantially all of its assets or enter into mergers, consolidations, or similar transactions; (4) change the nature of its business; (5) make investments, loans, or advances or guarantee obligations; (6) pay cash dividends or make certain other payments; (7) enter into transactions with affiliates; (8) enter into sale and leaseback transactions; (9) enter into hedging transactions; (10) amend its organizational documents or material agreements; or (11) make certain undisclosed capital expenditures.
The Eureka Hunter Pipeline Credit Facilities also require Eureka Hunter Pipeline to satisfy certain financial covenants, including maintaining:
•
a consolidated total debt to capitalization ratio of not more than 60%;
•
a ratio of consolidated earnings before interest, taxes, depreciation, depletion, amortization , "EBITDA," to consolidated interest expense, in each case, for the four fiscal quarter period then ended, ranging from:
(i)
for the term loan, not less than (A) 2.25 to 1.00, for the fiscal quarters ending December 31, 2013 and March 31, 2014, (B) 2.50 to 1.00, for the fiscal quarters ending June 30, 2014 and September 30, 2014, and (C) 2.75 to 1.0 for the fiscal quarter ending December 31, 2014 and each fiscal quarter ending thereafter, and
(ii)
in the event any portion of the revolver has been drawn, for the revolver, not less than (A) 2.50 to 1.00, for the fiscal quarters ending December 31, 2013 and March 31, 2014, (B) 2.75 to 1.00, for the fiscal quarters ending June 30, 2014 and September 30, 2014, and (C) 3.00 to 1.0 for the fiscal quarter ending December 31, 2014 and each fiscal quarter ending thereafter;
•
a ratio of consolidated total debt to consolidated EBITDA for the four fiscal quarter period then ended ranging from:
(i)
for the term loan, not greater than (A) 4.50 to 1.0 for the fiscal quarters ending December 31, 2013, March 31, 2014, June 30, 2014, and September 30, 2014, and (B) 4.25 to 1.0 for the fiscal quarter ending December 31, 2014 and each fiscal quarter ending thereafter, and
(ii)
in the event any portion of the revolver has been drawn, for the revolver, not greater than (A) 4.50 to 1.0 for the fiscal quarters ending December 31, 2013 and March 31, 2014, and (B) 4.00 to 1.0 for the fiscal quarter ending June 30, 2014 and each fiscal quarter ending thereafter; and
•
a ratio of consolidated debt under the revolver to consolidated EBITDA of (i) for the term loan, not greater than 3.5 to 1.0, and (ii) for the revolver, if any portion of the revolver has been drawn, not greater than 3.25 to 1.0 for each fiscal quarter.
The obligations of Eureka Hunter Pipeline under each of the revolver and the term loan may be accelerated upon the occurrence of an event of default (as such term is defined in the facility) under such facility. Events of default include customary events for these types of financings, including, among others, payment defaults, defaults in the performance of affirmative or negative covenants, the inaccuracy of representations or warranties, defaults under the term loan (with respect to the revolver) or the revolver (with respect to the term loan), defaults relating to judgments, material defaults under certain material contracts of Eureka Hunter Pipeline, and defaults by the Company which cause the acceleration of the Company’s debt under our revolving credit facility.
In connection with the Eureka Hunter Pipeline Credit Facilities, (i) Eureka Hunter Pipeline and its subsidiaries have entered into customary ancillary agreements and arrangements, which provide that the obligations of Eureka Hunter Pipeline under the Eureka Hunter Pipeline Credit Facilities are secured by substantially all of the assets of Eureka Hunter Pipeline and its subsidiaries and (ii) Eureka Hunter Holdings, the sole parent of Eureka Hunter Pipeline and a majority-owned subsidiary of the Company, entered into customary ancillary agreements and arrangements, which granted the lenders under the facilities a non-recourse security interest in Eureka Hunter Holdings’ equity interest in Eureka Hunter Pipeline.
Senior Notes
On May 16, 2012, Magnum Hunter issued $450 million in aggregate principal amount of its 9.750% Senior Notes due 2020, referred to as our Unregistered Senior Notes. The Unregistered Senior Notes were issued pursuant to an indenture entered into on May 16, 2012 as supplemented, among the Company, the subsidiary guarantors party thereto, Wilmington Trust, National Association, as the trustee, and Citibank, N.A., as the paying agent, registrar, and authenticating agent. On December 18, 2012, Magnum Hunter issued an additional $150 million in aggregate principal amount of Unregistered Senior Notes pursuant to a supplement to the indenture. The Unregistered Senior Notes issued in May 2012 and the Unregistered Senior Notes issued in December 2012 had identical terms and were treated as a single class of securities under the indenture. We did not register the issuances of the Unregistered Senior Notes under the Securities Act in reliance on certain exemptions from the registration requirements, but on November 8, 2013 we completed an exchange offer pursuant to which we exchanged $600 million of Senior Notes registered under the Securities Act for all of the Unregistered Notes. We refer to the registered Senior Notes as the Exchange Notes or our Senior Notes. The Exchange Notes have substantially identical terms to our former Unregistered Senior Notes except the Exchange Notes are generally freely transferable under the Securities Act. As of December 31, 2013, we had $600 million aggregate principal amount of Senior Notes outstanding.
The Senior Notes mature on May 15, 2020. Interest on the Senior Notes accrues at an annual rate of 9.750% and is payable semi-annually in arrears on May 15 and November 15. Our revolving credit facility prohibits the prepayment of the Senior Notes.
The Senior Notes are Magnum Hunter’s general unsecured senior obligations. Accordingly, they rank:
•
equal in right of payment to all of our existing and future senior unsecured indebtedness;
•
effectively subordinated to all our existing and future senior secured indebtedness incurred from time to time, such as our revolving credit facility, to the extent of the value of our assets securing such indebtedness;
•
structurally subordinated to all existing and future indebtedness and other liabilities, including trade payables, of any non-guarantor subsidiaries (such as Eureka Hunter Holdings, Eureka Hunter Pipeline, TransTex Hunter and our foreign subsidiaries), other than indebtedness and other liabilities owed to us; and
•
senior in right of payment to all of our future subordinated indebtedness.
The Senior Notes are jointly and severally guaranteed by all of our existing and future direct or indirect domestic subsidiaries that guarantee obligations under our revolving credit facility. In the future, the guarantees may be released or terminated under certain circumstances. Each guarantee ranks:
•
equal in right of payment to all existing and future senior unsecured indebtedness of the guarantor;
•
effectively subordinated to all of the guarantors’ existing and future senior secured indebtedness incurred from time to time (including guarantees of our revolving credit facility), to the extent of the value of the assets securing such indebtedness;
•
structurally subordinated to all existing and future indebtedness and other liabilities, including trade payables, of our non-guarantor subsidiaries (such as Eureka Hunter Holdings, Eureka Hunter Pipeline, TransTex Hunter and our foreign subsidiaries), other than indebtedness and other liabilities owed to us; and
•
senior in right of payment to any future subordinated indebtedness of the guarantor.
At any time prior to May 15, 2015, we may, from time to time, redeem up to 35% of the aggregate principal amount of the Senior Notes with the net cash proceeds of certain equity offerings at the redemption prices specified in the indenture if at least 65% of the aggregate principal amount of the Senior Notes issued under the indenture (excluding notes held by us) remains outstanding immediately after such redemption and the redemption occurs within 180 days of the closing date of such equity offering. At any time prior to May 15, 2016, we may redeem the notes, in whole or in part, at a “make-whole” redemption price specified in the indenture. On and after May 15, 2016 we may redeem the notes, in whole or in part, at the redemption prices specified in the indenture.
If we experience certain change of control events, each holder of Senior Notes may require us to repurchase all or a portion of the Senior Notes for cash at a price equal to 101% of the aggregate principal amount of such notes, plus any accrued and unpaid interest to, but not including, the date of repurchase.
The indenture governing the Senior Notes contains covenants that, among other things, limit our and our restricted subsidiaries’ ability to:
•
incur or guarantee additional indebtedness or issue certain preferred stock;
•
pay dividends on capital stock or redeem, repurchase or retire our capital stock or subordinated indebtedness or make certain other restricted payments;
•
transfer or sell assets;
•
make loans and other investments;
•
create or permit to exist certain liens;
•
enter into agreements that restrict dividends or other payments or distributions from our restricted subsidiaries to us;
•
consolidate, merge or transfer all or substantially all of our assets;
•
engage in transactions with affiliates; and
•
create unrestricted subsidiaries.
These covenants are subject to certain exceptions and qualifications as described in the indenture. At December 31, 2013, the Company was in compliance with all of its requirements under the indenture related to the Senior Notes.
The indebtedness of the Company under the indenture may (or, in certain cases, will automatically) be accelerated upon the occurrence of an Event of Default (as such term is defined in the indenture). Events of Default include customary events for a financing agreement of this type, including, without limitation, payment defaults, defaults in the performance of affirmative or negative covenants, bankruptcy or related events, certain cross-defaults relating to other indebtedness for borrowed money and defaults relating to judgments.
We entered into registration rights agreements pursuant to which we had agreed to file an exchange offer registration statement under the Securities Act to allow the holders of the Unregistered Senior Notes to exchange the Unregistered Senior Notes issued in the May and December 2012 offerings for the same principal amount of a new issue of Exchange Notes. As a result of the delay in the filing of certain of our SEC reports, we failed to complete the registered exchange offer within the time period specified in our registration rights agreement. Accordingly, as required by the terms of the registration rights agreement, we were required to pay penalty interest on the Unregistered Senior Notes from May 6, 2013 through November 8, 2013 when we completed the exchange of the Exchange Notes for the Unregistered Senior Notes. The Company paid such penalty interest totaling $1.1 million during 2013.
Until August 2014, approximately twelve months after the date on which we became current with our SEC reporting obligations, we are ineligible to use abbreviated and less costly SEC filings, such as the SEC's Form S-3 registration statement, to register our securities for sale as a result of our 2012 Form 10-K, First Quarter 2013 Form 10-Q and certain pro forma financial information regarding our sale of Eagle Ford Hunter, Inc. to Penn Virginia (as part of the Form 8-K we filed with the SEC on April 30, 2013 reporting the sale) not having been filed within the time frames permitted by the SEC. See “Risk Factors-Our failure to timely file certain periodic reports with the SEC limits our access to the public markets to raise debt or equity capital.” These adverse impacts from our late SEC filings will be reduced, to some extent, by the net proceeds we received from the sale of our Eagle Ford properties and expected net proceeds in 2013 and 2014 from sales of non-core properties.
Eureka Hunter Holdings Equity Commitment Facility
Pursuant to the Series A Convertible Preferred Unit Purchase Agreement among Magnum Hunter, Eureka Hunter Holdings and Ridgeline, referred to as the Unit Purchase Agreement, Ridgeline committed, subject to certain conditions, to purchase up to $200 million of preferred units of Eureka Hunter Holdings. As of December 31, 2013, Eureka Hunter Holdings had sold preferred units to Ridgeline for an aggregate purchase price of $187.8 million.
Eureka Hunter Holdings’ ability to obtain additional funds from Ridgeline is subject to the satisfaction of certain conditions to Ridgeline’s obligation to purchase preferred units as set forth in the Unit Purchase Agreement. These conditions include, among others, that (i) the proceeds be used for certain approved capital expenditures, midstream growth projects and/or acquisitions (or for any other purposes agreed to by Ridgeline) and (ii) no defaults or material adverse events have occurred.
The Amended and Restated Limited Liability Company Agreement of Eureka Hunter Holdings, referred to as the EH Operating Agreement, contains certain covenants that, among other things, restrict the ability of Eureka Hunter Holdings and its subsidiaries, including Eureka Hunter Pipeline and TransTex Hunter, to, with certain exceptions:
•
incur funded indebtedness, whether direct or contingent;
•
issue additional equity interests;
•
pay distributions to its owners, or repurchase or redeem any of its equity securities;
•
make any material acquisitions, dispositions or divestitures; or
•
enter into a sale, merger, consolidation or other change of control transaction.
Under the EH Operating Agreement, the holders of preferred units of Eureka Hunter Holdings are entitled to receive an annual distribution of 8%, payable quarterly. Through and including the quarter ended March 31, 2013, the board of directors of Eureka
Hunter Holdings could elect to pay up to 75% of any such distribution in kind (i.e., in additional preferred units), in lieu of cash. For the quarter ending June 30, 2013 through and including the quarter ending March 31, 2014, the board of directors of Eureka Hunter Holdings may elect to pay up to 50% of any such distribution in kind. Thereafter, all distributions to Ridgeline relating to the preferred units will be paid solely in cash.
In addition to the required quarterly distributions of accrued preferred return on the preferred units, the EH Operating Agreement also (i) gives Eureka Hunter Holdings the right, at any time on or after the fifth anniversary of the closing of the initial Ridgeline investment, to redeem all, but not less than all, of the outstanding preferred units, and (ii) gives Ridgeline the right, at any time on or after the eighth anniversary of the closing of the initial Ridgeline investment, to require Eureka Hunter Holdings to redeem all, but not less than all, of the outstanding preferred units. If Eureka Hunter Holdings fails to meet its redemption obligations under clause (ii) above, then Ridgeline will have the right to assume control of the board of directors of Eureka Hunter Holdings and, at its option, to cause Eureka Hunter Holdings and/or its other owners to enter into a sale, merger or other disposition of Eureka Hunter Holdings or its assets (on terms acceptable to Ridgeline).
Further, pursuant to the terms of the EH Operating Agreement, the number and composition of the board of directors of Eureka Hunter Holdings may change over time based on Ridgeline’s percentage ownership interest in Eureka Hunter Holdings (after taking into account any additional purchases of preferred units) or the failure of Eureka Hunter Holdings to satisfy certain performance goals by the third anniversary of the closing of the initial Ridgeline investment (or as of any anniversary after such date). The board of directors of Eureka Hunter Holdings is currently composed of a majority of members appointed by Magnum Hunter. Subject to the rights described above, the board of directors of Eureka Hunter Holdings may in the future be composed of an equal number of directors appointed by Magnum Hunter and Ridgeline or, in certain cases, of a majority of directors appointed by Ridgeline.
The EH Operating Agreement originally contained a requirement that Ridgeline have an exclusive first right to fund up to 100% of Eureka Hunter Holdings’ funding requirements, subject to certain exceptions. On March 7, 2013, Magnum Hunter and Ridgeline entered into an amendment to the EH Operating Agreement which, among other things, provides Magnum Hunter a right to make additional capital contributions to Eureka Hunter Holdings in conjunction with or alongside additional capital contributions from Ridgeline. Accordingly, Magnum Hunter contributed $30 million to Eureka Hunter Holdings on March 7, 2013, followed by Ridgeline contributing $20 million during April 2013. Further, the agreement (as amended) provides that the next $70.5 million of additional capital contributions ($20.0 million of which had been paid by September 30, 2013) must be made 60% by Magnum Hunter and 40% by Ridgeline in order for each party to maintain their existing ownership percentage interests in Eureka Hunter Holdings.
If a change of control of Magnum Hunter occurs at any time prior to a qualified public offering (as defined in the EH Operating Agreement) of Eureka Hunter Holdings, Ridgeline will have the right under the terms of the EH Operating Agreement to purchase sufficient additional preferred units in Eureka Hunter Holdings so that it holds up to 51.0% of the equity ownership of Eureka Hunter Holdings.
The EH Operating Agreement also contains (i) preferred unit conversion rights in favor of Ridgeline, whereby it may convert its preferred units into common units of Eureka Hunter Holdings, (ii) transfer restrictions on Magnum Hunter’s ownership interests in Eureka Hunter Holdings (subject to certain exceptions), (iii) certain pre-emptive rights, rights of first refusal and co-sale rights in favor of Ridgeline and (iv) certain Securities Act registration rights in favor of Ridgeline.
Related Party Transactions
The following table sets forth the related party transaction activities for the twelve months ended December 31, 2013, 2012 and 2011, respectively:
_________________________________
(1)
GreenHunter is an entity of which Gary C. Evans, the Company's Chairman and CEO, is the Chairman, Interim CEO and a major shareholder; of which David Krueger, the Company's former Chief Accounting Officer and Senior Vice President, is the former Chief Financial Officer; and of which Ronald D. Ormand, the Company’s former Chief Financial Officer and Executive Vice President, is a former director. Eagle Ford Hunter received, and Triad Hunter and Viking International Resources Co., Inc. ("Virco"), wholly-owned subsidiaries of the Company, receive services related to brine water and rental equipment from GreenHunter and its affiliated companies, White Top Oilfield Construction, LLC and Black Water Services, LLC. The Company believes that such services were and are provided at competitive market rates and were and are comparable to, or more attractive than, rates that could be obtained from unaffiliated third party suppliers of such services. Prepaid expenses from GreenHunter were $9,000, $0 and $0 at December 31, 2013, December 31, 2012 and December 31, 2011, respectively. The Company had net accounts payable to GreenHunter of $23,000, $0 and $70,000 at December 31, 2013, December 31, 2012, and December 31, 2011 respectively.
(2)
On February 17, 2012, the Company sold its wholly-owned subsidiary, Hunter Disposal, to GreenHunter Water, LLC ("GreenHunter Water"), a wholly-owned subsidiary of GreenHunter. The Company recognized an embedded derivative asset resulting from the conversion option under the convertible promissory note it received as partial consideration for the sale. The fair market value of the derivative asset was $79,000, $264,000, and $0 at December 31, 2013, December 31, 2012 and December 31, 2011, respectively. See "Note 3 - Fair Value of Financial Instruments". The Company has recorded interest income as a result of the note receivable from GreenHunter. Also as a result of this transaction, the Company has an equity method investment in GreenHunter that is included in derivatives and other long term assets and an available for sale investment in GreenHunter included in investments.
(3)
The Company rented an airplane for business use for certain members of Company management at various times from Pilatus Hunter, LLC, an entity 100% owned by Mr. Evans. Airplane rental expenses are recorded in general and administrative expense.
(4)
During the years ended December 31, 2011 and 2012, the Company paid rent under a lease for a Houston, Texas corporate apartment from an executive of the Company, which apartment was used by other Company employees when in Houston for Company business. The lease terminated in May 2012.
In connection with the sale of Hunter Disposal, Triad Hunter entered into agreements with Hunter Disposal and GreenHunter Water for wastewater hauling and disposal capacity in Kentucky, Ohio, and West Virginia and a five-year tank rental agreement with GreenHunter Water. See "Note 2 - Divestitures and Discontinued Operations".
Mr. Evans, the Company's Chairman and Chief Executive Officer, was a 4.0% limited partner in TransTex Gas Services, LP ("TransTex Gas"). This limited partnership received total consideration of 622,641 Class A Common Units of Eureka Hunter Holdings and cash of $46.0 million upon the Company's acquisition of certain of its assets. This includes units issued in accordance with the agreement of Eureka Hunter Holdings and TransTex Gas to provide the limited partners of TransTex Gas the opportunity to purchase additional Class A Common Units of Eureka Hunter Holdings in lieu of a portion of the cash distribution they would otherwise receive. Certain limited partners purchased such units, including Mr. Evans, who purchased 27,641 Class A Common Units of Eureka Hunter Holdings for $553,000 which was the same purchase price equivalent offered to all TransTex investors.
Contractual Commitments
The following table summarizes our contractual commitments as of December 31, 2013 (in thousands):
No dividends on preferred securities issued by the Company and Eureka Hunter Holdings have been included in the table above because the total amounts to be paid are not determinable. See "Note 10 - Shareholders' Equity" and "Note 11 - Redeemable Preferred Stock" to our consolidated financial statements for further details regarding our obligations to preferred shareholders.
_________________________________
(1)
See "Note 8 - Long-Term Debt", to the Company’s consolidated financial statements.
(2)
Interest payments have been calculated by applying the interest rate in effect as of December 31, 2013 on the debt facilities in place as of December 31, 2013. This results in a weighted average interest rate of 8.13%.
(3)
See "Note 7 - Asset Retirement Obligations" to our consolidated financial statements for a discussion of our asset retirement obligations.
(4)
See “Quantitative and Qualitative Disclosures About Market Risk” and "Note 4 - Financial Instruments and Derivatives" to our consolidated financial statements regarding the Company’s derivative obligations.
Off-Balance Sheet Arrangements
From time to time, we enter into off-balance sheet arrangements and transactions that can give rise to off-balance sheet obligations. As of December 31, 2013, the off-balance sheet arrangements and transactions that we have entered into include operating lease agreements. We do not believe that these arrangements are reasonably likely to have a current or future effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that is material to investors.
Critical Accounting Policies and Estimates
The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting policies generally accepted in the U.S. The preparation of our consolidated financial statements requires us to make estimates and assumptions that affect our reported results of operations and the amount of reported assets, liabilities and proved oil and gas reserves. Some accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. Actual results may differ from the estimates and assumptions used in the preparation of our consolidated financial statements. Described below are the most significant policies we apply in preparing our consolidated financial statements, some of which are subject to alternative treatments under U.S. GAAP. We also describe the most significant estimates and assumptions we make in applying these policies. See "Note 1 - Organization, Nature of Operations and Summary of Significant Accounting Policies".
Oil and Gas Activities-Successful Efforts
Accounting for oil and gas activities is subject to unique rules. We use the successful efforts method of accounting for our oil and gas activities. The significant principles for this method are:
•
Geological and geophysical evaluation costs are expensed as incurred.
•
Dry holes for exploratory wells are expensed, and dry holes for developmental wells are capitalized.
•
Capitalized costs relating to proved oil and gas properties, including wells and related equipment and facilities, are evaluated for impairment based on an analysis of undiscounted future net cash flows in accordance with ASC 360, Accounting for the Impairment or Disposal of Long Lived Assets. If undiscounted cash flows are insufficient to recover the net capitalized costs relating to proved properties, then we recognize an impairment charge to proved property impairment expense equal to the difference between the net capitalized costs relating to proved properties and their estimated fair values based on the present value of the related future net cash flows.
•
Capitalized costs relating to unproved oil and gas properties are evaluated for impairment based on an analysis of undiscounted future net cash flows in accordance with ASC 932, Property, Plant and Equipment. The Company impairs an unproved lease if it becomes probable that its carrying value will not be recovered based on management's outlooks. By their nature, unproved properties' impairment assessments are judgmental unless active exploration of the project is underway or clear intent exists to allow the underlying leaseholds to expire before exploring them for proved reserves. If impairment indicators exist, inquiries become more critical and demanding. Factors that affect the impairment assessments include but may not be limited to: results of exploration activities, commodity price outlooks, planned future sales, expirations or extensions of all or a portion of the projects, and capital budgeting considerations. For properties assessed, if the property is surrendered or the lease expires without identifying proved reserves, the cost of the property is recognized as a charge to exploration and abandonment expense.
Proved Reserves
For the year ended December 31, 2013, we engaged CG&A., independent petroleum engineers, to prepare independent estimates of the extent and value of the proved reserves associated with our oil and gas properties in accordance with guidelines established by the SEC, including the 2008 revisions designed to modernize oil and gas reserve reporting requirements. We adopted these revisions effective December 31, 2009.
Estimates of proved oil and gas reserves directly impact financial accounting estimates including depletion, depreciation and amortization expense, evaluation of impairment of properties and the calculation of plugging and abandonment liabilities. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations. The process of estimating quantities of proved reserves is very complex, requiring significant subjective decisions in the evaluation of all geological, engineering and economic data for each reservoir. The data for any reservoir may change substantially over time due to results from operational activity. Proved reserve volumes at December 31, 2013, were estimated based on the un-weighted, arithmetic average of the closing price on the first day of each month for the 12-month period prior to December 31, 2013 for oil and natural gas in accordance with the SEC’s reserve rules. The average price used for oil was $96.78 and for natural gas was $3.67.
See also "Business” and "Properties-Proved Reserves” and "Note 15 - Other Information" to our consolidated financial statements regarding our estimated proved reserves.
Derivative Instruments and Commodity Derivative Activities
Marked-to-market at fair value, derivative contracts are included on our consolidated balance sheets as current or non-current assets or liabilities based on the anticipated timing of cash settlements under the related contracts. We record changes in such fair value in earnings on our consolidated statements of operations under the caption entitled “Gain (loss) on derivative contracts, net.”
Although we have not designated our derivative instruments as cash-flow hedges, we use those instruments to reduce our exposure to fluctuations in commodity prices related to our oil and gas production. We record gains and losses on settled and open transactions under those instruments in other revenues on our consolidated statements of operations. Gains and losses on open transactions result from changes in the fair market value of the derivative contracts from period to period, and represent non-cash gains or losses. Changes in commodity prices could have a significant effect on the fair value of our derivative contracts.
We estimate the fair values of swap contracts based on the present value of the difference in exchange-quoted forward price curves and contractual settlement prices multiplied by notional quantities. We internally valued the collar contracts using industry-standard option pricing models and observable market inputs. We utilize the assistance of third-party valuations providers to determine the fair values of the contracts that are reflected on our consolidated balance sheets. Gains and losses on settled transactions are also included in “Gain (loss) on derivative contracts” on our consolidated statements of operations.
Changes in the derivative’s fair value are currently recognized in the statement of operations unless specific commodity derivative hedge accounting criteria are met and such strategies are designated. We continue not to designate our derivative instruments as cash-flow hedges.
We are exposed to credit losses in the event of nonperformance by the counterparties on our commodity derivatives positions and have considered the exposure in our internal valuations. However, we do not anticipate nonperformance by the counterparties over the term of the commodity derivatives positions.
The following table summarizes the net gain (loss) on our derivative contracts for the years ended December 31, 2013, 2012 and 2011:
A hypothetical 10% increase in the NYMEX floating prices would have resulted in a $15.0 million decrease in the December 31, 2013 fair value of the derivative liabilities recorded on our balance sheet and a corresponding increase to the loss on commodity derivatives in our statement of operations. A hypothetical 10% decrease in the NYMEX floating prices would have a resulted in a $7.9 million increase in the December 31, 2013 fair value of the derivative liabilities recorded on our balance sheet and would have increased the gain on commodity derivatives in our statement of operations by the corresponding amount.
The Company also has preferred stock derivative liabilities resulting from certain conversion features, redemption options, and other features of the Series A Convertible Preferred Units of Eureka Hunter Holdings and a convertible security embedded derivative asset primarily due to the conversion feature of the promissory note received by us as partial consideration for the sale of Hunter Disposal, LLC. See "Note 1 - Organization, Nature of Operations and Summary of Significant Accounting Policies", "Note 3 - Fair Value of Financial Instruments", "Note 4 - Financial Instruments and Derivatives", and "Note 10 - Shareholders' Equity".
Asset Retirement Obligation
Our asset retirement obligation primarily represents the estimated present value of the amount we will incur to plug, abandon and remediate our producing properties at the end of their productive lives, in accordance with applicable federal, state and local laws. We determine our asset retirement obligation by calculating the present value of estimated cash flows related to the liability. The retirement obligation is recorded as a liability at its estimated present value as of the asset’s inception, with an offsetting increase to proved properties. Periodic accretion of discount of the estimated liability is recorded as accretion expense in the consolidated statements of operations.
Our liability is determined using significant assumptions, including current estimates of plugging and abandonment costs, annual inflation of these costs, the productive lives of wells and our risk-adjusted interest rate. Changes in any of these assumptions can result in significant revisions to the estimated asset retirement obligation. Our liability for asset retirement obligations was approximately $16.2 million and $30.7 million at December 31, 2013 and 2012, respectively. See "Note 7 - Asset Retirement Obligations".
Share-Based Compensation
The Company estimates the fair value of share-based payment awards made to employees and directors, including stock options, restricted stock and employee stock purchases related to employee stock purchase plans, on the date of grant using an option-pricing model. The value of the portion of the award that is ultimately expected to vest is recognized as an expense ratably over the requisite service periods. Awards that vest only upon achievement of performance criteria are recorded only when achievement of the performance criteria is considered probable. We estimate the fair value of each share-based award using the Black-Scholes option pricing model or a lattice model. These models are highly complex and dependent on key estimates by management. The estimates with the greatest degree of subjective judgment are the estimated lives of the stock-based awards, the estimated volatility of our stock price, and the assessment of whether the achievement of performance criteria is probable. For the years ended December 31, 2013, 2012 and 2011, we recognized approximately $13.6 million, $15.7 million, and $25.1 million in non-cash stock compensation, respectively. See "Note 9 - Share-Based Compensation".
Impairment and Disposition of Long Lived Assets
The Company accounts for the impairment and disposition of long-lived assets in accordance with ASC 360, Accounting for the Impairment or Disposal of Long-Lived Assets. ASC 360 requires that the Company’s long-lived assets, including its proved oil and gas properties, be assessed for potential impairment in their carrying values whenever events or changes in circumstances indicate such impairment may have occurred. An impairment charge to current operations is recognized when the estimated
undiscounted future net cash flows of the asset are less than its carrying value. Any such impairment is recognized based on the differences in the carrying value and estimated fair value of the impaired asset.
The guidance provides for future revenue from the Company’s oil and gas production to be estimated based upon prices at which management reasonably estimates such products will be sold. These estimates of future product prices may differ from current market prices of oil and gas. Any downward revisions to management’s estimates of future production or product prices could result in an impairment of the Company’s proved oil and gas properties in subsequent periods.
The long-lived assets of the Company which are subject to evaluation consist primarily of oil and gas properties. Impairment reviews are performed quarterly by management. The Company recognized a non-cash, pre-tax charge against earnings related to the impairment of proved property of approximately $10.0 million, $3.8 million, and none for the years ended December 31, 2013, 2012, and 2011, respectively.
Capitalized costs relating to unproved oil and gas properties are evaluated for impairment based on an analysis of undiscounted future net cash flows in accordance with ASC 932, Property, Plant and Equipment. The Company impairs an unproved lease if it becomes probable that its carrying value will not be recovered based on management's outlooks. During 2013, the Company's exploration expense included $89.1 million and $6.8 million associated with the Company's unproved properties in the Williston Basin and the Appalachian Basin, respectively, along with $1.4 million of geological and geophysical costs. During 2012, the Company's exploration expense included $59.2 million, $15.0 million, and $1.4 million associated with the Company's unproved properties in the Williston Basin, Appalachian Basin, and south Texas, respectively, along with $2.6 million of geological and geophysical costs. The significant components of the Company's 2011 exploration expense included unproved acreage abandonments of $0.8 million and $0.3 million in the Appalachian Basin and Eagle Ford Shale areas, respectively, and $1.5 million of geological and geophysical costs.
By their nature, unproved properties' impairment assessments are judgmental unless active exploration of the project is underway or clear intent exists to allow the underlying leaseholds to expire before exploring them for proved reserves. If impairment indicators exist, inquiries become more critical and demanding. Factors that affect the impairment assessments include but may not be limited to: results of exploration activities, commodity price outlooks, planned future sales, expirations or extensions of all or a portion of the projects, and capital budgeting considerations. For properties assessed, if the property is surrendered or the lease expires without identifying proved reserves, the cost of the property is recognized as a charge to exploration and abandonment expense. See "Note 1 - Organization, Nature of Operations and Summary of Significant Accounting Policies".
Goodwill and Intangible Assets
Goodwill represents the excess of the purchase price of an entity over the estimated fair value of the assets acquired and the liabilities assumed. Intangible assets consist primarily of the fair value of the acquired gas treating agreements and customer relationships in the TransTex Gas Services, LP assets acquisition. The intangible assets were valued at fair value using a discounted cash flow model with a discount rate of 13%. Such assets are being amortized over the weighted average term of 8.5 years. The customer relationships are being amortized with a 12.5 year life. The Company assessed goodwill for impairment on April 1, 2013, and determined that no impairment existed. The Company updated its annual impairment test through December 31, 2013, with an evaluation of any triggering events or circumstances that would indicate that impairment of the carrying value of goodwill is likely, and none were determined to exist. The Company assesses the carrying amount of its other intangible assets for impairment when events or changes in circumstances indicate the carrying value may not be recoverable. At December 31, 2013, neither our goodwill nor our other intangible assets were impaired.
Revenue Recognition
Revenues associated with sales of crude oil and liquids, natural gas, petroleum products, and other items are recognized when earned. Revenues are considered earned when the products are delivered, which occurs when the customer has taken title and has assumed the risks and rewards of ownership, prices are fixed or determinable and collectability is reasonably assured.
Revenues from the production of crude oil and natural gas properties in which we have an interest with other producers are recognized based on the actual volumes we sold during the period. Any differences between volumes sold and entitlement volumes, based on our net working interest, which are deemed to be non-recoverable through remaining production, are recognized as accounts receivable or accounts payable, as appropriate. Cumulative differences between volumes sold and entitlement volumes are not significant.
Revenues from field servicing activities are recognized at the time the services are provided and earned as provided in the various contract agreements. Gas gathering revenues are recognized at the time the natural gas is delivered at the destination point.
Income Taxes
Income taxes are accounted for in accordance with FASB ASC 740, under which deferred income taxes are recognized for the future tax effects of temporary differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities using the enacted statutory tax rates in effect at year-end. The effect on deferred taxes for a change in tax rates is
recognized in earnings in the period that includes the enactment date. A valuation allowance for deferred tax assets is recorded when it is more likely than not that the benefit from the deferred tax asset will not be realized.
Uncertain Income Tax Positions
Under accounting standards for uncertainty in income taxes (ASC 740-10), a company recognizes a tax benefit in the financial statements for an uncertain tax position only if management's assessment is that the position is “more likely than not” (i.e., a likelihood greater than 50 percent) to be allowed by the tax jurisdiction based solely on the technical merits of the position. The term “tax position” in the accounting standards for income taxes refers to a position in a previously filed tax return or a position expected to be taken in a future tax return that is reflected in measuring current or deferred income tax assets and liabilities for interim or annual periods. No material uncertain tax positions existed at December 31, 2013.
Recently Issued Accounting Standards
Accounting standards-setting organizations frequently issue new or revised accounting rules. We regularly review all new pronouncements to determine their impact, if any, on our financial statements. There were no new pronouncements which are expected to have a material effect on our financial statements.
Item 7A.
Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Some of the information below contains forward-looking statements. The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in oil and gas prices and other related factors. The disclosure is not meant to be a precise indicator of expected future losses, but rather an indicator of reasonably possible losses. This forward-looking information provides an indicator of how we view and manage our ongoing market risk exposures. Our market risk sensitive instruments were entered into for commodity derivative and investment purposes, and not for trading purposes.
Commodity Price Risk
Given the current economic outlook, we expect commodity prices to remain volatile. Even modest decreases in commodity prices can materially affect our revenues and cash flow. In addition, if commodity prices remain suppressed for a significant amount of time, we could be required under successful efforts accounting rules to perform a write down of the carrying value of our oil and gas properties.
We may enter into financial swaps and collars to reduce the risk of commodity price fluctuations. We do not designate such instruments as cash flow hedges. Accordingly, we record open commodity derivative positions on our consolidated balance sheets at fair value and recognize changes in such fair values as income (expense) on our consolidated statements of operations as they occur.
The table below is a summary of the Company's commodity derivatives as of December 31, 2013:
________________________________
(1) A collar is a sold call and a purchased put. Some collars are "costless" collars with the premiums netting to approximately zero.
(2) These three-way collars are a combination of three options: a sold call, a purchased put and a sold put.
At December 31, 2013, the fair value of our open commodity derivative contracts was a liability of $1.7 million.
Currently, Bank of Montreal, KeyBank National Association, Credit Suisse Energy, LLC, Bank of America - Merrill Lynch, Citibank, N.A., and J. Aron & Company are the only counterparties to our commodity derivatives positions. We are exposed to credit losses in the event of nonperformance by the counterparties; however, we do not anticipate nonperformance by the counterparties over the term of the commodity derivatives positions. All counterparties or their affiliates are participants in our revolving credit facility, and the collateral for the outstanding borrowings under which is used as collateral for our commodity derivatives with those counterparties.
Gains and losses on open transactions are included on our consolidated balance sheets as current or non-current assets or liabilities based on the anticipated timing of cash settlements under the related contracts. Changes in the fair value of our commodity derivative contracts are recorded in earnings as they occur and included in other income (expense) on our consolidated statements of operations. We estimate the fair values of swap contracts based on the present value of the difference in exchange-quoted forward price curves and contractual settlement prices multiplied by notional quantities. We internally valued the collar, call, and put contracts using industry-standard option pricing models and observable market inputs.
The following table summarizes the gains and losses on settled and open derivative contracts for the years ended December 31, 2013, 2012 and 2011:
Item 8.
Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Report of Independent Registered Public Accounting Firm
Board of Directors and Shareholders
Magnum Hunter Resources Corporation
Houston, Texas
We have audited the accompanying consolidated balance sheets of Magnum Hunter Resources Corporation as of December 31, 2013 and 2012, and the related consolidated statements of operations, comprehensive loss, shareholders' equity, and cash flows for the years then ended. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Magnum Hunter Resources Corporation at December 31, 2013 and 2012, and the results of its operations and its cash flows for the years then ended, in conformity with accounting principles generally accepted in the United States of America.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Magnum Hunter Resources Corporation's internal control over financial reporting as of December 31, 2013, based on criteria established in Internal Control - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 25, 2014, expressed an adverse opinion thereon.
/s/ BDO USA, LLP
Dallas, Texas
February 25, 2014
Report of Independent Registered Public Accounting Firm
Board of Directors and Shareholders
Magnum Hunter Resources Corporation
Houston, Texas
We have audited Magnum Hunter Resources Corporation's internal control over financial reporting as of December 31, 2013, based on criteria established in Internal Control - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission (1992 COSO Framework). Magnum Hunter Resources Corporation's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying, “Item 9a. Management's Report on Internal Control Over Financial Reporting”. Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the company's annual or interim financial statements will not be prevented or detected on a timely basis. Material weaknesses regarding management's failure to design and maintain internal control over financial reporting have been identified and include the following as described in management's assessment:
•
Controls over the intraperiod allocation of income taxes.
•
Controls over timely preparation and review of account reconciliations.
•
Controls over property accounting with respect to the accuracy and completeness of property records and related information, as a result of aggregated deficiencies.
These material weaknesses were considered in determining the nature, timing, and extent of audit tests applied in our audit of the 2013 consolidated financial statements, and this report does not affect our report dated February 25, 2014 on those consolidated financial statements.
In our opinion, Magnum Hunter Resources Corporation did not maintain, in all material respects, effective internal control over financial reporting as of December 31, 2013, based on the 1992 COSO Framework.
We do not express an opinion or any other form of assurance on management's statements referring to any corrective actions taken by the Company after the date of management's assessment.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Magnum Hunter Resources Corporation as of December 31, 2013 and 2012, and the related consolidated statements of operations, comprehensive loss, shareholders' equity, and cash flows for the years then ended and our report dated February 25, 2014, expressed an unqualified opinion thereon.
/s/ BDO USA, LLP
Dallas, Texas
February 25, 2014
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Stockholders
Magnum Hunter Resources Corporation
We have audited the accompanying consolidated statements of operations, comprehensive loss, shareholders' equity, and cash flows for the year ended December 31, 2011, of Magnum Hunter Resources Corporation and subsidiaries (collectively, the “Company”). These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the results of operations of the Company and subsidiaries and their cash flows for the year ended December 31, 2011, in conformity with U.S. generally accepted accounting principles.
/s/ Hein & Associates LLP
Dallas, Texas
February 29, 2012, except for Note 18 and Note 2 as to which the dates are January 11, 2013 and November 27, 2013, respectively
MAGNUM HUNTER RESOURCES CORPORATION
CONSOLIDATED BALANCE SHEETS
(in thousands, except share and per share data)
The accompanying Notes to Consolidated Financial Statements are an integral part of these Statements
MAGNUM HUNTER RESOURCES CORPORATION
CONSOLIDATED BALANCE SHEETS
(in thousands, except share and per share data)
The accompanying Notes to Consolidated Financial Statements are an integral part of these Statements
MAGNUM HUNTER RESOURCES CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except share and per share data)
The accompanying Notes to Consolidated Financial Statements are an integral part of these Statements
MAGNUM HUNTER RESOURCES CORPORATION
CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS
(in thousands)
The accompanying Notes to Consolidated Financial Statements are an integral part of these Statements
MAGNUM HUNTER RESOURCES CORPORATION
CONSOLIDATED STATEMENT OF SHAREHOLDERS' EQUITY
(in thousands)
The accompanying Notes to Consolidated Financial Statements are an integral part of these Statements
MAGNUM HUNTER RESOURCES CORPORATION
CONSOLIDATED STATEMENT OF SHAREHOLDERS' EQUITY
(in thousands)
The accompanying Notes to Consolidated Financial Statements are an integral part of these Statements
MAGNUM HUNTER RESOURCES CORPORATION
CONSOLIDATED STATEMENT OF CASH FLOWS
(in thousands)
The accompanying Notes to Consolidated Financial Statements are an integral part of these Statements
MAGNUM HUNTER RESOURCES CORPORATION
Notes to Consolidated Financial Statements
NOTE 1 - ORGANIZATION, NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Magnum Hunter Resources Corporation, a Delaware corporation, operating directly and indirectly through its subsidiaries (“Magnum Hunter” or the “Company”), is a Houston, Texas based independent exploration and production company engaged in the acquisition and development of producing properties and undeveloped acreage and the production of oil and natural gas in the United States and Canada, along with certain midstream and oil field service activities.
Presentation of Consolidated Financial Statements
The consolidated financial statements include the accounts of the Company and entities in which it holds a controlling interest. Our financial statements are prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP"). All significant intercompany balances and transactions have been eliminated. The preparation of our financial statements requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses. These estimates are based on information that is currently available to us and on various other assumptions that it believes to be reasonable under the circumstances. Actual results could differ from those estimates under different assumptions and conditions. Significant estimates are required for proved oil and gas reserves which may have a material impact on the carrying value of oil and gas property, and of assets held for sale.
Non-Controlling Interest in Consolidated Subsidiaries
The Company has consolidated Eureka Hunter Holdings, LLC (“Eureka Hunter Holdings”) in which it owns 56.4% and 61.0% as of December 31, 2013 and 2012, respectively. Eureka Hunter Holdings owns, directly or indirectly, 100% of the equity interests of Eureka Hunter Pipeline, LLC ("Eureka Hunter Pipeline"), TransTex Hunter, LLC and Eureka Hunter Land, LLC. On December 30, 2013, the Company’s subsidiary, PRC Williston, LLC ("PRC Williston"), in which the Company owned 87.5%, sold substantially all of its assets. The consolidated financial statements also reflect the interests of Magnum Hunter Production, Inc. (MHP) in various managed drilling partnerships. The Company accounts for the interests in these partnerships using the proportionate consolidation method.
Divestitures and Discontinued Operations
As a result of the sale of Hunter Disposal, LLC in 2012, the Company reclassified the assets and liabilities of this entity to assets and liabilities held for sale and the gain on sale and all prior operating income and expense for this entity as discontinued operations. On April 24, 2013, the Company sold all of its ownership interest in its 100%-owned subsidiary, Eagle Ford Hunter, Inc. ("Eagle Ford Hunter"). In September 2013, the Company adopted a plan to divest all of its interests in (i) MHP, a 100%-owned subsidiary of the Company whose oil and natural gas operations are located primarily in the southern Appalachian Basin in Kentucky and Tennessee, and (ii) the Canadian operations of Williston Hunter Canada, Inc., a 100%-owned subsidiary of the Company ("WHI Canada"). The Company has reflected the operations of Eagle Ford Hunter and MHP, which have historically been included as part of the U.S. Upstream operating segment and WHI Canada, which historically has been the only member of our Canadian Upstream segment, as discontinued operations for all periods presented. See "Note 2 - Divestitures and Discontinued Operations".
Reclassification of Prior-Year Balances
Certain prior-year balances in the consolidated financial statements have been reclassified to correspond with current-year classifications.
Cash and cash equivalents
Cash and cash equivalents include cash in banks and highly liquid debt securities that have original maturities of three months or less. At December 31, 2013, the Company had cash deposits in excess of FDIC insured limits at various financial institutions.
Financial Instruments
The carrying amounts of financial instruments including cash and cash equivalents, accounts receivable, notes receivable, accounts payable and accrued liabilities, derivatives, and certain long-term debt approximate fair value as of December 31, 2013 and 2012. See "Note 3 - Fair Value of Financial Instruments".
Inventory
The Company’s materials and supplies inventory is primarily comprised of frac sand used in the completion process of hydraulic fracturing. Frac sand is acquired for use in future well completion operations or repair operations and is carried at the lower of cost or market, on a first-in, first-out cost basis. “Market,” in the context of inventory valuation, represents net realizable value, which is the amount that the Company is allowed to bill to the joint accounts under joint operating agreements to which the Company is a party. Valuation reserve allowances for materials and supplies inventories are recorded as reductions to the carrying values of the materials and supply inventories in the Company’s consolidated balance sheets and as operating expense in the accompanying consolidated statements of operations. As of December 31, 2012 , the Company estimated that $3.5 million of its frac sand inventory would not be utilized within one year. Accordingly, those inventory values were classified as other long term assets in the accompanying consolidated balance sheet as of December 31, 2012. As of December 31, 2013 the frac sand inventory is anticipated to be entirely used within the coming year, and all inventories are classified as current.
Commodities inventories are carried at the lower of average cost or market, on a first-in, first-out basis. The Company’s commodities inventories consist of crude oil held in storage and is carried at the lower of average cost or market, on a first in, first out basis. Any valuation allowances of commodities inventories are recorded as reductions to the carrying values of the commodities inventories included in the Company’s consolidated balance sheets and as charges to lease operating expense in the consolidated statements of operations.
The following table sets forth the Company's inventory as of December 31, 2013 and December 31, 2012, respectively:
Oil and Natural Gas Properties
Capitalized Costs
Our oil and natural gas properties comprised the following:
The Company follows the successful efforts method of accounting for oil and gas producing activities. Costs to acquire mineral interests in oil and gas properties and to drill and equip new development wells and related asset retirement costs are capitalized. Costs to acquire mineral interests and drill exploratory wells are also capitalized pending determination of whether the wells have
proved reserves or not. If the Company determines that the wells do not have proved reserves, the costs are charged to exploration expense. Geological and geophysical costs, including seismic studies and related costs of carrying and retaining unproved properties are charged to exploration expense as incurred.
On the sale or retirement of a complete unit of a proved property, the cost and related accumulated depreciation, depletion, and amortization are eliminated from the property accounts, and the resultant gain or loss is recognized. On the retirement or sale of a partial unit of proved property, the cost is charged to accumulated depreciation, depletion, and amortization with no resulting gain or loss recognized in income. A sale of an entire field is generally treated as discontinued operations.
Leasehold costs attributable to proved oil and gas properties are depleted by the unit-of-production method over total proved reserves. Capitalized development costs are depleted by the unit-of-production method over producing proved reserves. Depreciation, depletion, amortization and accretion expense for oil and gas producing property and related equipment was $69.0 million, $49.2 million, and $18.4 million for the years ended December 31, 2013, 2012, and 2011, respectively.
Unproved oil and gas leasehold costs that are individually significant are periodically assessed for impairment of value by comparing current quotes and recent acquisitions, and taking into account management's intent, and a loss is recognized at the time of impairment by providing an impairment allowance in exploration expense.
Capitalized costs related to proved oil and gas properties, including wells and related equipment and facilities, are evaluated for impairment quarterly based on an analysis of undiscounted future net cash flows. If undiscounted future net cash flows are insufficient to recover the net capitalized costs related to proved properties, then the Company recognizes an impairment charge in income from operations equal to the difference between the net capitalized costs related to proved properties and their estimated fair values based on the present value of the related future net cash flows and other relevant market value data. Impairment of proved oil and gas properties is calculated on a field by field basis.
It is common for operators of oil and gas properties to request that joint interest owners pay for large expenditures, typically for drilling new wells, in advance of the work commencing. This right to call for cash advances is typically a provision of the joint operating agreement that working interest owners in a property adopt. The Company records these advance payments to Advances in the property accounts and reclassifies amounts from this account when the actual expenditure is later billed to us by the operator.
If an unproved property is sold or the lease expires without identifying proved reserves, the cost of the property is charged to the impairment allowance. If a partial interest in an unproved property is sold, the amount received is treated as a reduction of the cost of the interest retained.
Estimates of Proved Oil and Natural Gas Reserves
Estimates of our proved reserves included in this report are prepared in accordance with U.S. SEC guidelines for reporting corporate reserves and future net revenue. The accuracy of a reserve estimate is a function of:
· the quality and quantity of available data;
· the interpretation of that data;
· the accuracy of various mandated economic assumptions; and
· the judgment of the persons preparing the estimate.
Our proved reserve information included in this report was predominately based on evaluations reviewed by independent third party petroleum engineers. Estimates prepared by other third parties may be higher or lower than those included herein. Because these estimates depend on many assumptions, all of which may substantially differ from future actual results, reserve estimates will be different from the quantities of oil and gas that are ultimately recovered. In addition, results of drilling, testing and production after the date of an estimate may justify material revisions to the estimate.
In accordance with SEC requirements, the Company based the estimated discounted future net cash flows from proved reserves on the unweighted arithmetic average of the prior 12-month commodity prices as of the first day of each of the months constituting the period and costs on the date of the estimate.
The estimates of proved reserves materially impact depreciation, depletion, amortization and accretion (DDA&A) expense. If the estimates of proved reserves decline, the rate at which the Company records DDA&A expense will increase, reducing future net income. Such a decline may result from lower market prices, which may make it uneconomic to drill for and produce from higher-cost fields.
Oil and Natural Gas Operations
Revenue Recognition
Revenues associated with sales of crude oil, natural gas, and natural gas liquids are recognized when title passes to the customer, which is when the risk of ownership passes to the purchaser and physical delivery of goods occurs, either immediately or within a fixed delivery schedule that is reasonable and customary in the industry.
Revenues from the production of natural gas and crude oil from properties in which the Company has an interest with other producers are recognized based on the actual volumes sold during the period. Any differences between volumes sold and entitlement volumes, based on our net working interest, which are deemed to be non-recoverable through remaining production, are recognized as accounts receivable or accounts payable, as appropriate. Cumulative differences between volumes sold and entitlement volumes are generally not significant.
During the years ended December 31, 2013, 2012, and 2011 the Company recognized sales of oil, natural gas and NGL as follows:
Revenues from field servicing activities are recognized at the time the services are provided and earned as provided in the various contract agreements. Gas gathering revenues are recognized at the time the natural gas is delivered at the destination point.
Accounts Receivable
The Company recognizes revenue for our production when the quantities are delivered to or collected by the respective purchaser. Prices for such production are defined in sales contracts and are readily determinable or estimable based on available data.
Accounts receivable from joint interest owners consist of joint interest owner obligations due within 30 days of the invoice date. Accounts receivable, oil and gas sales, consist of accrued revenues due under normal trade terms, generally requiring payment within 30 to 60 days of production. The Company reviews accounts receivable periodically and reduce the carrying amount by a valuation allowance that reflects our best estimate of the amount that may not be collectible. As of December 31, 2013 and 2012, the Company had allowances for doubtful accounts of $0.3 million and $0.4 million respectively.
Revenue Payable
Revenue payable represents amounts collected from purchasers for oil and gas sales which are either revenues due to other working or royalty interest owners or severance taxes due to the respective state or local tax authorities. Generally, the Company is required to remit amounts due under these liabilities within 30 days of the end of the month in which the related production occurred.
Lease Operating Expenses
Lease operating expenses, including compressor rental and repair, pumpers’ salaries, saltwater disposal, ad valorem taxes, insurance, repairs and maintenance, workovers and other operating expenses are expensed as incurred. Transportation, gathering, and processing costs are expensed as incurred and included in lease operating expenses.
Exploration
Exploration expense consists primarily of impairment reserves for abandonment costs associated with unproved properties for which the Company has no further exploration or development plans, exploratory dry hole costs, and geological and geophysical costs. The following table provides the Company's exploration expense for 2013, 2012 and 2011:
The Company's exploration expense was primarily attributable to leasehold impairments, due to the large acreage position the Company initially acquired and results to date in the area, which led us to focus on other areas, thereby letting certain acreage expire in that region. The Company did not drill any dry holes in 2013, 2012, or 2011.
Impairment of Proved Oil and Natural Gas Properties
During the years ended December 31, 2013, 2012 and 2011, the Company recorded proved property impairments as follows:
Severance Taxes and Marketing Costs
Severance taxes are comprised of production taxes charged by most states on oil, natural gas, and natural gas liquids produced. These taxes are computed on the basis of volumes and/or value of production or sales. These taxes are usually levied at the time and place the minerals are severed from the producing reservoir. Marketing costs are those directly associated with marketing our production and are based on volumes.
Gas Gathering and Processing Costs
Gas gathering and processing costs are those costs associated with oil and gas gathering revenues of our midstream operations.
Dependence on Major Customers
The Company's share of oil and gas production is sold to various purchasers who must be prequalified under the Company's credit risk policies and procedures. The Company records allowances for doubtful accounts based on the age of accounts receivables and the financial condition of its purchasers and, depending on facts and circumstances, may require purchasers to provide collateral or otherwise secure their accounts. The loss of any one significant purchaser could have a material, adverse effect on the ability of the Company to sell its oil and gas production in a certain region. Although the Company is exposed to a concentration of credit risk, it believes that all of its purchasers are credit worthy. See "Note 13 - Major Customers".
Dependence on Suppliers
Our industry is cyclical, and from time to time there is a shortage of drilling rigs, fracture stimulation services, equipment, related supplies and qualified personnel. During these periods, the costs and delivery times of rigs, equipment and supplies are substantially greater. If the unavailability or high cost of drilling rigs, equipment, supplies or qualified personnel were particularly severe in the areas where the Company operates, it could be materially and adversely affected. The Company believes that there are potential alternative providers of drilling services and that it may be necessary to establish relationships with new contractors as our activity level increases and capital program grows. However, there can be no assurance that the Company can establish such relationships and that those relationships will result in increased availability of drilling rigs.
Gas Transportation, Gathering and Processing Equipment and Other
Our gas gathering system assets and field servicing assets are carried at cost. The Company capitalizes interest on expenditures for significant construction projects that last more than six months while activities are in progress to bring the assets to their intended use. Interest of $2.6 million and $4.4 million was capitalized on our Eureka Hunter Gas Gathering System during the years ended 2013 and 2012, respectively. The Company did not capitalize any interest in 2011. Depreciation of gas gathering system assets is provided using the straight line method over an estimated useful life of fifteen years. Depreciation of field servicing assets is provided using the straight line method over various useful lives ranging from three to ten years. Gain or loss on retirement or sale or other disposition of assets is included in income in the period of disposition.
Furniture, fixtures and equipment are carried at cost. Depreciation of furniture, fixtures and equipment is provided using the straight-line method over estimated useful lives ranging from five to fifteen years. Gain or loss on retirement or sale or other disposition of assets is included in other income in the period of disposition.
Such equipment is comprised of the following:
Depreciation expense for other property and equipment was $15.6 million, $8.1 million, and $7.8 million, for the years ended December 31, 2013, 2012, and 2011, respectively.
TransTex Hunter sells and leases gas treating and processing equipment, much of which is leased to third party operators for treating gas at the wellhead. The leases generally have a term of three years or less. The equipment under leases in place as of December 31, 2013 had terms for future payments extending as far as December 2016. TransTex Hunter has non-cancelable leases to third parties in place as of December 31, 2013, with future minimum base rentals of $4.4 million, and $0.9 million, and $0.2 million for the years ending December 31, 2014, 2015, and 2016, respectively. Equipment leasing revenue is reported in gas transportation, gathering, and processing revenue in our statement of operations.
Deferred Financing Costs
In connection with debt financings, the Company paid $1.2 million and $20.3 million in fees in the year ended December 31, 2013, and 2012, respectively. These fees were recorded as deferred financing costs and are being amortized over the life of the debt instrument using the straight line method for debt in the form of a line of credit and effective interest method for term loans. Amortization and write off of deferred financing costs for the years ended December 31, 2013, 2012, and 2011 was $4.8 million, $7.1 million, and $3.6 million, respectively.
Commodity and Financial Derivative Instruments
The Company uses commodity and financial derivative instruments, typically options and swaps, to manage the risk associated with fluctuations in oil and gas prices, and the Company accounts for these instruments in accordance with ASC 815 - Derivatives and Hedging. The Company also has an embedded derivative liability resulting from certain conversion features, redemption options, and other features of our Series A Convertible Preferred Units of Eureka Hunter Holdings, LLC and an embedded derivative asset resulting from the bifurcated conversion feature associated with the convertible note received as partial consideration upon the sale of Hunter Disposal, LLC. See "Note 3 - Fair Value of Financial Instruments", "Note 2 - Divestitures and Discontinued Operations", "Note 10 - Shareholders' Equity", and "Note 16 - Related Party Transactions".
Derivative instruments are recorded at fair value in the balance sheet as either an asset or liability, with those contracts maturing in the next twelve months classified as current, and those maturing thereafter as long-term. The Company recognizes changes in the derivatives' fair values in earnings, as it has not designated our oil and gas price derivative contracts as cash flow hedges. The Company recognizes the gains and losses on settled and open transactions on a net basis within the “Gain (loss) on derivative contracts” line item within the “Other Income (expense)” section of the Consolidated Statement of Operations.
Investments
Investments are comprised of common and preferred stock of companies publicly traded on the TSX Venture Exchange and the NYSE MKT (formerly NYSE Amex) with quoted prices in active markets. On February 17, 2012, the Company received 1,846,722 restricted common shares of GreenHunter Resources, Inc., which has a carrying value of $0.6 million and $1.3 million at December 31, 2013 and 2012, respectively, and 88,000 shares of GreenHunter Resources, Inc. 10% Series C Preferred Stock, which has a fair value of $1.7 million and $1.7 million at December 31, 2013 and 2012, respectively, as partial consideration for the sale by our wholly-owned subsidiary, Triad Hunter, LLC, of its equity ownership interest in Hunter Disposal, LLC to GreenHunter Resources, Inc. The GreenHunter common stock investment is accounted for under the equity method within the scope of ASC 323: Investments - Equity Method. The Company initially accounted for its investment in GreenHunter’s Series C Preferred Stock under the cost method specified in ASC 325: Investments - Other. The preferred shares were cost basis investments from February 17, 2012 through July 31, 2012, since the preferred stock was not publicly traded and did not have a readily determinable fair value, and therefore ineligible for accounting under ASC 320: Investments - Debt and Equity Securities.
Beginning July 31, 2012, the GreenHunter Series C Preferred Stock is publicly traded with a readily determinable fair value and is classified as available for sale within the scope of ASC 320. Available-for-sale assets are securities and other financial investments that are neither held for trading, nor held to maturity, nor held for strategic reasons, and that have a readily available market price. As such, the gains and losses resulting from marking available-for-sale investments to market are not included in net income but are reflected in other comprehensive income until they are realized.
Below is a summary of changes in investments for the years ended December 31, 2013 and 2012:
(1) Available for sale securities above includes $147,000 that has been classified as held for sale associated with the classification of the MHP subsidiary.
(2) Equity method investments includes $350,000 classified as long term other assets.
On April 24, 2013, the Company received 10.0 million shares of common stock of Penn Virginia Corporation valued at approximately $42.3 million as partial consideration for the sale of our wholly-owned subsidiary, Eagle Ford Hunter. As of September 30, 2013, the Company had sold all of the shares of Penn Virginia common stock, for total gross proceeds of approximately $50.6 million in cash, recognizing a gain of $8.3 million in other income.
Goodwill and Other Intangible Assets
During 2012, the Company recorded goodwill associated with the acquisition of the assets of TransTex Gas Services, LP, which represents the fair value of the acquired entity over the net amounts assigned to assets acquired and liabilities assumed. In accordance with GAAP, goodwill is not amortized to earnings, but is assessed annually in April for impairment, or whenever events or circumstances indicate that impairment of the carrying value of goodwill is likely. The Company has established April 1 as the annual testing date. If the carrying value of goodwill is determined to be impaired, it is reduced to its implied fair value with a corresponding charge to pretax earnings in the period in which it is determined to be impaired. Financial Accounting Standards Board ("FASB") Accounting Standards Update No. 2011-08, Intangibles - Goodwill and Other (Topic 350) permits an entity to first assess qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount as a basis for determining whether it is necessary to perform the two-step goodwill impairment test. The Company used this approach, and performed a full qualitative analysis of the need for impairment as of April 1, 2013. The Company performed a follow up analysis to determine if there were any triggering events as of December 31, 2013, and if an interim analysis was necessary, and none were determined to exist, as TransTex Gas Services, LP has experienced positive results on the Company's performance measures, and it has not experienced any significant adverse conditions.
Intangible assets consist primarily of the fair value of the acquired gas treating agreements and customer relationships in the TransTex Gas Services, LP assets acquisition. The intangible assets were valued at fair value using a discounted cash flow model with a discount rate at the date of acquisition of 13%. Such assets are being amortized over the weighted average term of 8.5 years. The customer relationships are being amortized with a 12.5 year life. The Company assesses the carrying amount of its other intangible assets for impairment when events or changes in circumstances indicate the carrying value may not be recoverable. At December 31, 2013, our other intangible assets were not impaired. See "Note 6 - Goodwill and Intangible Assets ".
Assets Held for Sale
Assets held for sale as of December 31, 2013 relate to the Company's interests in (i) Magnum Hunter Production, Inc. (“MHP”), a wholly-owned subsidiary of the Company whose oil and natural gas operations are located primarily in the southern Appalachian Basin in Kentucky and Tennessee, and (ii) the Canadian operations of Williston Hunter Canada, Inc., a wholly-owned subsidiary of the Company ("WHI Canada"). The Company is actively marketing these interests and anticipates completing the divestitures by the second quarter of 2014. Assets for sale as of December 31, 2012 relate to a drilling rig owned by Alpha Hunter Drilling, a subsidiary of Triad Hunter, LLC. The following table summarizes assets held for sale for the years indicated. See "Note 2 - Divestitures and Discontinued Operations.”
Asset Retirement Obligation
The asset retirement obligation ("ARO") primarily represents the estimated present value of the amount the Company will incur to plug, abandon and remediate our producing properties at the projected end of their productive lives, in accordance with applicable federal, state and local laws. The Company determined its ARO by calculating the present value of estimated cash flows related to the obligation. The retirement obligation is recorded as a liability at its estimated present value as of the asset’s inception, with an offsetting increase to proved properties. Periodic accretion of discount of the estimated liability is recorded as accretion expense in the consolidated statements of operations.
The liability is determined using significant assumptions, including current estimates of plugging and abandonment costs, annual inflation of these costs, the productive lives of wells and our risk-adjusted interest rate. Changes in any of these assumptions can result in significant revisions to the estimated ARO. The liability for current and long term AROs were approximately $0.1 million and $16.2 million, respectively, at December 31, 2013, and $2.4 million and $28.3 million, respectively, at December 31, 2012. The liability for current AROs is reported in other current liabilities. See "Note 7 - Asset Retirement Obligations".
Share-Based Compensation
The Company estimates the fair value of share-based payment awards made to employees and directors, including stock options, restricted stock and matching contributions of stock to employees under our employee stock ownership plan, on the date of grant using an option-pricing model. The value of the portion of the award that is ultimately expected to vest is recognized as an expense ratably over the requisite service periods. Awards that vest only upon achievement of performance criteria are recorded only when achievement of the performance criteria is considered probable. The Company estimated the fair value of each share-based award using the Black-Scholes option pricing model or a lattice model. These models are highly complex and dependent on key estimates by management. The estimates with the greatest degree of subjective judgment are the estimated lives of the stock-based awards, the estimated volatility of our stock price, and the assessment of whether the achievement of performance criteria is probable.
Income Taxes
Income taxes are accounted for in accordance with FASB ASC 740, under which deferred income taxes are recognized for the future tax effects of temporary differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities using the enacted statutory tax rates in effect at year-end. The effect on deferred taxes for a change in tax rates is recognized in earnings in the period that includes the enactment date. A valuation allowance for deferred tax assets is recorded when it is more likely than not that the benefit from the deferred tax asset will not be realized.
Uncertain Income Tax Positions
Under accounting standards for uncertainty in income taxes (ASC 740-10), a company recognizes a tax benefit in the financial statements for an uncertain tax position only if management's assessment is that the position is “more likely than not” (i.e., a likelihood greater than 50 percent) to be allowed by the tax jurisdiction based solely on the technical merits of the position. The term “tax position” in the accounting standards for income taxes refers to a position in a previously filed tax return or a position expected to be taken in a future tax return that is reflected in measuring current or deferred income tax assets and liabilities for interim or annual periods. The Company had no uncertain tax positions at December 31, 2013 or 2012.
Loss per Common Share
Basic net income or loss per common share is computed by dividing the net income or loss attributable to common shareholders by the weighted average number of shares of common stock outstanding during the period. Diluted net income or loss per common share is calculated in the same manner, but also considers the impact to net income and common shares for the potential dilution from stock options, stock warrants and any outstanding convertible securities.
The Company has issued potentially dilutive instruments in the form of our restricted common stock granted and not yet issued, common stock warrants, common stock options granted to our employees and directors, and our Series E Cumulative Convertible Preferred Stock. The Company did not include any of these instruments in its calculation of diluted loss per share during the periods because to include them would be anti-dilutive due to the Company's loss from continuing operations during the periods.
The following table summarizes the types of potentially dilutive securities outstanding as of December 31, 2013, 2012 and 2011:
Regulated Activities
Energy Hunter Securities, Inc. is a 100%-owned subsidiary and is a registered broker-dealer and member of the Financial Industry Regulatory Authority. Among other regulatory requirements, it is subject to the net capital provisions of Rule 15c3-1 under the Securities Exchange Act of 1934, as amended. Because it does not hold customer funds or securities or owe money or securities to customers, Energy Hunter Securities, Inc. is required to maintain minimum net capital equal to the greater of $5,000 or 6.67% of its aggregate indebtedness. At December 31, 2013 and 2012, Energy Hunter Securities, Inc. had net capital of $77,953 and $71,928, respectively, and aggregate indebtedness of $16,657 and $291,307, respectively.
Sentra Corporation, a 100%-owned subsidiary, owns and operates distribution systems for retail sales of natural gas in south central Kentucky. Sentra Corporation’s gas distribution billing rates are regulated by Kentucky’s Public Service Commission based on recovery of purchased gas costs. The Company accounts for its operations based on the provisions of ASC 980-605, Regulated
Operations-Revenue Recognition, which requires covered entities to record regulatory assets and liabilities resulting from actions of regulators. For the years ended December 31, 2013, 2012, and 2011, the Company had gas transmission, compression and processing revenue, reported in other revenue, which included gas utility sales from Sentra Corporation’s regulated operations aggregating $216,000, $511,000, and $61,000, respectively.
Other Comprehensive Income (Loss)
The functional currency of the Company's operations in Canada (which operations are reflected in these financial statements as discontinued operations) is the Canadian dollar. For purposes of consolidation, the Company translates the assets and liabilities of its Canadian subsidiary into U.S. dollars at current exchange rates while revenues and expenses are translated at the average rates in effect for the period. The related translation gains and losses are included in accumulated other comprehensive income. During the year ended December 31, 2013, 2012, and 2011 the Company recognized a translation loss of $10.9 million, a gain of $3.9 million, and a loss of $12.5 million, respectively.
Unrealized gains and losses on changes in fair value of common and preferred stock of publicly traded companies are included in accumulated other comprehensive income. As of September 30, 2013, the Company had completed the sale of all of the shares of the Penn Virginia common stock it acquired in connection with its sale of Eagle Ford Hunter in April 2013. The Company received gross proceeds of $50.6 million, resulting in a reclassification out of comprehensive income of $8.3 million, which is classified within other income.
NOTE 2 - DIVESTITURES AND DISCONTINUED OPERATIONS
Discontinued Operations
Sale of Hunter Disposal
On February 17, 2012, the Company, through its 100%-owned subsidiary, Triad Hunter, LLC, sold 100% of its equity ownership interest in Hunter Disposal, LLC, to a 100%-owned subsidiary of GreenHunter Resources, Inc., for total consideration of $9.3 million, comprised of cash of $2.2 million, 1,846,722 restricted common shares of GreenHunter Resources, Inc., valued at $2.6 million based on a closing price of $1.79 per share, discounted for restrictions, 88,000 shares of GreenHunter Resources, Inc. 10% Series C Preferred Stock, with a fair value of $1.9 million, and a promissory note of $2.2 million which is convertible, at the option of the Company, into 880,000 shares of GreenHunter Resources, Inc. common stock based on the conversion price of $2.50 per share. The Company recognized an embedded derivative asset resulting from the conversion option on the convertible promissory note with an initial fair value of $405,000. See "Note 3 - Fair Value of Financial Instruments". The cash proceeds from the sale were adjusted downward to $783,000 for changes in working capital and certain fees to reflect the effective date of the sale of December 31, 2011. Triad Hunter recognized a gain on the sale of discontinued operations of $3.7 million, $2.4 million net of tax of $1.3 million. GreenHunter Resources, Inc. is a related party as described in "Note 16 - Related Party Transactions".
Sale of Eagle Ford Hunter
On April 24, 2013, the Company closed on the sale of all of its ownership interest in its wholly-owned subsidiary, Eagle Ford Hunter to an affiliate of Penn Virginia for a total purchase price of approximately $422.1 million paid to the Company in the form of $379.8 million in cash (after estimated customary initial purchase price adjustments) and 10.0 million shares of common stock of Penn Virginia valued at approximately $42.3 million (based on the closing market price of the stock of $4.23 as of April 24, 2013). The effective date of the sale was January 1, 2013. Upon closing of the sale, $325.0 million of sale proceeds were used to pay down outstanding borrowings under the MHR Senior Revolving Credit Facility. During the third quarter of 2013, the Company had completed the sale of all of its Penn Virginia common stock for gross proceeds of $50.6 million, recognizing a gain of $8.3 million in other income. Initially, the Company has recognized a gain on the sale of $172.5 million, net of tax.
On August 24, 2013, the Company presented Penn Virginia with the Company’s estimate of the final settlement of the adjustments to the cash portion of the purchase price, to which Penn Virginia responded on October 21, 2013 with its calculation of the final adjustment amounts. On February 3, 2014, the Company submitted its updated calculation of the final adjustment amount to the arbitrator in the amount of $26.6 million (on a pre-tax basis) and Penn Virginia submitted its updated calculation of the final adjustment amount in the amount of $56.4 million. The Company is currently in the process of reviewing Penn Virginia’s calculation of the final adjustment amounts. As of December 31, 2013, the Company estimated that the final settlement of the adjustment amounts may result in an obligation to Penn Virginia ranging from $22 million to $33 million, net of taxes, but such estimate is subject to further review by the Company and discussions with Penn Virginia. Therefore, the Company has recorded a liability for its revised estimate of the final settlement of the adjustment amounts, after taxes, as a reduction in the gain on disposal of discontinued operations of Eagle Ford Hunter.
Planned Divestitures of Magnum Hunter Production and Williston Hunter Canada
In September 2013, the Company adopted a plan to divest all of its interests in (i) Magnum Hunter Production, Inc. (“MHP”), a wholly-owned subsidiary of the Company whose oil and natural gas operations are located primarily in the southern Appalachian Basin in Kentucky and Tennessee, and (ii) the Canadian operations of Williston Hunter Canada, Inc., a wholly-owned subsidiary of the Company ("WHI Canada"). The Company is actively marketing these interests and anticipates completing the divestitures by the second quarter of 2014. The Company has reclassified the associated assets and liabilities to assets and liabilities held for sale and the operations are reflected as discontinued operations for all periods presented. The Company has recorded an impairment expense of $56.7 million , net of tax, for the year ended December 31, 2013 relating to the discontinued operations which is recorded in income (loss) from discontinued operations and an expense of $92.4 million, net of tax, to reflect the net assets at their estimated selling prices, less costs to sell, which is recorded in loss on disposal of discontinued operations for the year ended December 31, 2013.
The Company included the results of operations of MHP and WHI Canada for all periods presented, Eagle Ford Hunter through April 24, 2013, and Hunter Disposal through February 17, 2012 in discontinued operations as follows:
_____________________
(1)
Includes impairment expense of $78.5 million, $324,000, and none for the years ended December 31, 2013, 2012, and 2011, respectively, and exploration expense of $19.6 million, $38.7 million, and none for the years ended December 31, 2013, 2012, and 2011, respectively relating to the discontinued operations of MHP and WHI Canada, which is recorded in income (loss) from discontinued operations.
(2)
The Company’s effective tax rate on the loss from discontinued operations is 6.2% primarily due to the significant losses generated in WHI Canada, which has an overall lower statutory tax rate further lowered by the utilization of certain net operating losses.
(3)
Income tax expense associated with gain/(loss) on sale of discontinued operations was $1.4 million, $1.3 million, and none for the years ended December 31, 2013, 2012, and 2011, respectively.
(4)
The Company’s effective tax rate on the gain on disposal of discontinued operations is 2.6% primarily due to the anticipated utilization of a capital loss on the sale of WHI Canada against the capital gains included in discontinued operations.
Other Divestitures
Sale of Certain North Dakota Oil and Natural Gas Properties
On September 2, 2013, Williston Hunter, Inc., a wholly owned subsidiary of the Company, entered into a purchase and sale agreement with Oasis Petroleum of North America LLC, or Oasis, to sell its non-operated working interest in certain oil and natural gas properties located in Burke County, North Dakota, to Oasis for $32.5 million in cash, subject to customary adjustments. The transaction closed on September 26, 2013, and was effective as of July 1, 2013. The Company recognized a loss of $38.1 million on the sale for the year ended December 31, 2013.
On December 30, 2013, PRC Williston, LLC and Williston Hunter ND, LLC , subsidiaries of the Company, closed on the sale of certain assets to Enduro Operating LLC, (“Enduro”). The Enduro sale included certain oil and gas properties and assets located in Burke, Renville, Bottineau and McHenry Counties, North Dakota, including operated working interests in approximately 180 wells producing primarily from the Madison formation in the Williston Basin. The effective date of the sale was September 1, 2013. The total purchase price, after initial purchase price adjustments, was $44.1 million in cash. The Company recognized a preliminary loss of $8.2 million and final determination of the customary adjustments to the purchase price will be made by the parties approximately 120 days after closing.
NOTE 3 - FAIR VALUE OF FINANCIAL INSTRUMENTS
Accounting standards define fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The standards also establish a framework for measuring fair value and a valuation hierarchy based upon the transparency of inputs used in the valuation of an asset or liability. Classification within the hierarchy is based upon the lowest level of input that is significant to the fair value measurement. The valuation hierarchy contains three levels:
●
Level 1 - Quoted prices (unadjusted) for identical assets or liabilities in active markets;
●
Level 2 - Quoted prices for similar assets or liabilities in active markets; quoted prices for identical or similar assets or liabilities in markets that are not active; and model-derived valuations whose inputs or significant value drivers are observable;
●
Level 3 - Significant inputs to the valuation model are unobservable.
The Company used the following fair value measurements for certain of its assets and liabilities during the years ended December 31, 2013 and 2012:
Level 1 Classification:
Available for Sale Securities
At December 31, 2013, the Company held common and preferred stock of companies publicly traded on the TSX Venture Exchange and the NYSE MKT (formerly NYSE Amex) with quoted prices in active markets. Accordingly, the fair market value measurements of these securities have been classified as Level 1.
Level 2 Classification:
Commodity Derivative Instruments
At December 31, 2013 and December 31, 2012, the Company had commodity derivative financial instruments in place. The Company does not designate its derivative instruments as hedges and therefore does not apply hedge accounting. Changes in fair value of derivative instruments subsequent to the initial measurement are recorded as gain (loss) on derivative contracts, in other income (expense). The estimated fair values of the Company’s derivative instruments have been determined at discrete points in time based on relevant market information which resulted in the Company classifying such derivatives as Level 2. Although the Company’s derivative instruments are valued using public indices, the instruments themselves are traded with unrelated counterparties and are not openly traded on an exchange. See "Note 4 - Financial Instruments and Derivatives".
As of December 31, 2013 and December 31, 2012, the Company’s derivative contracts were with financial institutions, all of which were either senior lenders to the Company or affiliates of such senior lenders, and some of which had investment grade credit ratings. All of the counterparties are believed to have minimal credit risk. Although the Company is exposed to credit risk to the extent of nonperformance by the counterparties to these derivative contracts, the Company does not anticipate such nonperformance and monitors the credit worthiness of its counterparties on an ongoing basis.
Level 3 Classification:
Preferred Stock Embedded Derivative
At December 31, 2013, the Company had preferred stock derivative liabilities resulting from certain conversion features, redemption options, and other features of its Series A Convertible Preferred Units of Eureka Hunter Holdings, LLC. See "Note 11 - Redeemable Preferred Stock".
The preferred stock embedded derivative was valued using the “with and without” analysis in a simulation model. The key inputs used in the model to determine fair value at December 31, 2013 were a volatility of 25.0%, credit spread of 13.90%, and an estimated enterprise value of Eureka Hunter Holdings of $568.0 million.
Convertible Security Embedded Derivative
The Company recognized an embedded derivative asset resulting from the fair value of the bifurcated conversion feature associated with the convertible note received as partial consideration upon the sale of Hunter Disposal, LLC ("Hunter Disposal") to GreenHunter Resources, Inc. ("GreenHunter"), a related party. See "Note 2 - Divestitures and Discontinued Operations". The convertible security embedded derivative was valued using a Black-Scholes model valuation of the conversion option.
The key inputs used in the Black-Scholes option pricing model were as follows:
The following table presents the changes in the fair value of the derivative assets and liabilities measured at fair value using significant unobservable inputs for the year ended December 31, 2013:
The following tables present financial assets and liabilities which are adjusted to fair value on a recurring basis at December 31, 2013 and 2012:
Other Fair Value Measurements
The carrying value of the Company's senior revolving credit facility (the “MHR Senior Revolving Credit Facility") approximates fair value as it is subject to short-term floating interest rates that approximate the rates available to us for those periods. The fair value hierarchy for the MHR Senior Revolving Credit Facility is Level 3.
The fair value of the Company's Senior Notes is based on quoted market prices available for our senior notes. The estimated fair value of the Company's Senior Notes as of December 31, 2013 and December 31, 2012 was $651.3 million and $613.5 million, respectively. The fair value hierarchy for the Company's Senior Notes is Level 2 (quoted prices for similar assets in active markets).
The fair value of Eureka Hunter Pipeline's second lien term loan is the estimated cost to acquire the debt, including a credit spread for the difference between the issue rate and the period end market rate. The credit spread is the Company’s default or repayment risk. The credit spread (premium or discount) is determined by comparing the Company’s fixed-rate notes and credit facility to new issuances (secured and unsecured) and secondary trades of similar size and credit statistics for both public and private debt. The fair value of all fixed-rate notes and the credit facility is based on interest rates currently available to the Company. Eureka Hunter Pipeline's second lien term loan is valued using an income approach and classified as Level 3 in the fair value hierarchy.
The Company uses available market data and valuation methodologies to estimate the fair value of debt. The carrying amounts and fair values of long-term debt are as follows:
________________________________
(1) The fair value of the Company's Senior Notes is based on quoted market prices.
(2) The carrying value of each of the MHR Senior Revolving Credit Facility and Magnum Hunter's second lien term loan approximates fair value as it is subject to short-term floating interest rates that approximate the rates available to us at such date.
(3) The fair value of (a) Eureka Hunter Pipeline’s second lien term loan and (b) equipment note payable, is the estimated cost to acquire the debt, including a credit spread for the difference between the issue rate and the period end market rate.
Fair Value on a Non-Recurring Basis
The Company follows the provisions of ASC 820-10 for nonfinancial assets and liabilities measured at fair value on a non-recurring basis. As it relates to Magnum Hunter, ASC 820-10 applies to certain nonfinancial assets and liabilities as may be acquired in a business combination and thereby measured at fair value; measurements of oil and natural gas property impairments; and the initial recognition of AROs, for which fair value is used. These ARO estimates are derived from historical costs as well as management's expectation of future cost environments. As there is no corroborating market activity to support the assumptions used, Magnum Hunter has designated these measurements as Level 3.
A reconciliation of the beginning and ending balances of Magnum Hunter's ARO is presented in "Note 7 - Asset Retirement Obligations".
New fair value measurements of proved oil and natural gas properties during the year ended December 31, 2013 and 2012 consist of:
________________________________
(1) The Company recorded impairment charges from continuing operations of $10.0 million and $3.8 million during the years ended December 31, 2013 and 2012, respectively, as a result of writing down the carrying value of certain properties to fair value. In order to determine fair value, Magnum Hunter compares net capitalized costs of proved oil and natural gas properties to estimated undiscounted future net cash flows using management's expectations of economically recoverable reserves. If the net capitalized cost exceeds the undiscounted future net cash flows, Magnum Hunter impairs the net cost basis down to the discounted future net cash flows, which is management's estimate of fair value. Significant inputs used to determine the fair value include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average
cost of capital rate. The underlying commodity prices embedded in the Company's estimated cash flows are the product of a process that begins with third party analyst forward curve pricing, adjusted for estimated location and quality differentials, as well as other factors that Magnum Hunter's management believes will impact realizable prices. The inputs used by management for the fair value
measurements utilized in this review include significant unobservable inputs, and therefore, the fair value measurements employed are classified as Level 3 for these types of assets.
(2)Magnum Hunter records the fair value of assets and liabilities acquired in business combinations. During the year ended December 31, 2012, Magnum Hunter acquired oil and natural gas properties with a fair value of $532.2 million. Properties acquired are recorded at fair value, which correlates to the discounted future net cash flow. Significant inputs used to determine the fair value of proved properties include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital rate. The underlying commodity prices embedded in the Company's estimated cash flows are the product of a process that begins with third party analyst forward curve pricing, adjusted for estimated location and quality differentials, as well as other factors that Magnum Hunter's management believes will impact realizable prices. For acquired unproved properties, the market-based weighted average cost of capital rate is subjected to additional project specific risking factors. The inputs used by management for the fair value measurements of these acquired oil and natural gas properties include significant unobservable inputs, and therefore, the fair value measurements employed are classified as Level 3 for these types of assets.
NOTE 4 - FINANCIAL INSTRUMENTS AND DERIVATIVES
The Company periodically enters into certain commodity derivative instruments such as futures contracts, swaps, collars, and basis swap contracts, which are effective in mitigating commodity price risk associated with a portion of its future monthly natural gas and crude oil production and related cash flows. The Company has not designated any of its commodity derivatives as hedges under ASC 815.
In a commodities swap agreement, the Company trades the fluctuating market prices of oil or natural gas at specific delivery points over a specified period, for fixed prices. As a producer of oil and natural gas, the Company holds these commodity derivatives to protect the operating revenues and cash flows related to a portion of its future natural gas and crude oil sales from the risk of significant declines in commodity prices, which helps reduce exposure to price risk and improves the likelihood of funding its capital budget. If the price of a commodity rises above what the Company has agreed to receive in the swap agreement, the amount that it agreed to pay the counterparty would theoretically be offset by the increased amount it received for its production.
The Company also enters into three-way collars with third parties. These instruments typically establish two floors and one ceiling. Upon settlement, if the index price is below the lowest floor, the Company receives the difference between the two floors. If the index price is between the two floors, the Company receives the difference between the higher of the two floors and the index price. If the index price is between the higher floor and the ceiling, the Company does not receive or pay any amounts. If the index price is above the ceiling, the Company pays the excess over the ceiling price. The advantage to the Company of the three-way collar is that the proceeds from the second floor allow us to lower the total cost of the collar.
The Company's failure to service any of its debt or to comply with any of its debt covenants (including failures stemming from its late SEC filings) could result in a default under the related debt agreement, and under any commodity derivative contract under which such debt default is a cross-default, which could result in the early termination of the commodity derivative contract (and an early termination payment obligation) and/or otherwise materially adversely affect its business, financial condition and results of operations.
The table below is a summary of the Company's commodity derivatives as of December 31, 2013:
________________________________
(1) A collar is a sold call and a purchased put. Some collars are "costless" collars with the premiums netting to approximately zero.
(2) These three-way collars are a combination of three options: a sold call, a purchased put and a sold put.
Currently, Bank of Montreal, KeyBank National Association, Credit Suisse Energy, LLC, Bank of America - Merrill Lynch, Deutsche Bank AG London Branch, Citibank, N.A., J. Aron & Company, an affiliate of Goldman Sachs, are the only counterparties to the Company's commodity derivatives positions. The Company is exposed to credit losses in the event of nonperformance by the counterparties on its commodity derivatives positions. However, the Company does not anticipate nonperformance by the counterparties over the term of the commodity derivatives positions. All counterparties or their affiliates are participants in the Company's senior revolving credit facility, and the collateral for the outstanding borrowings under its senior revolving credit facility is used as collateral for its commodity derivatives with those counterparties.
At December 31, 2013, the Company has preferred stock derivative liabilities resulting from certain conversion features, redemption options, and other features of its Series A Convertible Preferred Units of Eureka Hunter Holdings, LLC. See "Note 3 - Fair Value of Financial Instruments" and "Note 10 - Shareholders' Equity".
At December 31, 2013, the Company also has a convertible security embedded derivative asset primarily due to the conversion feature of the promissory note receivable from GreenHunter Resources, Inc. received as partial consideration for the sale of Hunter Disposal, LLC. See "Note 3 - Fair Value of Financial Instruments", "Note 2 - Divestitures and Discontinued Operations" and "Note 16 - Related Party Transactions".
The following table summarizes the fair value of the Company's derivative contracts as of the dates indicated:
The following table summarizes the net gain (loss) on all derivative contracts included in other income (expense) on the consolidated statements of operations for the years ended December 31, 2013, 2012 and 2011:
NOTE 5 - ACQUISITIONS
The Company has recognized $2.8 million, $4.7 million, and $8.9 million of transaction expenses related to acquisitions in its general and administrative expenses for the years ended December 31, 2013, 2012, and 2011, respectively. Substantially all of the Company's acquisitions contained a significant amount of unproved acreage, as is consistent with the Company's business strategy.
Utica Shale Assets Acquisition
On February 17, 2012, the Company closed on the acquisition of leasehold mineral interests located predominately in Noble County, Ohio for a total purchase price of $24.8 million in cash.
Eagle Operating Assets Acquisition
On March 30, 2012, the Company, through its wholly-owned subsidiary, Williston Hunter ND, LLC, a Delaware limited liability company (“Williston Hunter”), closed on the purchase of operating working interest in certain oil and gas leases and wells located in several counties in North Dakota from Eagle Operating, Inc. (“Eagle Operating”), an unrelated third party, effective April 1, 2011. Total consideration was $52.9 million consisting of $51.0 million in cash and 296,859 shares of Magnum Hunter restricted common stock valued at $1.9 million based on a price of $6.41 per share. The purpose of the acquisition was to expand the Company’s position in the Williston Basin. The Company already owned a non-operated ownership interest in the properties acquired.
The acquisition was accounted for using the acquisition method of accounting, which requires the net assets acquired to be recorded at their fair values. The following table summarizes the purchase price and the estimates of fair values of the net assets acquired (in thousands, except shares and per share information):
TransTex Gas Services, LP Assets Acquisition
On April 2, 2012, the Company, through its majority owned subsidiary, Eureka Hunter Holdings, LLC, and its wholly-owned subsidiary, Eureka Hunter Acquisition Sub, LLC, closed on their purchase of certain assets of TransTex Gas Services, LP (“TransTex”), a related third party, under an asset purchase agreement dated March 21, 2012, which resulted in the recognition of approximately $30.6 million in goodwill and $10.5 million of intangible assets. See "Note 6 - Goodwill and Intangible Assets". The Company expects all of the goodwill, which is associated with the Company’s midstream operating segment, to be deductible for tax purposes. The purpose of the acquisition was to complement the Company’s existing midstream assets. The total purchase price paid for the acquired assets was $58.5 million, comprised of $46.0 million in cash and 622,641 Eureka Hunter Holdings Class A Common Units representing membership interests in Eureka Hunter Holdings, with a value of $12.5 million based on an estimated enterprise value of $400.0 million at that time determined utilizing a discounted future cash flow analysis.
The following table summarizes the purchase price and the estimates of fair values of the net assets acquired from TransTex (in thousands):
Gary C. Evans, the Company's Chairman and CEO, previously held a small limited partnership interest in TransTex, and participated in the purchase of certain Eureka Hunter Holdings Class A Common Units offered to all limited partners of TransTex in connection with the acquisition. See "Note 16 - Related Party Transactions".
Baytex Energy USA Assets Acquisition
On May 22, 2012, the Company, through its wholly-owned subsidiary, Bakken Hunter, LLC, closed on the acquisition of certain Williston Basin assets of Baytex Energy USA, Ltd. (“Baytex Energy USA”), an affiliate of Baytex Energy Corporation, an unrelated third party, for a total purchase price of $312.0 million. The purpose of the acquisition was to significantly increase the Company’s ownership interest in existing mineral leases in a key shale play where the Company has increased its drilling activities. To a lesser extent, proved reserves were added attributable to the acquired properties. The acquired assets include all of Baytex Energy USA’s non-operated working interest in oil and gas properties and wells located in Divide and Burke Counties, North Dakota, within an area subject to an operating agreement among Samson Resources Company, as operator, Baytex Energy Corporation, and Williston Hunter, Inc., a wholly-owned subsidiary of Magnum Hunter.
The following table summarizes the purchase price and the preliminary estimates of fair values of the net assets acquired (in thousands):
Acquisition of Viking International Resources Co., Inc.
On November 2, 2012, Triad Hunter, LLC, a wholly-owned subsidiary of the Company, closed on the acquisition of all outstanding capital stock of Viking International Resources Co., Inc. (“Virco”) effective January 1, 2012. The total fair market value of consideration paid was approximately $100.8 million, made up of approximately $37.3 million paid in cash and 2,774,850 depositary shares representing 2,774.85 shares of 8.0% Series E Cumulative Convertible Preferred Stock of the Company with market value of approximately $65.2 million and stated liquidation preference of approximately $69.4 million. See "Note 10 - Shareholders' Equity" regarding the Series E Preferred Stock. The primary purpose of the acquisition was to acquire leasehold acreage and wells complementary to the Company's existing acreage position of this region and expand its ownership interest in the Marcellus Shale and Utica Shale plays in West Virginia and Ohio.
The following table summarizes the purchase price and the preliminary estimates of fair values of the net assets acquired (in thousands):
Samson Resources Assets Acquisition
On December 20, 2012, Bakken Hunter, LLC, a wholly-owned subsidiary of the Company, closed on the acquisition of certain existing wells and Williston Basin lease acres located in Divide County, North Dakota from Samson Resources Company. The purchase price for the assets was $30.0 million in cash, subject to customary adjustments. The effective date of the transaction was August 1, 2012.
With the closing of this transaction, the Company owns varied working ownership interests in these properties up to approximately 100%. The acquisition established the Company as an operator in certain of this Bakken acreage, covering four Townships and Ranges in northern Divide County, North Dakota, previously operated by Samson Resources Company.
Agreement to Purchase Utica Shale Acreage
On August 12, 2013, Triad Hunter entered into an asset purchase agreement, with MNW. MNW is an Ohio limited liability company that represents an informal association of various land owners, lessees and sub-lessees of mineral acreage who own or have rights in mineral acreage located in Monroe, Noble and/or Washington Counties, Ohio. Pursuant to the purchase agreement, Triad Hunter
has agreed to acquire, subject to certain conditions, from MNW up to 32,000 net mineral acres, including currently leased and subleased acreage, located in such counties, over the next 10 months or possibly longer. The maximum purchase price, if MNW delivers 32,000 acres with acceptable title, would be $142.1 million, excluding title costs. During 2013, Triad Hunter purchased leasehold acreage from MNW for an aggregate purchase price of $24.5 million.
The following summarizes the revenue and operating income (loss) from the acquisitions included in the Company's consolidated statements of operations for the years ended December 31, 2013 and 2012:
The following unaudited summary, prepared on a pro forma basis, presents the results of operations for the year ended December 31, 2012, as if the above acquisitions along with transactions necessary to finance the acquisitions, had occurred as of the beginning of 2012. The pro forma information includes the effects of adjustments for interest expense, depreciation and depletion expense, and dividend expense. The pro forma results are not necessarily indicative of what actually would have occurred if the acquisition had been completed as of the beginning of each period presented, nor are they necessarily indicative of future consolidated results. The Company determined that pro forma presentation of the leasehold acreage acquired from MNW was not necessary, as the acquisitions were not significant to its balance sheet and the undeveloped acreage had no operating results.
NOTE 6 - GOODWILL AND INTANGIBLE ASSETS
Goodwill
Goodwill represents the excess of the purchase price of an entity over the estimated fair value of the assets acquired and the liabilities assumed. The Company assesses the carrying amount of goodwill by testing the goodwill for impairment annually or whenever interim impairment indicators arise. Goodwill of $30.6 million was recorded related to the Company's midstream segment during 2012 as a result of its acquisition of the assets of TransTex Gas Services, LP, discussed in "Note 5 - Acquisitions". The Company assessed goodwill for impairment on April 1, 2013, and determined that no impairment existed. The Company updated its annual impairment test through December 31, 2013, with an evaluation of any triggering events or circumstances that would indicate that impairment of the carrying value of goodwill is likely, and none were determined to exist.
Intangible Assets
Intangible assets consist primarily of the fair value of the acquired gas treating agreements and customer relationships in the TransTex Gas Services, LP assets acquisition completed in 2012. The intangible assets were valued at fair value using a discounted cash flow model with a discount rate of 13%. Such assets are being amortized over the weighted average term of 8.54 years.
The following table summarizes the Company's changes in intangible assets during the years ended December 31, 2013 and 2012:
The following table summarizes the aggregate amortization of intangible assets over the next five years:
NOTE 7 - ASSET RETIREMENT OBLIGATIONS
The Company's ARO primarily represents the estimated present value of the amount the Company will incur to plug, abandon and remediate its producing properties at the end of their productive lives, in accordance with applicable federal, state and local laws. The Company determined its ARO by calculating the present value of estimated cash flows related to the liability. The retirement obligation is recorded as a liability at its estimated present value as of the asset’s inception, with a corresponding increase to proved properties. The Company records accretion of the estimated liability as accretion expense in depreciation, depletion, amortization, and accretion in the consolidated statements of operations.
The Company's liability is determined using significant assumptions, including current estimates of plugging and abandonment costs, annual inflation of these costs, the productive lives of wells and its risk-adjusted interest rate. Changes in any of these assumptions can result in significant revisions to the estimated ARO. Revisions to the ARO are recorded with a corresponding change to producing properties, resulting in prospective changes to depreciation, depletion and amortization expense and accretion of discount. Because of the subjectivity of assumptions and the relatively long lives of most of the Company's wells, the costs to ultimately retire its wells may vary significantly from prior estimates. The Company's liability for AROs was approximately $16.2 million and $30.7 million at December 31, 2013 and 2012, respectively.
The Company's midstream operating assets generally consist of underground pipelines and related components along rights-of-way and above ground storage tanks and related facilities. The Company's right-of-way agreements typically do not require the dismantling, removal and reclamation of the right-of-way upon permanent cessation of pipeline service. Additionally, management is unable to predict when, or if, the Company's pipelines, storage tanks and related facilities would become completely obsolete and require decommissioning. Accordingly, the Company has recorded no liability or corresponding asset as an ARO as both the amounts and timing of such future costs are indeterminable.
The following table summarizes the changes in the Company’s ARO transactions during the years ended December 31, 2013 and 2012:
NOTE 8 - LONG-TERM DEBT
Notes payable at December 31, 2013 and 2012 consisted of the following:
_________________
(1) Includes notes classified as liabilities associated with assets held for sale of which $163,000 is current and $3.8 million is long term
The following table presents the approximate annual maturities of debt, gross of unamortized discount:
Senior Notes
On May 16, 2012, the Company completed the issuance of $450.0 million aggregate principal amount of its 9.75% Unregistered Senior Notes which mature on May 15, 2020 for total proceeds of $431.2 million net of issuing costs of $12.8 million, resulting in a discount of $6.0 million.
On December 13, 2012, the Company completed the issuance of an additional $150.0 million aggregate principal amount of its 9.75% Unregistered Senior Notes for total proceeds of $149.9 million net of issuing costs of $3.1 million, resulting in a premium of $3.0 million.
On November 8, 2013 we completed an exchange offer pursuant to which we exchanged $600 million of Senior Notes registered under the Securities Act for all of the Unregistered Notes. We refer to the exchange Senior Notes as the Exchange Notes or our Senior Notes. The Exchange Notes have substantially identical terms to our former Unregistered Senior Notes except the Exchange Notes are generally freely transferable under the Securities Act.
The Senior Notes are unsecured and are guaranteed, jointly and severally, on a senior unsecured basis by certain of the Company’s domestic subsidiaries. The indenture governing the Senior Notes permits a guarantor of the Senior Notes to be released from its guarantee under certain circumstances, including in connection with a sale or other disposition of all or substantially all of the assets of the guarantor, a sale of other disposition of the capital stock of the guarantor to a third party, or upon the liquidation or dissolution of the guarantor.
Interest on the Senior Notes is paid semi-annually in arrears on May 15 and November 15 of each year. The Company paid penalty interest totaling $1.1 million during 2013 due to its untimely filing of a Registration Statement on Form S-4 to consummate an exchange offer.
The Company used the net proceeds of the Senior Notes, together with other sources of liquidity, (i) to finance a portion of the $312.0 million acquisition of oil properties in the Williston Basin from Baytex Energy USA, Ltd., which closed on May 22, 2012, (ii) to pay off all amounts outstanding under the Company’s second lien term loan, (iii) to repay outstanding debt under the Company’s senior revolving credit facility, (iv) for capital expenditures and (v) general corporate purposes.
The Senior Notes were issued pursuant to an indenture entered into on May 16, 2012 as supplemented, among the Company, the subsidiary guarantors party thereto, Wilmington Trust, National Association, as the trustee, and Citibank, N.A., as the paying agent, registrar and authenticating agent. The terms of the Senior Notes are governed by the indenture, which contains affirmative and restrictive covenants that, among other things, limit the Company’s and the guarantors’ ability to incur or guarantee additional indebtedness or issue certain preferred stock; pay dividends on capital stock or redeem, repurchase or retire capital stock or subordinated indebtedness or make certain other restricted payments; transfer or sell assets; make loans and other investments; create or permit to exist certain liens; enter into agreements that restrict dividends or other payments from restricted subsidiaries to the Company; consolidate, merge or transfer all or substantially all of their assets; engage in transactions with affiliates; and create unrestricted subsidiaries.
The indenture also contains events of default. Upon the occurrence of events of default arising from certain events of bankruptcy or insolvency, the Senior Notes shall become due and payable immediately without any declaration or other act of the trustee or the holders of the Senior Notes. Upon the occurrence of certain other events of default, the trustee or the holders of at least 25% in aggregate principal amount of the then outstanding Senior Notes may declare all outstanding Senior Notes to be due and payable immediately.
At December 31, 2013, the Company was in compliance with all of its requirements under the indenture related to the Senior Notes.
The Senior Notes are redeemable by the Company at any time on or after May 15, 2016, at the redemption price of 104.875%, after May 15, 2017, at the redemption price of 102.438%, and after May 15, 2018, at the redemption price of 100.00%. The Senior Notes are redeemable by the Company prior to May 15, 2016 at the redemption price equal to 100.00% of the principal amount of the notes redeemed, plus a “make-whole” premium of the greater of:
(1)1.0% of the principal amount of the note; and
(2)The excess of:
(a)
The present value at such redemption date of (i) the redemption price of the note at May 15, 2016 plus (ii) all required interest payments due on the note through May 15, 2016 (excluding accrued but unpaid interest to the redemption date), computed using a discount rate equal to the treasury rate as of such redemption date plus 50 basis points discounted to such redemption date on a semi-annual basis, over
(b)
The principal amount of the note.
The Company is also entitled to redeem up to 35% of the aggregate principal amount of the Senior Notes before May 15, 2015 with net proceeds that the Company raises in certain equity offerings at a redemption price of 109.750%, so long as at least 65% of the aggregate principal amount of the Senior Notes issued under the indenture (excluding Senior Notes held by the Company) remains outstanding immediately after such redemption and the redemption occurs within 180 days of the closing date of such equity offering. If the Company experiences certain change of control events, each holder of Senior Notes may require the Company to repurchase all or a portion of the Senior Notes for cash at a price equal to 101% of the aggregate principal amount of such Senior Notes, plus any accrued and unpaid interest up to, but not including the date of repurchase.
Eureka Hunter Pipeline Credit Facilities
On August 16, 2011, Eureka Hunter Pipeline, LLC (“Eureka Hunter Pipeline ”), a majority-owned subsidiary of the Company, entered into (i) a First Lien Credit Agreement (the “First Lien Agreement”) by and among Eureka Hunter Pipeline, the lenders party thereto and SunTrust Bank, as administrative agent, and (ii) a Second Lien Term Loan Agreement (the “Second Lien Agreement”), by and among Eureka Hunter Pipeline, the lenders party thereto and U.S. Bank National Association, as collateral agent (the First Lien Agreement and the Second Lien Agreement being collectively referred to as the “Eureka Credit Agreements”).
The First Lien Agreement provides for a revolving credit facility (the “Revolver”) in an aggregate principal amount of up to $100 million (with an initial committed amount of $25 million), secured by a first lien on substantially all of the assets of Eureka Hunter Pipeline. The Second Lien Agreement provides for a $50 million term loan facility (the “Term Loan”), secured by a second lien on substantially all of the assets of Eureka Hunter Pipeline. The entire $50 million Term Loan had previously been drawn. As of May 1, 2013, the revolving credit facility was not available due to the Company's inability to satisfy certain financial ratios included in the agreement. The Revolver has a maturity date of August 16, 2016, and the Term Loan has a maturity date of August 16, 2018. Both the Revolver and the Term Loan are non-recourse to Magnum Hunter Resources Corporation. See "Effect of Late SEC Filings on Liquidity and Capital Resources."
The terms of the First Lien Agreement provide that the Revolver may be used for (i) revolving loans, (ii) swingline loans in an aggregate amount of up to $5 million at any one time outstanding, or (iii) letters of credit in an aggregate amount of up to $5 million at any one time outstanding. The Revolver provides for a commitment fee of 0.5% per annum based on the unused portion of the commitment under the Revolver.
Borrowings under the Revolver will, at Eureka Hunter Pipeline’s election, bear interest at:
•
a base rate equal to the highest of (i) the prime lending rate announced from time to time by the Administrative Agent, (ii) the then-effective Federal Funds Rate (as definited in the Eureka Hunter Pipeline Revolver) plus 0.5% per annum, or (iii) the Adjusted LIBO Rate (as defined in the First Lien Agreement) for a one-month interest period on such day plus 1.0% per annum, plus an applicable margin ranging from 1.25% to 2.25%; or
•
the Adjusted LIBO Rate, plus an applicable margin ranging from 2.25% to 3.5%.
Borrowings under the Term Loan will bear interest at 12.50% per annum in cash (increasing to 13.50% on and at all times when Eureka Hunter Pipeline and its subsidiaries incur indebtedness (other than the Term Loan) in excess of $1 million).
If an event of default occurs under either the Revolver or the Term Loan, the lenders may increase the interest rate then in effect by an additional 2.0% per annum for the period that the default exists under the Revolver or the Term Loan.
The Eureka Credit Agreements contain negative covenants that, among other things, restrict the ability of Eureka Hunter Pipeline and its subsidiaries to, with certain exceptions: (1) incur indebtedness; (2) grant liens; (3) dispose of all or substantially all of its assets or enter into mergers, consolidations, or similar transactions; (4) change the nature of its business; (5) make investments, loans, or advances or guarantee obligations; (6) pay cash dividends or make certain other payments; (7) enter into transactions with affiliates; (8) enter into sale and leaseback transactions; (9) enter into hedging transactions; (10) amend its organizational documents or material agreements; or (11) make certain undisclosed capital expenditures.
The Eureka Credit Agreements also require Eureka Hunter Pipeline to satisfy certain financial covenants, including maintaining:
•
a consolidated total debt to capitalization ratio of not more than 60%;
•
a ratio of consolidated EBITDA to consolidated interest expense, in each case, for the four fiscal quarter period then ended ranging from:
(i) for the Term Loan, not less than (A) 2.25 to 1.00, for the fiscal quarters ending December 31, 2013 and March 31, 2014, (B) 2.50 to 1.00, for the fiscal quarters ending June 30, 2014 and September 30, 2014, and (C) 2.75 to 1.0 for the fiscal quarter ending December 31, 2014 and each fiscal quarter ending thereafter, and
(ii) in the event any portion of the Revolver has been drawn, for the Revolver, not less (A) 2.50 to 1.00, for the fiscal quarters ending December 31, 2013 and March 31, 2014, (B) 2.75 to 1.00, for the fiscal quarters ending June 30, 2014 and September 30, 2014, and (C) 3.00 to 1.0 for the fiscal quarter ending December 31, 2014 and each fiscal quarter ending thereafter;
•
a ratio of consolidated total debt to consolidated EBITDA for the four fiscal quarter period then ended ranging from:
(i) for the Term Loan, not greater than (A) 4.50 to 1.0 for the fiscal quarters ending December 31, 2013, March 31, 2014, June 30, 2014, and September 30, 2014, and (B) 4.25 to 1.0 for the fiscal quarter ending December 31, 2014 and each fiscal quarter ending thereafter, and
(ii) in the event any portion of the Revolver has been drawn, for the Revolver, not greater than (A) 4.50 to 1.0 for the fiscal quarters ending December 31, 2013 and March 31, 2014, and (B) 4.00 to 1.0 for the fiscal quarter ending June 30, 2014 and each fiscal quarter ending thereafter; and
•
a ratio of consolidated debt under the Revolver to consolidated EBITDA of (i) for the Term Loan, not greater than 3.5 to 1.0, and (ii) for the Revolver, if any portion of the Revolver has been drawn, not greater than 3.25 to 1.0 for each fiscal quarter.
The obligations of Eureka Hunter Pipeline under each of the Revolver and the Term Loan may be accelerated upon the occurrence of an Event of Default (as such term is defined in such Eureka Credit Agreement) under such Eureka Credit Agreement. Events of Default include customary events for these types of financings, including, among others, payment defaults, defaults in the performance of affirmative or negative covenants, the inaccuracy of representations or warranties, defaults under the Term Loan (with respect to the Revolver) or the Revolver (with respect to the Term Loan), defaults relating to judgments, material defaults under certain material contracts of Eureka Hunter Pipeline, and defaults by the Company which cause the acceleration of the Company’s debt under its existing MHR Senior Revolving Credit Facility.
Under the Eureka Credit Agreements, (i) Eureka Hunter Pipeline and its subsidiaries have entered into customary ancillary agreements and arrangements, which provide that the obligations under the Eureka Credit Agreement are secured by substantially all of the assets of Eureka Hunter Pipeline and such subsidiaries, consisting primarily of pipelines, pipeline rights-of-way, and gas treating and processing equipment and certain other equipment, and (ii) Eureka Hunter Holdings, the sole parent of Eureka Hunter Pipeline and a majority owned subsidiary of the Company, entered into customary ancillary agreements and arrangements, which granted the lenders under the Eureka Credit Agreements a non-recourse security interest in Eureka Hunter Holdings' equity interests in Eureka Hunter Pipeline.
Availability under the Revolver is subject to satisfaction of certain financial covenants that are tested on a quarterly basis.
At December 31, 2013, the Company was in compliance with all of its covenants, as amended or waived, contained in the Eureka Hunter Pipeline credit facilities.
Eureka Hunter Pipeline had loans outstanding under this second lien facility of $50.0 million as of December 31, 2013 and 2012.
The Amended and Restated Limited Liability Company Agreement of Eureka Hunter Holdings, referred to as the EH Operating Agreement, contains certain covenants that, among other things, restrict the ability of Eureka Hunter Holdings and its subsidiaries, including Eureka Hunter Pipeline and TransTex Hunter, LLC, to, with certain exceptions:
•
incur funded indebtedness, whether direct or contingent;
•
issue additional equity interests;
•
pay distributions to its owners, or repurchase or redeem any of its equity securities;
•
make any material acquisitions, dispositions or divestitures; or
•
enter into a sale, merger, consolidation or other change of control transaction.
Revolving Credit Facility
On December 13, 2013, the Company entered into a Third Amended and Restated Credit Agreement (the “Credit Agreement”) by and among the Company, Bank of Montreal, as Administrative Agent, the lenders party thereto and the agents party thereto. The Credit Agreement amended and restated that certain Second Amended and Restated Credit Agreement, dated as of April 13, 2011, by and among such parties, as amended (the "Prior Credit Agreement"). The terms of the Credit Agreement are substantially similar to the Prior Credit Agreement.
The Credit Agreement provides for an asset-based, senior secured revolving credit facility maturing April 13, 2016 (the "Revolving Facility"). As of December 31, 2013 the borrowing base under the Revolving Facility was $242.5 million. The Revolving Facility is governed by a semi-annual borrowing base redetermination derived from the Company's proved crude oil and natural gas reserves, and based on such redeterminations, the borrowing base may be decreased or increased up to a maximum commitment level of $750 million. The borrowing base is subject to such periodic redeterminations commencing May 1, 2014.
The terms of the Credit Agreement provide that the Revolving Facility may be used for loans, and subject to a $10.0 million sublimit,
letters of credit. The Credit Agreement provides for a commitment fee of 0.5% of the unused portion of the borrowing base and commitments under the Revolving Facility.
Borrowings under the Revolving Facility will, at the Company’s election, bear interest at either (i) an alternate base rate (“ ABR ”)
equal to the highest of (A) the Prime Rate (as defined in the Credit Agreement) in effect on such day, (B) the Federal Funds Effective Rate (as defined in the Credit Agreement) in effect on such day, plus 0.5% per annum, and (C) the LIBO Rate (as defined in the Credit Agreement) for a one month interest period on such day, plus 1.00% or (ii) the Adjusted LIBO Rate (as defined in the Credit Agreement) for one, two, three, six or twelve months (as the Company may elect), plus, in each of the cases described in clauses (i) and (ii), an applicable margin ranging from 1.5% to 2.25% for ABR loans and from 2.5% to 3.25% for Adjusted LIBO Rate loans. Overdue amounts shall bear interest at a rate equal to 2.00% per annum plus the rate applicable to ABR loans.
The Credit Agreement contains negative covenants that, among other things, restrict the ability of the Company and its restricted
subsidiaries to, with certain exceptions, (i) incur indebtedness, (ii) grant liens, (iii) make certain payments, (iv) change the nature of its business, (v) dispose of all or substantially all of its assets or enter into mergers, consolidations or similar transactions, (vi) make investments, loans or advances, (vii) pay dividends, unless certain conditions are met, and with respect to the payment of dividends on preferred stock, subject to (A) no Event of Default (as defined in the Credit Agreement) existing, (B) after giving effect to any such preferred stock dividend payment, the Company maintaining availability under the borrowing base in an amount greater than the greater of (x) 2.50% percent of the borrowing base then in effect or (y) $5,000,000 and (C) a “basket” of $45,000,000 per year, and (viii) enter into transactions with affiliates.
In addition, the Credit Agreement requires the Company and its restricted subsidiaries to satisfy certain financial covenants, including maintaining:
(i) a ratio of consolidated current assets to consolidated current liabilities of not less than 1.0 to 1.0 as of the last day of any fiscal quarter;
(ii) a ratio of EBITDAX (as defined in the Credit Agreement) for the trailing four fiscal quarter period then ended to Interest Expense (as defined in the Credit Agreement) for such period of not less than (A) 2.00 to 1.00 for the fiscal quarter ending December 31, 2013, (B) 2.25 to 1.00 for the fiscal quarter ending March 31, 2014 and (C) 2.50 to 1.00 for the fiscal quarter ending June 30, 2014 and for each fiscal quarter ending thereafter; provided that solely for calculating such ratio for the fiscal quarter ending December 31, 2013, EBITDAX and interest expense for that fiscal quarter shall be calculated on an actual basis without giving effect to any pro forma adjustments;
(iii) beginning with the fiscal quarter ending June 30, 2014, a ratio of total debt to EBITDAX for the trailing four fiscal quarter period then ended of not more than (A) 4.50 to 1.0 for the fiscal quarters ending June 30, 2014 and September 30, 2014 and (B) 4.25 to 1.0 for the fiscal quarter ending December 31, 2014 and for each fiscal quarter ending thereafter; and
(iv) as of the last day of any fiscal quarter period ending through March 31, 2014, a ratio of total debt (less the outstanding principal amount of the Company’s 9.750% Senior Notes due 2020) to EBITDAX for the trailing four fiscal quarter period then ended of not more than 2.00 to 1.00.
At December 31, 2013, the Company was in compliance with all of its covenants, as amended or waived, contained in the Revolving Facility.
The obligations of the Company under the Credit Agreement may be accelerated upon the occurrence of an Event of Default. Events of Default include customary events for a financing agreement of this type, including, without limitation, payment defaults, defaults in the performance of affirmative or negative covenants, the inaccuracy of representations and warranties, bankruptcy or related defaults, defaults relating to judgments and the occurrence of a Change of Control (as defined in the Credit Agreement), subject, in certain circumstances, to certain cure periods.
Subject to certain permitted liens, the Revolving Facility is secured by the grant of a first priority lien on all or substantially all of the assets of the Company and its restricted subsidiaries, including, without limitation, a lien on no less than 80% of the value of the proved oil and gas properties of the Company and its restricted subsidiaries. In connection with the Credit Agreement, the Company and its restricted subsidiaries also entered into customary ancillary agreements and arrangements, which among other things, provide that the Revolving Facility is unconditionally guaranteed by such restricted subsidiaries.
Interest Expense
The following table sets forth interest expense for the years ended December 31, 2013 and 2012:
The Company capitalizes interest on expenditures for significant construction projects that last more than six months while activities are in progress to bring the assets to their intended use. Interest of $2.6 million and $4.4 million was capitalized on our Eureka Hunter Gas Gathering System during the years ended 2013 and 2012, respectively. The Company did not capitalize any interest in 2011.
NOTE 9 - SHARE-BASED COMPENSATION
Employees, directors and other persons who contribute to the success of Magnum Hunter are eligible for grants of common stock, common stock options, and stock appreciation rights under the Company's amended and restated Stock Incentive Plan. At December 31, 2013, 27,500,000 shares of the Company's common stock are authorized to be issued under the plan, and 5,360,176 shares have been issued as of December 31, 2013.
The Company recognized share-based compensation expense of $13.6 million, $15.7 million, and $25.1 million for the years ended December 31, 2013, 2012, and 2011 respectively.
A summary of stock option and stock appreciation rights activity for the years ended December 31, 2013, 2012, and 2011 is presented below:
A summary of the Company’s non-vested options and stock appreciation rights as of December 31, 2013, 2012, and 2011 is presented below:
Total unrecognized compensation cost related to the non-vested options was $14.1 million, $12.6 million, and $9.2 million as of December 31, 2013, 2012, and 2011, respectively. The cost at December 31, 2013 is expected to be recognized over a weighted-average period of 1.77 years. At December 31, 2013, the aggregate intrinsic value for the outstanding options was $29.7 million; and the weighted average remaining contract life was 5.88 years.
The assumptions used in the fair value method calculations for the years ended December 31, 2013, 2012, and 2011 are disclosed in the following table:
During 2013, the Company granted 182,994 fully vested shares of common stock to the Company’s board members as payment of board and committee meeting fees and chairperson retainers.
A summary of the Company’s non-vested common shares granted under the Stock Incentive Plan as of December 31, 2013, 2012, and 2011 is presented below:
Total unrecognized compensation cost related to the above non-vested shares amounted to $0.2 million, $0.4 million, and $0.8 million as of December 31, 2013, 2012, and 2011, respectively. The unrecognized compensation cost at December 31, 2013 is expected to be recognized over a weighted-average period of 2.9 years.
NOTE 10 - SHAREHOLDERS' EQUITY
Common Stock
During the years ended December 31, 2013, 2012, and 2011, the Company issued :
•
182,994, 84,052, and 121,143 shares, respectively, of the Company’s common stock in connection with share-based compensation which had fully vested to certain senior management and officers of the Company.
•
1,466,025, 1,438,275, and 6,293,107 shares, respectively, of the Company’s common stock upon the exercise of warrants and options for total proceeds of approximately $5.4 million, $2.3 million, and $7.6 million, respectively.
During the year ended December 31, 2011, the Company issued 1,713,598 shares of common stock in open market transactions at an average price of $8.27 per share pursuant to an “At the Market” sales agreement (ATM) the Company had with its sales agent for total proceeds of approximately $13.9 million. Sales of shares of the Company's common stock by its sales agent have been made in privately negotiated transactions or in any method permitted by law deemed to be an “At The Market” offering as defined in Rule 415 promulgated under the Securities Act of 1933, as amended, at negotiated prices, at prices prevailing at the time of sale or at prices related to such prevailing market prices, including sales made directly on an exchange or sales made through a market maker other than on an exchange. The Company's sales agent has made all sales using commercially reasonable efforts consistent with its normal sales and trading practices on mutually agreed upon terms between the Company and its sales agent.
On January 14, 2011, the Company issued 946,314 shares of common stock valued at approximately $7.5 million based on a closing stock price of $7.97 as consideration in the second closing of the PostRock assets acquisition.
On April 13, 2011, the Company issued 6,635,478 shares of common stock valued at approximately $53.0 million based on a closing stock price of $7.99 as consideration in the closing of the acquisition of NGAS. In connection with the NGAS acquisition, the Company issued 350,626 shares of common stock valued at approximately $2.8 million to NGAS employees as change in control payments.
On May 3, 2011, the Company issued 38,131,846 shares of common stock valued at approximately $282.2 million based on a closing stock price of $7.40 as consideration in the closing of the acquisition of NuLoch.
On March 30, 2012, the Company issued 296,859 restricted shares of the Company’s common stock valued at approximately $1.9 million based on a price of $6.41 per share as partial consideration for the acquisition of the assets of Eagle Operating.
On May 16, 2012, the Company issued 35,000,000 shares of the Company’s common stock in an underwritten public offering at a price of $4.50 per share for total proceeds of $157.5 million. The net proceeds of the offering, after deducting underwriting discounts and commissions and offering expenses, were approximately $148.2 million.
During the years ended December 31, 2013, 2012, and 2011 the Company issued 505,835, 3,188,036, and 582,127 shares of the Company’s common stock, respectively, upon exchange of exchangeable shares issued by MHR Exchangeco Corporation in connection with the Company’s acquisition of NuLoch Resources, Inc. in May 2011.
On August 13, 2013 and August 20, 2012, the Company issued an aggregate of 221,170 and 199,055 shares, respectively, of the Company’s common stock as "safe harbor" and discretionary matching contributions to the Magnum Hunter Resources Corporation 401(k) Employee Stock Ownership Plan (the "KSOP" or the "Plan"). The Plan was established effective October 1, 2010 as a defined contribution plan. At the discretion of the Board of Directors, the Company may elect to contribute discretionary contributions to the Plan either as profit sharing contributions or as employee stock ownership plan contributions. It is the intent of the Company to review and make discretionary contributions to the Plan in the future, however, the Company has no further obligation to make future contributions to the Plan as of December 31, 2013, except for statutorily required "safe harbor" matching contributions.
Unearned Common Stock in Magnum Hunter Resources Corporation 401(k) Employee Stock Ownership Plan
On August 13, 2012, the Company rescinded the loan of 153,300 Magnum Hunter common shares to the Company's KSOP and the common shares were returned to the Company and held in treasury at cost of $3.94 per share. The loan was rescinded to correct a mutual mistake by the parties in connection with the Company’s original acquisition of the shares through open market purchases. The Company has agreed that 153,300 shares of the Company’s common stock will either be (i) offered for sale to the participants in the Plan at a price not to exceed the lesser of $3.94 per share (the basis of these treasury shares) or the fair market value of the shares on the date of the sale, or (ii) contributed to the Plan as one or more discretionary matching contributions. Such sale or contribution shall be made at such time or times as determined by the trustee of the Plan, except to the extent that the Company elects prior to that time to contribute all or a part of such shares as a discretionary matching contribution.
Exchangeable Common Stock
On May 3, 2011, in connection with the acquisition of NuLoch, the Company issued 4,275,998 exchangeable shares of MHR Exchangeco Corporation, which are exchangeable for shares of the Company at a one for one ratio. The shares of MHR Exchangeco Corporation were valued at approximately $31.6 million. Each exchangeable share was exchangeable for one share of the Company's common stock at any time after issuance at the option of the holder and was redeemable at the option of the Company, through Exchangeco, after one year or upon the earlier of certain specified events. During the year ended December 31, 2013, 2012, and 2011, 505,835, 3,188,036, and 582,127, respectively, of the exchangeable shares were exchanged for common shares of the Company. As of December 31, 2013, there were no exchangeable shares outstanding.
Common Stock Warrants
During 2006, the Company issued 871,500 warrants to purchase an equal number of shares of the Company’s common stock at an exercise price of $3.00 per share in conjunction with private placement sales of common stock. The warrants had a term of five years from the date of issuance. The Company also issued 326,812 warrants to purchase an equal number of shares of the Company’s common stock at an exercise price of $3.00 per share along with a cash payment for commission fees.
In association with common stock sales on November 5, 2009, the Company issued 457,982 common stock warrants. Each warrant issued to a purchaser had a term of 3 years and (i) was exercisable for one share of the Company's common stock at any time after the shares of common stock underlying the warrant are registered with the SEC for resale pursuant to an effective registration statement, which was June 12, 2010, (ii) had a cash exercise price of $2.50 per share of the Company's common stock, and (iii) upon notice to the holder of the warrant, was redeemable by the Company for $0.01 per share of the Company's common stock underlying the warrant if (a) the registration statement as filed with the SEC is effective and (b) the average trading price of the Company's common stock as traded and quoted on the NYSE Amex equals or exceeds $3.75 per share for at least 20 days in any period of 30 consecutive days.
On November 16, 2009, the Company issued 1,280,744 common stock warrants. The warrants, which represent the right to acquire an aggregate of up to 1,280,744 common shares, were exercisable at any time on or after May 17, 2010 and had a term of 3 years, at an exercise price of $2.50 per share, which was 145% of the closing price of the Company's common shares on the NYSE Amex on November 11, 2009. These warrants were exercised during the years 2010, 2011, 2012.
On April 13, 2011, at the time of the NGAS acquisition, NGAS had 4,609,038 warrants outstanding which were converted, based on the exchange ratio of 0.0846, to 389,924 warrants exercisable for Magnum Hunter common stock. The warrants had a cash-out option, which remained available to the holder for 30 days from the date of the acquisition, based on fair market value of the warrants at April 13, 2011. The Company paid cash of $1.0 million upon exercise of the cash-out option on the warrants exercisable for 251,536 shares of the Company’s common stock. At December 31, 2013, common stock warrants exercisable for 138,388 shares of the Company’s common stock were outstanding. The warrants consist of 97,780 warrants with an exercise price of $15.13 which expire February 13, 2014 and 40,608 warrants with an exercise price of $19.04 which expire November 17, 2014.
On August 13, 2011, the Company declared a dividend to be paid in the form of one common stock warrant for every ten shares held by holders of record of the Company's common stock and exchangeable shares of MHR Exchangeco Corporation on August 31, 2011. The Company issued 12,875,093 common stock warrants to common stock holders and 378,174 warrants to holders of MHR Exchangeco Corporation exchangeable shares. Each warrant entitled the holder to purchase one share of the Company’s common stock for an initial exercise price of $10.50 and expired on October 14, 2013. The fair market value of the warrants was $6.9 million. The warrants were accounted for in additional paid-in capital rather than as a reduction of retained earnings because the Company has an accumulated deficit position.
On August 26, 2013, the Company declared a dividend on its outstanding shares of common stock in the form of 17,030,622 warrants to purchase shares of the Company's common stock at $8.50 per share with such warrants having a fair value of $21.6 million as of the declaration date of August 26, 2013. The warrants were issued on October 15, 2013 to shareholders of record on September 16, 2013. Each shareholder of record received one warrant for every ten shares owned as of the record date (with the number of warrants rounded down to the nearest whole number). Each warrant entitles the holder to purchase one share of the Company's common stock at an exercise price of $8.50 per share, subject to certain anti-dilution adjustments, and will expire on April 15, 2016. The warrants will become exercisable on the later of September 1, 2014 or the date that a registration statement has been filed with and declared effective by the SEC with respect to the issuance of the common stock underlying the warrants. The warrants will be subject to redemption at the option of the Company at $0.001 per warrant upon not less than thirty days’ notice to the holders.
During the year ended December 31, 2011, 771,812 of the Company's $3.00 common stock warrants and 42,045 of the Company's $2.50 common stock warrants were exercised for total combined proceeds of approximately $2.4 million, and 15,000 of the Company's $3.00 common stock warrants expired.
During the year ended December 31, 2012, 48 of the Company's $10.50 common stock warrants and 134,177 of the Company's $2.50 common stock warrants were exercised for total combined proceeds of approximately $328,000, and 15,330 of the Company's $10.50 common stock warrants were canceled upon the rescission of the 153,300 Magnum Hunter common shares loaned to the Company's KSOP.
During the year ended December 31, 2013, 13,237,889 of the Company's $10.50 common stock warrants expired.
A summary of warrant activity for the years ended December 31, 2013, 2012, and 2011 is presented below:
At December 31, 2013, the warrants had no aggregate fair value; and the weighted average remaining contract life was 0.8 years.
Series D Preferred Stock
During the year ended December 31, 2011, the Company sold 1,437,558 shares of our 8.0% Series D Cumulative Preferred Stock, par value $0.01 per share and liquidation preference of $50.00 per share, of which 400,000 were sold in an underwritten offering and 1,037,558 were sold under the ATM sales agreement, for net proceeds of $65.0 million. The Series D Preferred Stock cannot be converted into common stock of the Company but may be redeemed by the Company, at the Company’s option, on or after March 14, 2014 for par value or $50.00 per share or in certain circumstances prior to such date as a result of a change in control of the Company. Dividends accrue and are payable monthly on the Series D Preferred Stock at a fixed rate of 8.0% per annum of the $50.00 per share liquidation preference.
During the year ended December 31, 2012, the Company issued an aggregate of 2,771,263 shares of our 8.0% Series D Cumulative Preferred Stock for cumulative net proceeds of approximately $122.5 million, which included various offering expenses of approximately $3.1 million. The 2,771,263 shares of our 8.0% Series D Cumulative Preferred Stock issued during the year ended December 31, 2012 included (i) 1,721,263 shares issued under an ATM sales agreement for net proceeds of approximately $77.9 million, which included approximately $1.5 million of offering and underwriting fees and (ii) 1,050,000 shares issued pursuant to an underwritten public offering on September 7, 2012 at a price of $44.00 per share for net proceeds of approximately $44.6 million, which included approximately $1.6 million of underwriting discounts, commissions and offering expenses.
During the year ended December 31, 2013, the Company issued under an ATM sales agreement 216,068 shares of its Series D Preferred Stock for net proceeds of approximately $9.6 million, which included sales agent commissions and other issuance costs of approximately $1.2 million.
Series E Preferred Stock
Each share of Series E Preferred Stock, par value $0.01 per share, has a stated liquidation preference of $25,000 and a dividend rate of 8.0% per annum (based on stated liquidation preference), is convertible at the option of the holder into a number of shares of the Company’s common stock equal to the stated liquidation preference (plus accrued and unpaid dividends) divided by a conversion price of $8.50 per share (subject to anti-dilution adjustments in the case of stock dividends, stock splits and combinations of shares), and is redeemable by the Company under certain circumstances. The Series E Preferred Stock is junior to the Company’s 10.25% Series C Cumulative Perpetual Preferred Stock and 8.0% Series D Cumulative Preferred Stock in respect of dividends and distributions upon liquidation. Each Depositary Share is a 1/1000th interest in a share of Series E Preferred Stock. Accordingly, the Depositary Shares have a stated liquidation preference of $25.00 per share and a dividend rate of 8.0% per annum (based on stated liquidation preference), are similarly convertible at the option of the holder into a number of shares of the Company’s common stock equal to the stated liquidation preference (plus accrued and unpaid dividends) divided by a conversion price of $8.50 per share (subject to corresponding anti-dilution adjustments), and are redeemable by the Company under certain circumstances.
In November 2012, the Company issued 2,774,850 Depositary Shares, each representing a 1/1,000th interest in a share of the Company’s 8% Series E Cumulative Convertible Preferred Stock, liquidation preference $25,000 per share, to the shareholders of Virco as partial consideration for the Company’s purchase of 100% of the outstanding stock of Virco. The Company also issued 70,000 Depositary Shares into an escrow account which were returned and held in treasury at cost of $1.8 million upon an indemnification settlement in favor of the Company.
In December 2012, the Company sold in a public offering an aggregate of 1,000,000 Depositary Shares, each representing a 1/1,000th interest in a share of the Company’s 8% Series E Cumulative Convertible Preferred Stock, liquidation preference $25,000 per share. The Depositary Shares were sold to the public at a price of $23.50 per Depositary Share, and the net proceeds to the Company were $22.44 per Depositary Share after deducting underwriting commissions, but before deducting expenses related to the offering.
During the year ended December 31, 2013, the Company issued under an ATM sales agreement an aggregate of 27,906 Depositary Shares, each representing a 1/1,000th interest in a share of the Company’s Series E Preferred Stock. The Depositary Shares were sold to the public at an average price of $24.24 per Depositary Share, and net proceeds to the Company were $590,000 after deducting sales agent commissions and other issuance costs.
Non-controlling Interests
During the year ended December 31, 2012, the Company purchased outstanding non-controlling interest in a subsidiary which the Company did not previously own. The Company acquired the non-controlling interest valued at $497,000 based on fair value at the date of acquisition.
In connection with a Williston Basin acquisition in 2008, the Company entered into equity participation agreements with certain of its lenders pursuant to which the Company agreed to pay to the lenders an aggregate of 12.5% of all distributions paid to the owners of PRC Williston, which equity participation agreements, for accounting purposes, are treated as non-controlling interests in PRC Williston, and consequently, PRC Williston is treated as a majority owned subsidiary of the Company and is consolidated by the Company. The equity participation agreements had a fair value of $3.4 million upon issuance and were accounted for as a non-controlling interest in PRC Williston.
On April 2, 2012, Eureka Hunter Holdings, a majority owned subsidiary, issued 622,641 Class A Common Units representing membership interests in Eureka Hunter Holdings, with a value of $12.5 million, as partial consideration for the assets acquired from TransTex. The value of the units transferred as partial consideration for the acquisition was determined utilizing a discounted future cash flow analysis. The carrying value of the Eureka Hunter Holdings Class A Common Units held by third parties is classified as non-controlling interest.
A summary of non-controlling interests in the Company for the years ended December 31, 2013, 2012, and 2011 is presented below:
Preferred Dividends Paid
A summary of dividends paid by the Company for the years ended December 31, 2013, 2012, and 2011 is presented below:
Accretion of the difference between the carrying value and the redemption value of the Eureka Hunter Holdings, Series A Preferred Units of $6.9 million for the year ended December 31, 2013, $3.8 million for the year ended December 31, 2012, and none for the year ended December 31, 2011, was included in dividends on preferred stock.
NOTE 11 - REDEEMABLE PREFERRED STOCK
Series C Preferred Stock
On December 13, 2009, the Company sold 214,950 shares of its 10.25% Series C Cumulative Perpetual Preferred Stock, par value $0.01 per share and liquidation preference $25.00 per share (the “Series C Preferred Stock”), for net proceeds of $5.1 million. The Series C Preferred Stock cannot be converted into common stock of the Company, but may be redeemed by the Company, at the Company’s option, on or after December 14, 2011 for par value or $25.00 per share. In the event of a change of control of the Company, the Series C Preferred Stock will be redeemable by the holders at $25.00 per share, except in certain circumstances when the acquirer is considered a qualifying public company. The Series C Preferred Stock is recorded as temporary equity because a forced redemption, upon certain circumstances as a result of a change in control of the Company, is outside the Company’s control. Dividends accrue and are payable monthly on the Series C Preferred Stock at a fixed rate of 10.25% per annum of the $25.00 per share liquidation preference.
During the year ended December 31, 2010, the Company sold 2,594,506 shares of the Series C Preferred Stock under its ATM sales agreement for net proceeds of $63.4 million.
During the year ended December 31, 2011, the Company sold 1,190,544 shares of its 10.25% Series C Cumulative Perpetual Preferred Stock under its ATM sales agreement for net proceeds of $29.1 million. The sales during the year ended December 31, 2011 have fully subscribed the authorized 4,000,000 shares of Series C Preferred Stock.
Eureka Hunter Holdings, LLC Series A Preferred Units
On March 21, 2012, Eureka Hunter Holdings entered into a Series A Convertible Preferred Unit Purchase Agreement (the “Unit Purchase Agreement”) with Magnum Hunter and Ridgeline Midstream Holdings, LLC (“Ridgeline”), an affiliate of ArcLight Capital Partners, LLC. Pursuant to this Unit Purchase Agreement, Ridgeline committed, subject to certain conditions, to purchase up to $200 million of Series A Convertible Preferred Units representing membership interests of Eureka Hunter Holdings (the “Series A Preferred Units”).
During the years ended December 31, 2013 and December 31, 2012, Eureka Hunter Holdings issued 1,800,000 and 7,590,000, Series A Preferred Units, respectively, to Ridgeline for net proceeds of $35.3 million and $148.6 million, respectively, net of transaction costs. The Series A Preferred Units outstanding at December 31, 2013 represented 41.7% of the ownership of Eureka Hunter Holdings on a basis as converted to Class A Common Units of Eureka Hunter Holdings and represent non-controlling interests in the form of redeemable preferred stock of a subsidiary in consolidation of the Company. Eureka Hunter Holdings pays cumulative distributions quarterly on the Series A Preferred Units at a fixed rate of 8% per annum of the initial liquidation preference. The distribution rate is increased to 10% if any distribution is not paid when due. The board of directors of Eureka Hunter Holdings may elect to pay up to 75% of the distributions owed for the period from March 21, 2012 through March 31, 2013 in the form of “paid-in-kind” units and may elect to pay up to 50% of the distributions owed for the period from April 1, 2013 through March 31, 2014 in such units. The Series A Preferred Units can be converted into Class A Common Units of Eureka Hunter Holdings upon demand by Ridgeline at any time or by Eureka Hunter Holdings upon the consummation of a qualified initial public offering, provided that Eureka Hunter Holdings converts no less than 50% of the Series A Preferred Units into Class A Common Units at that time. The conversion rate is 1:1, which may be adjusted from time to time based upon certain anti-dilution and other provisions. Eureka Hunter Holdings can redeem all outstanding Series A Preferred Units at their liquidation preference, which involves a specified IRR hurdle, any time after March 21, 2017. Holders of the Series A Preferred Units can force redemption of all outstanding Series A Preferred Units any time after March 21, 2020, at a redemption rate equal to the higher of the as-converted value and a specified internal investment rate of return calculation. The Series A Preferred Units are recorded as temporary equity because a forced redemption by the holders of the preferred units is outside the control of Eureka Hunter Holdings.
The Company has evaluated the Series A Preferred Units and determined that they should be considered a “debt host” and not an “equity host”. This evaluation is necessary to determine if any embedded features require bifurcation and, therefore, would be required to be accounted for separately as a derivative liability. The Company's analysis followed the “whole instrument approach,” which compares an individual feature against the entire preferred instrument that includes that feature. The Company's analysis was based on a consideration of the economic characteristics and risks of the preferred unit and, more specifically, evaluated all of the stated and implied substantive terms and features of such unit, including (1) whether the preferred unit included redemption features; (2) how and when any redemption features could be exercised; (3) whether the holders of preferred units were entitled to dividends; (4) the voting rights of the preferred unit; and (5) the existence and nature of any conversion rights. As a result of the Company's determination that the preferred unit is a “debt host,” the Company determined that the embedded conversion option, redemption options and other features of the preferred units do require bifurcation and separate accounting as embedded derivatives. The fair value of the embedded features were determined at the issuance dates which were bifurcated from the issuance values of the Series A Preferred Units and presented in long term liabilities. The fair value of this embedded feature was determined to be $75.9 million and $43.5 million in the aggregate at December 31, 2013 and 2012, respectively. See "Note 3 - Fair Value of Financial Instruments".
During the year ended December 31, 2013, the Company paid cash distributions of $5.2 million and accrued distributions of $3.9 million not yet paid, to the holder of the Company's Series A Preferred Units. During such year, distributions in the amount of $8.2 million were paid-in-kind to the holder of the Series A Preferred Units and the Company issued 412,157 Series A Preferred Units as payment. At December 31, 2013, 9,885,048 shares of Series A Preferred Units were outstanding.
NOTE 12 - INCOME TAXES
The total provision for income taxes applicable to continuing operations consists of the following:
At December 31, 2013, the Company has net operating loss carryforwards ("NOL's") available for U.S. federal income tax purposes of approximately $400 million, which expire in varying amounts during the tax years 2018 through 2033. In addition, the Company has NOL carryforwards related to its Canadian operations of approximately $66.4 million , which expire in varying amounts between years 2015 through 2033. The deferred tax asset recorded for the U.S. NOL does not include $22.4 million of deductions for excess stock-based compensation (tax effected $8.3 million). The Company will recognize the NOL tax assets associated with excess stock-based compensation tax deductions only when all other components of the NOL tax assets have been fully utilized and a cash tax benefit is realized. Upon realization, the excess stock-based compensation deduction will reduce taxes payable and will be credited directly to equity.
At December 31, 2013, the Company was not under examination by any federal or state taxing jurisdiction, nor had the Company been contacted by any examining agency.
The Company has approximately $2.8 million (tax effected $1.1 million) of depletion carryover which has no expiration.
The Company has no unremitted earnings in Canada.
The Company has recorded a valuation allowance of $150.5 million against the net deferred tax assets of the Company at December 31, 2013. The Company is uncertain on a more likely than not basis that the NOL and other deferred tax assets will be utilized in the future. Management evaluated all available positive and negative evidence in making this assessment. The assessment included objectively verifiable information such as historical operating results, future projections of operating results, future reversals of existing taxable temporary differences and anticipated capital expenditures. Management placed a significant amount of weight on the historical results.
The following is a reconciliation of the reported amount of income tax expense (benefit) attributable to continuing operations for the years ended December 31, 2013, 2012, and 2011 to the amount of income tax expense that would result from applying domestic federal statutory tax rates to pretax income:
Income (loss) before income taxes was as follows:
Deferred Tax Assets and Liabilities
The tax effects of temporary differences that gave rise to the Company's deferred tax assets and liabilities are presented below:
As of December 31, 2013 the Company provided for a liability of $3.9 million for unrecognized tax benefits related to various federal tax matters, which were netted against the Company's net operating loss. Settlement of the uncertain tax position is expected to occur in the next 12 months and will have no effect on income tax expense (benefit). The Company has elected to classify interest and penalties related to uncertain income tax positions in income tax expense. Due to available NOLs, as of December 31, 2013, the Company has accrued no amounts for potential payment of interest and penalties.
Following is a reconciliation of the total amounts of unrecognized tax benefits during the years ended December 31, 2013, 2012 and 2011:
NOTE 13 - MAJOR CUSTOMERS
The Company's share of oil and gas production is sold to various purchasers who must be prequalified under the Company's credit risk policies and procedures. After giving effect to the Eagle Ford Hunter sale, the following purchasers individually accounted for ten percent or more of the Company's consolidated continuing oil and gas revenues in at least one of the three years ended December 31, 2013. The loss of any one significant purchaser could have a material, adverse effect on the ability of the Company to sell its oil and gas production. Although the Company is exposed to a concentration of credit risk, the Company believes that all of its purchasers are credit worthy.
The table below provides the percentages of the Company's consolidated oil, NGL and gas revenues from continuing operations represented by its major purchasers during the periods presented:
NOTE 14 - SUPPLEMENTAL CASH FLOW INFORMATION
The following summarizes cash paid (received) for interest and income taxes, as well as non-cash investing transactions:
The Company issued dividends on common stock in the form of 17,030,622 warrants and 12,875,093 warrants with fair value of $21.6 million and $6.7 during the years ended December 31, 2013 and 2012, respectively.
NOTE 15 - OTHER INFORMATION
Quarterly Data (Unaudited)
The following tables set forth unaudited summary financial results on a quarterly basis for the most recent two years.
______________
(1)
The quarter-ended September 30, 2013, loss from operations was primarily driven by the loss on the sale of certain properties in Burke County, North Dakota of $38.1 million, and exploration expense. Management reviews leasehold acreage on a quarterly basis. During the quarter-ended September 30, 2013, management determined a significant portion of the non-core Williston Basin acreage would not be utilized as the Company planned to focus on assets that will provide a higher rate of return.
(2)
The quarter-ended September 30, 2013, loss from discontinued operations was primarily driven by impairment expense of $72.5 million, as management determined a significant portion of the non-core acreage would not be utilized.
(3)
The quarter-ended June 30, 2013 gain on disposal of discontinued operations was primarily due to the gain on sale of the Company's Eagle Ford Shale assets. The quarter-ended September 30, 2013 loss on disposal of discontinued operations was primarily due to an expense of $64.8 million, net of tax to reflect the net assets of Magnum Hunter Production and Williston Hunter Canada to their fair values as a result of the Company's decision to sell these assets. The quarter-ended December 31, 2013 loss on disposal of discontinued operations was primarily due to an expense of $27.6 million, net of tax, to reflect changes in the estimated fair values of the net assets of Magnum Hunter Production and Williston Hunter Canada which the Company had decided to sell during the quarter ended September 30, 2013. See "Note 2 - Divestitures and Discontinued Operations".
(4)
The quarter-ended December 31, 2012, loss from operations was primarily driven by exploration expense. During the quarter-ended December 31, 2012 management determined that a significant portion of the non-core Williston Basin acreage would not be utilized as the Company planned to focus on assets that will provide a higher rate of return in 2013.
Segment Reporting
U.S. Upstream, Midstream and Oilfield Services represent the operating segments of the Company. As of December 31, 2013 the Canadian Upstream segment, comprised of the WHI Canada operations, was classified as assets held for sale and discontinued operations. The factors used to identify these reportable segments are based on the nature of the operations, nationality, operating strategies and management expertise involved in each. The Upstream segments are organized and operate to explore for and produce crude oil and natural gas within the geographic boundaries of the U.S. and Canada. The Midstream segment markets natural gas and operates a network of pipelines and compression stations that gather natural gas and NGL for transportation to market. The Oilfield Services segment provides drilling services to oil and natural gas exploration and production companies. Midstream and Oilfield Services customers are the Company's subsidiaries and other third-party oil and natural gas companies.
The following tables set forth operating activities and capital expenditures by segment for the years ended, and segment assets as of December 31, 2013, 2012, and 2011.
Supplemental Oil and Gas Disclosures (Unaudited)
The following table sets forth the costs incurred in oil and gas property acquisition, exploration, and development activities (in thousands):
Oil and Gas Reserve Information
Proved oil and gas reserve quantities are based on estimates prepared by Magnum Hunter’s third party reservoir engineering firms Cawley, Gillespie, & Associates, Inc. in 2013, and Cawley, Gillespie, & Associates, Inc. and AJM Deloitte in 2012 and 2011. There are numerous uncertainties inherent in estimating quantities of proved reserves and projecting future rates of production and timing of development expenditures. The following reserve data only represent estimates and should not be construed as being exact.
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Reserves
The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves and the changes in standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves were prepared in accordance with provisions of ASC 932, Extractive Activities - Oil and Gas. Future cash inflows at December 31, 2013, 2012, and 2011 were computed by applying the unweighted, arithmetic average of the closing price on the first day of each month for the 12-month period prior to December 31, 2013, 2012, and 2011 to estimated future production. Future production and development costs are computed by estimating the expenditures to be incurred in developing and producing the proved oil and natural gas reserves at year-end, based on year-end costs and assuming continuation of existing economic conditions.
Future income tax expenses are calculated by applying appropriate year-end tax rates to future pretax net cash flows relating to proved oil and natural gas reserves, less the tax basis of properties involved. Future income tax expenses give effect to permanent differences, tax credits and loss carry forwards relating to the proved oil and natural gas reserves. Future net cash flows are discounted
at a rate of 10% annually to derive the standardized measure of discounted future net cash flows. This calculation procedure does not necessarily result in an estimate of the fair market value of the Company's oil and natural gas properties.
The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves are as follows:
Future cash flows as shown above were reported without consideration for the effects of commodity derivative transactions outstanding at each period end.
Changes in Standardized Measure of Discounted Future Net Cash Flows
The changes in the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves are as follows:
______________
(1)
The Company's net changes due to revisions of previous quantity estimates primarily reflect upward revisions to recoverable quantities of oil and gas minerals assuming existing prices and technology. For the year ended December 31, 2013, the Company made upward revisions of 6,148 MBbl of oil and natural gas liquids and 100,456 MMcf of natural gas due to additional information gathered from continued production from the shale areas and increases in estimated ultimate recoveries (EURs). For the year ended December 31, 2012, the Company made upward revisions of 12,568 MBbls of oil and natural gas liquids and 25,644 MMcf of natural gas.
(2)
The Company's changes in timing and other primarily represent changes in the Company's estimates of when proved reserve quantities will be realized. The reserves as of December 31, 2012, reflect accelerated recovery of minerals due to purchases of minerals in place and capital expenditures incurred to develop properties.
The commodity prices inclusive of adjustments for quality and location used in determining future net revenues related to the standardized measure calculation are as follows:
NOTE 16 - RELATED PARTY TRANSACTIONS
The following table sets forth the related party balances as of December 31, 2013 and 2012:
The following table sets forth the related party transaction activities for the years ended December 31, 2013, 2012 and 2011:
_________________________________
(1)
GreenHunter is an entity of which Gary C. Evans, Magnum Hunter's Chairman and CEO, is the Chairman, a major shareholder and former interim CEO; of which David Krueger, the Company's former Chief Accounting Officer and Senior Vice President, is the former Chief Financial Officer; and of which Ronald D. Ormand, the Company’s former Chief Financial Officer and Executive Vice President, is a former director. Eagle Ford Hunter received, and Triad Hunter and Viking International Resources, Inc. ("Virco"), 100% owned subsidiaries of the Company, receive services related to salt water disposal and rental equipment from GreenHunter and its affiliated companies, White Top Oilfield Construction, LLC and Black Water Services, LLC. The Company believes that such services were and are provided at competitive market rates and were and are comparable to, or more attractive than, rates that could be obtained from unaffiliated third party suppliers of such services.
(2)
On February 17, 2012, the Company sold its 100% owned subsidiary, Hunter Disposal, to GreenHunter Water, LLC ("GreenHunter Water"), a 100% owned subsidiary of GreenHunter. The Company recognized an embedded derivative asset resulting from the conversion option under the convertible promissory note it received as partial consideration for the sale. The Company has recorded interest income at the rate of 10% on the note receivable
from GreenHunter. Also as a result of this transaction, the Company has an equity method investment in GreenHunter that is included in derivatives and other long term assets and an available for sale investment in GreenHunter included in investments.
(3)
The Company rented an airplane for business use for certain members of Company management at various times from Pilatus Hunter, LLC, an entity 100% owned by Mr. Evans. Airplane rental expenses are recorded in general and administrative expense.
(4)
During the years ended December 31, 2011 and 2012, the Company paid rent under a lease for a Houston, Texas corporate apartment from an executive of the Company, which apartment was used by other Company employees when in Houston for Company business. The lease terminated in May 2012.
In connection with the sale of Hunter Disposal, Triad Hunter entered into agreements with Hunter Disposal and GreenHunter Water for wastewater hauling and disposal capacity in Kentucky, Ohio, and West Virginia and a five-year tank rental agreement with GreenHunter Water. See "Note 2 - Divestitures and Discontinued Operations".
Mr. Evans, the Company's Chairman and Chief Executive Officer, was a 4.0% limited partner in TransTex Gas Services, LP ("TransTex Gas"). This limited partnership received total consideration of 622,641 Class A Common Units of Eureka Hunter Holdings and cash of $46.0 million upon the Company's acquisition of certain of its assets. This includes units issued in accordance with the agreement of Eureka Hunter Holdings and TransTex Gas to provide the limited partners of TransTex Gas the opportunity to purchase additional Class A Common Units of Eureka Hunter Holdings in lieu of a portion of the cash distribution they would otherwise receive. Certain limited partners purchased such units, including Mr. Evans, who purchased 27,641 Class A Common Units of Eureka Hunter Holdings for $553,000 which was the same purchase price equivalent offered to all TransTex investors.
On February 17, 2012, the Company sold its wholly-owned subsidiary, Hunter Disposal, LLC, to GreenHunter Water, LLC, a wholly-owned subsidiary of GreenHunter Resources, Inc. The terms and conditions of the equity purchase agreement between the parties were approved by an independent special committee of the Board of the Company. Total consideration for the sale was approximately $9.3 million comprised of $2.2 million in cash, 1,846,722 shares of GreenHunter Resources, Inc. restricted common stock valued at $2.6 million based on a closing price of $1.79 per share, discounted for restrictions, 88,000 shares of GreenHunter Resources, Inc. 10% Series C Cumulative Preferred Stock with a fair value of $1.9 million, and a $2.2 million convertible promissory note which is convertible at the option of the Company into 880,000 shares of GreenHunter Resources, Inc. common stock based on the conversion price of $2.50 per share. The Company recognized a gain of on the sale of $2.4 million, in gain on disposal of discontinued operations, net of tax. The Company has recognized an embedded derivative asset resulting from the conversion option on the convertible promissory note with fair market value of $79,000 at December 31, 2013 and $264,000 at December 31, 2012. See "Note 3 - Fair Value of Financial Instruments". The cash proceeds from the sale were adjusted downward to $783,000 for changes in working capital and certain fees to reflect the effective date of the sale of December 31, 2012. The Company has recorded interest income as a result of the note receivable from GreenHunter Resources, Inc., in the amount of $204,760 for the year ended December 31, 2013. As a result of this transaction, the Company has an investment in GreenHunter Resources, Inc. that is included in derivatives and other long term assets and recorded under the equity method. The loss related to this investment was $0.7 million for the year ended December 31, 2013. In connection with the sale, Triad Hunter entered into agreements with Hunter Disposal, LLC and GreenHunter Water, LLC for wastewater hauling and disposal capacity in Kentucky, Ohio, and West Virginia and a five-year tank rental agreement with GreenHunter Water, LLC.
NOTE 17 - COMMITMENTS AND CONTINGENCIES
Legal Proceedings
On April 23, 2013, Anthony Rosian, individually and on behalf of all other persons similarly situated, filed a class action complaint in the United States District Court, Southern District of New York, against the Company and certain of its officers, two of whom also serve as directors. On April 24, 2013, Horace Carvalho, individually and on behalf of all other persons similarly situated, filed a similar class action complaint in the United States District Court, Southern District of Texas, against the Company and certain of its officers, two of whom also serve as directors. Several substantially similar putative class actions have been filed in the Southern District of New York and in the Southern District of Texas. All such cases are collectively referred to as the Securities Cases. The cases filed in the Southern District of Texas have since been dismissed, but the cases in the Southern District of New York have been consolidated and remain ongoing. The plaintiffs in the Securities Cases have filed a consolidated amended complaint alleging that the Company made certain false or misleading statements in its filings with the SEC, including statements related to the Company's internal and financial controls, the calculation of non-cash share-based compensation expense, the late filing of the Company's 2012 Form 10-K, the dismissal of Magnum Hunter's previous independent registered accounting firm, the Company’s characterization of the auditors’ position with respect to the dismissal, and other matters identified in the Company's April 16, 2013 Form 8-K, as amended. The consolidated amended complaint asserts claims under Sections 10(b) and 20 of the Securities Exchange Act based on alleged false statements made regarding these issues throughout the alleged class period, as well as claims under Sections 11, 12, and 15 of the Securities Act based on alleged false statements and omissions regarding the Company’s internal controls made in
connection with the 35,000,000-share secondary offering that Magnum Hunter completed on May 14, 2012. The consolidated amended complaint demands that the defendants pay unspecified damages to the class action plaintiffs, including damages allegedly caused by the decline in the Company's stock price between February 22, 2013 and April 22, 2013. The Company and the individual defendants intend to vigorously defend the Securities Cases. It is possible that additional investor lawsuits could be filed over these events.
On May 10, 2013, Steven Handshu filed a shareholder derivative suit in the 151st Judicial District Court of Harris County, Texas on behalf of the Company against the Company's directors and senior officers (the “Handshu Action”). On June 6, 2013, Zachariah Hanft filed another shareholder derivative suit in the Southern District of New York on behalf of the Company against the Company's directors and senior officers (the “Hanft Action”). On June 18, 2013, Mark Respler filed another shareholder derivative suit in the District of Delaware on behalf of the Company against the Company's directors and senior officers (the “Respler Action”). On June 27, 2013, Timothy Bassett filed another shareholder derivative suit in the Southern District of Texas on behalf of the Company against the Company's directors and senior officers. On September 16, 2013, Joseph Vitellone was substituted as plaintiff in the action filed by Mr. Bassett (the “Vitellone Action”). These suits are collectively referred to as the Derivative Cases. The Derivative Cases assert that the individual defendants unjustly enriched themselves and breached their fiduciary duties to the Company by publishing allegedly false and misleading statements to the Company's investors regarding the Company's business and financial position and results, and allegedly failing to maintain adequate internal controls. The complaints demand that the defendants pay unspecified damages to the Company, including damages allegedly sustained by the Company as a result of the alleged breaches of fiduciary duties by the defendants, as well as disgorgement of profits and benefits obtained by the defendants, and reasonable attorneys', accountants' and experts' fees and costs to the plaintiff. On December 13, 2013, the Handshu Action was dismissed for want of prosecution. On December 20, 2013, the United States District Court for the Southern District of Texas granted the Company’s motion to dismiss the Vitellone Action and entered a final judgment dismissing the case in its entirety. The court held that the plaintiff failed to allege particularized facts that would excuse them from making pre-suit demand on the Company’s Board of Directors as required by Delaware law. On January 21, 2014, the Hanft Action was dismissed with prejudice after the plaintiff in that action filed a voluntary motion for dismissal. On February 18, 2014, the District of Delaware granted the Company’s motion to dismiss the Respler Action on collateral estoppel grounds and closed the case. Accordingly, no shareholder derivative cases are currently pending against the Company’s officers and directors. It is possible, however, that additional shareholder derivative suits could be filed over these events
In addition, the Company has received several demand letters from shareholders seeking books and records relating to the allegations in the Securities Cases and the Derivative Cases under Section 220 of the Delaware General Corporation Law. On September 17, 2013, Anthony Scavo, who is one of the shareholders that made a demand, filed a books and records action in the Delaware Court of Chancery pursuant to Section 220 of the Delaware General Corporation Law (the “Scavo Action”). The Scavo Action seeks various books and records relating to the claims in the Securities Cases and the Derivative Cases, as well as costs and attorneys’ fees. The Company has filed an answer in the Scavo Action. It is possible that additional similar actions may be filed and that similar shareholder demands could be made.
The Company also received an April 26, 2013 letter from the SEC stating that the SEC's Division of Enforcement was conducting an inquiry regarding the Company's internal controls, change in outside auditors and public statements to investors and asking the Company to preserve documents relating to these matters. The Company is complying with this request. On December 30, 2013, the Company received a document subpoena relating to the issues identified in the April 26, 2013 letter. The Company is producing documents in response to the subpoena.
Any potential liability from these claims cannot currently be estimated.
Twin Hickory Matter
On April 11, 2013, a flash fire occurred at Eureka Hunter Pipeline’s Twin Hickory site located in Tyler County, West Virginia. The incident occurred during a pigging operation at a natural gas receiving station. Two employees of third-party contractors received fatal injuries. Another employee of a third-party contractor was injured. In mid-February 2014, the estate of one of the deceased third-party contractor employees sued Eureka Hunter Pipeline and certain other parties in Karen S. Phipps v. Eureka Hunter Pipeline, LLC et al., Civil Action No. 14-C-41, in the Circuit Court of Ohio County, West Virginia. The plaintiff alleges that Eureka Hunter Pipeline and the other defendants engaged in certain negligent and reckless conduct which resulted in the wrongful death of the third-party contractor employee. The plaintiff has demanded judgment for an unspecified amount of compensatory, general and punitive damages. A pre-suit settlement demand has also been received from another potential claimant. Investigation regarding the incident is ongoing. It is not possible to predict at this juncture the extent to which, if at all, Eureka Hunter Pipeline or any related entities will incur liability or damages because of this incident. However, we believe our insurance coverage will be sufficient to cover any losses or liabilities we may incur as a result of this incident.
Agreement to Purchase Utica Shale Acreage
On August 12, 2013, Triad Hunter entered into an asset purchase agreement, with MNW. MNW is an Ohio limited liability company that represents an informal association of various land owners, lessees and sub-lessees of mineral acreage who own or have rights in mineral acreage located in Monroe, Noble and/or Washington Counties, Ohio. Pursuant to the purchase agreement, Triad Hunter has agreed to acquire from MNW up to 32,000 net mineral acres, including currently leased and subleased acreage, located in such counties, over the next 10 months or possibly longer, subject to certain conditions. On October 7, 2013, Triad Hunter purchased 1,156.14 net leasehold acres for $4.9 million from MNW. On October 31, 2013, Triad Hunter purchased an additional 2,050.40 net leasehold acres for $8.7 million from MNW. On December 17, 2013, Triad Hunter purchased an additional 2,837.64 net leasehold acres for $10.9 million from MNW.
Payable on Sale of Partnership
On September 26, 2008, the Company sold its 5.33% limited partner interest in Hall-Houston Exploration II, L.P. pursuant to a Partnership Interest Purchase Agreement dated September 26, 2008, as amended on September 29, 2008. The interest was purchased by a non-affiliated partnership for a cash consideration of $8.0 million and the purchaser’s assumption of the first $1.4 million of capital calls subsequent to September 26, 2008. The Company agreed to reimburse the purchaser for up to $754,255 of capital calls in excess of the first $1.4 million. The Company’s net gain on the sale of the asset is subject to future upward adjustment to the extent that some or all of the $754,255 is not called. The liability as of December 31, 2013 and 2012 was $640,695.
Operational Contingencies
The exploration, development and production of oil and gas assets, the operations of oil and natural gas gathering systems, and the performance of oil field services are subject to various federal, state, local and foreign laws and regulations designed to protect the environment. Compliance with these regulations is part of the Company's day-to-day operating procedures. Infrequently, accidental discharge of such materials as oil, natural gas or drilling fluids can occur and such accidents can require material expenditures to correct. The Company maintains various levels and types of insurance which it believes to be appropriate to limit its financial exposure. The Company is unaware of any material capital expenditures required for environmental control during the year ending December 31, 2014.
Operating Leases
As of December 31, 2013, office space rentals with terms of 12 months or greater include office spaces in Houston, Texas, at a monthly cost of $33,000, office spaces in Grapevine, Texas, with monthly payments of approximately $4,800, and Williston Hunter subsidiaries office spaces in Denver, Colorado that have monthly payments of $5,800.
Future minimum lease commitments under noncancellable operating leases at December 31, 2013, are as follows (in thousands):
Drilling Rig Purchase
On May 7, 2013, the Company, through its wholly-owned subsidiary, Alpha Hunter Drilling, LLC, completed the purchase of a new drilling rig intended for use in the Utica and Marcellus Shale formations located in southeastern Ohio and western West Virginia. Costs to acquire and install the rig and components were $15.3 million as of December 31, 2013 .
Gas Gathering and Processing Agreements
On December 14, 2011, the Company entered into a 120 -month gas transportation contract. The contract became effective on August 1, 2012. The Company's remaining liability under the contract was approximately $21.9 million as of December 31, 2013. On June 27, 2012, Eureka Hunter Pipeline entered into 36-month gas compression contract. The contract became effective on October 1, 2012. The Company's remaining liability under the contract was $3.2 million as of December 31, 2013. With the Virco Acquisition,
Triad Hunter assumed a 120-month gas transportation contract. The Company's remaining liability under the contract was $3.5 million as of December 31, 2013.
Future minimum gathering, processing, and transportation commitments at December 31, 2013, are as follows (in thousands):
Eureka Hunter Holdings Operating Agreement
Pursuant to the Eureka Hunter Holdings operating agreement, the number and composition of the board of directors of Eureka Hunter Holdings may change over time based on Ridgeline’s percentage ownership interest in Eureka Hunter Holdings (after taking into account any additional purchases of preferred units) or the failure of Eureka Hunter Holdings to satisfy certain performance goals by the third anniversary of the closing of the initial Ridgeline investment (or as of any anniversary after such date) or under certain other circumstances. The board of directors of Eureka Hunter Holdings is currently composed of a majority of members appointed by Magnum Hunter. Subject to the rights described above, the board of directors of Eureka Hunter Holdings may in the future be composed of an equal number of directors appointed by Magnum Hunter and Ridgeline or, in certain cases, of a majority of directors appointed by Ridgeline.
If a change of control of Magnum Hunter occurs at any time prior to a qualified public offering (as defined in the Eureka Hunter Holdings operating agreement) of Eureka Hunter Holdings, Ridgeline will have the right under the terms of the operating agreement to purchase sufficient additional preferred units in Eureka Hunter Holdings so that it holds up to 51.0% of the equity ownership of Eureka Hunter Holdings.
NOTE 18 - CONDENSED CONSOLIDATED GUARANTOR FINANCIAL STATEMENTS
Debt Securities Under Universal Shelf Registration Statement
Certain of the Company’s 100% owned subsidiaries, Shale Hunter, LLC, Triad Hunter, LLC, NGAS Hunter, LLC, Magnum Hunter Production, Inc., Williston Hunter, Inc., Williston Hunter ND, LLC, and Bakken Hunter, LLC (collectively, “Guarantor Subsidiaries”), have fully and unconditionally guaranteed the obligations of the Company under any debt securities that it may issue under a universal shelf registration statement on Form S-3, on a joint and several basis.
These condensed consolidating guarantor financial statements have been retrospectively revised to reflect Eagle Ford Hunter as a non-guarantor as the subsidiary was no longer a guarantor upon the closing of the sale on April 24, 2013. See "Note 2 - Divestitures and Discontinued Operations".
Condensed consolidating financial information for Magnum Hunter Resources Corporation, the Guarantor Subsidiaries and the other subsidiaries of the Company (the “Non Guarantor Subsidiaries”) as of December 31, 2013 and 2012 and for the years ended December 31, 2013, 2012, and 2011, was as follows:
Magnum Hunter Resources Corporation and Subsidiaries
Condensed Consolidating Balance Sheets
(in thousands)
Magnum Hunter Resources Corporation and Subsidiaries
Condensed Consolidating Balance Sheets
(in thousands)
Magnum Hunter Resources Corporation and Subsidiaries
Condensed Consolidating Statements of Operations
(in thousands)
Magnum Hunter Resources Corporation and Subsidiaries
Condensed Consolidating Statements of Operations
(in thousands)
_______________________
(1) PRC Williston, LLC has been presented as a discontinued operation on a stand alone basis. Elimination entries have been recorded to eliminate discontinued operations treatment on a consolidated basis.
Magnum Hunter Resources Corporation and Subsidiaries
Condensed Consolidating Statements of Comprehensive Income (Loss)
(in thousands)
Magnum Hunter Resources Corporation and Subsidiaries
Condensed Consolidating Statements of Cash Flows
(in thousands)
Senior Notes
Certain of the Company’s subsidiaries, including Alpha Hunter Drilling, LLC, Bakken Hunter, LLC, Shale Hunter, LLC, Hunter Aviation, LLC, Hunter Real Estate, LLC, Magnum Hunter Marketing, LLC, Magnum Hunter Production, Inc., Magnum Hunter Resources, GP, LLC, Magnum Hunter Resources, LP, NGAS Gathering, LLC, NGAS Hunter, LLC, PRC Williston, LLC, Triad Hunter, LLC, Williston Hunter, Inc., Williston Hunter ND, LLC, and Viking International Resources, Co., Inc. (collectively, "Guarantor Subsidiaries"), jointly and severally guarantee on a senior unsecured basis, the obligations of the Company under all the Senior Notes issued under the indenture entered into by the Company on May 16, 2012, as supplemented.
These condensed consolidating guarantor financial statements have been revised to reflect Eagle Ford Hunter as a non-guarantor as the subsidiary was no longer a guarantor upon the closing of the sale on April 24,2013. See "Note 2 - Divestitures and Discontinued Operations".
Condensed consolidating financial information for Magnum Hunter Resources Corporation , the Guarantor Subsidiaries and the other subsidiaries of the Company (the "Non Guarantor Subsidiaries") as of December 31, 2013 and 2012 and for the years ended December 31, 2013, 2012, and 2011 was as follows:
Magnum Hunter Resources Corporation and Subsidiaries
Condensed Consolidating Balance Sheets
(in thousands)
Magnum Hunter Resources Corporation and Subsidiaries
Condensed Consolidating Balance Sheets
(in thousands)
Magnum Hunter Resources Corporation and Subsidiaries
Condensed Consolidating Statements of Operations
(in thousands)
Magnum Hunter Resources Corporation and Subsidiaries
Condensed Consolidating Statements of Operations
(in thousands)
_________________
(1) PRC Williston, LLC has been presented as a discontinued operation on a stand alone basis. Elimination entries have been recorded to eliminate discontinued operations treatment on a consolidated basis.
Magnum Hunter Resources Corporation and Subsidiaries
Condensed Consolidating Statements of Comprehensive Income (Loss)
(in thousands)
Magnum Hunter Resources Corporation and Subsidiaries
Condensed Consolidating Statements of Cash Flows
(in thousands)
Magnum Hunter Resources Corporation and Subsidiaries
Condensed Consolidating Statements of Cash Flows
(in thousands)
NOTE 19 - SUBSEQUENT EVENTS
Master Loan and Security Agreement
On January 21, 2014, Alpha Hunter Drilling, LLC entered into a Master Loan and Security Agreement with CIT Finance to borrow $5.6 million at an interest rate of 7.94% over a term of forty-eight months. The note is collateralized by field equipment, and the Company is a guarantor on the note.
Derivative Contracts
We entered into commodity derivative contracts subsequent to December 31, 2013, through the date of this report. Our objective for holding these commodity derivatives is to protect the operating revenues and cash flows related to a portion of our future natural gas and crude oil sales from the risk of significant declines in commodity prices, which helps insure our ability to fund our capital expenditure budget. We have not designated any of these commodity derivatives as hedges under ASC 815.
The table below is a summary of our commodity derivatives entered into subsequent to December 31, 2013 through the date of this report:
Common Stock Granted to Employees, Management and Board Members
On January 8, 2014, the Company granted 1,312,575 restricted shares of common stock to officers, executives, and employees of the Company. The shares vest over a 3-year period with 33% of the options vesting one year from the date of the grant. The Company also granted 123,798 restricted shares to the directors of the Company which vest 100% one year from the date of the grant.
Issuance of Series A Preferred Units of Eureka Hunter Holdings
Eureka Hunter Holdings has issued 97,492 Series A Preferred units with a redemption value of $1.9 million for dividends paid in kind subsequent to December 31, 2013.
Settlement Agreement with Seminole Energy Services
On January 10, 2014, the company and certain of its subsidiaries entered into an Omnibus Settlement Agreement and Release dated January 9, 2014 with Seminole Energy Services, LLC and certain of its affiliates (collectively, "Seminole"). In connection with and pursuant to the terms of the Settlement Agreement, the Company and Seminole have agreed to release and discharge each other from all claims and causes of action alleged in, arising from or related to certain legal proceedings and terminate, amend and enter into certain new, related agreements effective immediately prior to year-end on December 31, 2013 (the "New Agreements").
By entering into the New Agreements, the Company and Seminole have restructured their existing agreements. The Company obtained a reduction in gas gathering rates it will pay for natural gas gathered on the Stone Mountain Gathering System that the Company owns or controls. The Company and Seminole collectively agreed to construct an enhancement of the Rogersville Plant designed to recover less ethane and more propane from the natural gas processed at the Rogersville Plant and reduce and extend the Company's contractual horizontal well drilling obligations owed to Seminole. The Company and Seminole have also agreed to modify the natural gas processing rates the Company will pay for processing at the Rogersville Plant, the Company's allocation of natural gas liquids ("NGL") recovered from gas processed and the costs of blend stock necessary to blend with the NGL produced from the Rogersville Plant, and certain deductions to the NGL purchase price the Company will pay Seminole for the Company's NGL produced from the Rogersville Plant. Seminole sold to the Company Seminole's 50% interest in a natural gas gathering trunk line and treatment facility located in southwestern Muhlenberg County, Kentucky, which had previously been owned equally by Seminole and the Company.
As a result of the restructuring effected by the Settlement Agreement, the Company expects to realize operational savings, certain components of which savings would occur over time, depending on the implementation timing or completion of certain of the benefits provided to the Company.
Sale of Certain other Eagle Ford Shale Assets
On January 28, 2014, the Company and certain of its affiliates closed on the sale of certain of its oil and gas properties and related assets in the Eagle Ford Shale in South Texas to New Standard Energy Texas LLC (“NSE Texas”), a subsidiary of New Standard Energy Limited (“NSE”), an Australian Securities Exchange-listed Australian company.
The divested properties and assets consisted primarily of leasehold acreage in Atascosa County, Texas and working interests in five horizontal wells, four of which wells were operated by the Company (the “Eagle Ford Assets”). The effective date of the sale was December 1, 2013. As consideration for the Eagle Ford Assets, the Company received aggregate purchase price consideration of $15 million in cash (before taking into account customary purchase price adjustments) and 65,650,000 ordinary shares of NSE valued, for purposes of the calculation of the purchase price, at approximately $9.5 million. This represents approximately 17% of the total shares outstanding of NSE.
In connection with the closing of the sale, Shale Hunter, LLC, a subsidiary of the Company (“Shale Hunter”), and NSE Texas entered into a Transition Services Agreement (the “TSA”). The TSA provides that, during a specified transition period, Shale Hunter will provide NSE Texas with certain transitional services relating to the Eagle Ford Assets for a fee.
Upon and as a result of the closing of the sale of the Eagle Ford Assets on January 28, 2014, the borrowing base under the Company’s asset-based, senior secured revolving credit facility maturing April 13, 2016 was automatically reduced by $10 million to $232.5 million as of the closing pursuant to the terms of the Company’s Third Amended and Restated Credit Agreement, dated as of December 13, 2013, by and among the Company, as borrower, certain of its subsidiaries, as guarantors, Bank of Montreal, as administrative agent, the lenders party thereto and the agents party thereto.
Item 9.
Item 9.
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
Item 9A.
Item 9A. CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
The Company's management, including the Chief Executive Officer (CEO) and Chief Financial Officer (CFO) performed an evaluation of the effectiveness of the Company's disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended) as of December 31, 2013. Based upon that evaluation, the CEO and CFO concluded that, as a result of the material weaknesses in internal control over financial reporting that are described below in Management's Report on Internal Control Over Financial Reporting, the Company's disclosure controls and procedures were not effective as of December 31, 2013.
Management's Report on Internal Control Over Financial Reporting
Management is responsible for establishing and maintaining adequate internal control over financial reporting. The Company's internal control over financial reporting is a process, under the supervision of the CEO and CFO, designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the Company's financial statements for external purposes in accordance with generally accepted accounting principles.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Our management, with the participation of outside consultants, has conducted an assessment of the effectiveness of the Company's internal control over financial reporting as of December 31, 2013 based on the criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (1992 COSO Framework). Based on the assessment, management has concluded that, as of December 31, 2013, the Company's internal control over financial reporting was not effective due to the material weaknesses described below.
A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the Company's annual or interim financial statements will not be prevented or detected on a timely basis. Management has failed to remediate the material weaknesses in the internal control over financial reporting as of December 31, 2013 as follows:
•
The Company did not maintain effective controls over the intraperiod allocation of income taxes.
•
The Company did not maintain effective controls over timely preparation and review of account reconciliations.
•
As a result of the aggregation of deficiencies, the Company determined that it did not maintain effective controls over property accounting with respect to the accuracy and completeness of property records and related information.
•
The Company reported fourteen material weaknesses as of December 31, 2012. Due to significant remediation efforts made by management, the number of material weaknesses has been reduced to three as of December 31, 2013.
As of December 31, 2013, management has sufficient evidence to conclude that remediation has been completed for the eleven other material weaknesses which were reported as of December 31, 2012.
Our independent registered public accounting firm has audited the effectiveness of our internal control over financial reporting as of December 31, 2013 as stated in their report, dated February 25, 2014, which appears herein.
Remediation Plan
The Board of Directors, the Audit Committee, and senior management of the Company understand their responsibility to provide the appropriate direction and oversight governance to ensure the Company achieves effective and comprehensive internal control over financial reporting. The management team has worked diligently to improve the design and operating effectiveness of internal control over financial reporting. Due to the continued efforts of management towards improving controls, the Company has been able to remediate the other eleven previously reported material weaknesses. Management expects to continue on the path of remediation in 2014 to improve our internal control over financial reporting.
The Company has a dedicated full-time tax manager and director and engaged a consulting firm to provide advisory services on tax matters. Although there have been significant control improvements made during 2013, a remediation plan and time-line has been put in place and management will monitor the Company's remediation efforts. Specifically, management has developed detailed procedures to ensure tax provisions and disclosures are properly reflected in the financial statements.
During 2013, management has continued to reorganize roles and responsibilities over the general accounting and financial reporting process in an effort to establish and maintain effective and sustainable controls. In addition, the Company implemented an account reconciliation software tool to enable the tracking, monitoring and evidencing of balance sheet account reconciliations. The improvement in processes is continuing as management has implemented procedures to monitor the performance of internal controls over reconciliations.
Management will continue the process of transitioning the manually tracked leases to an automated land system in order to improve the completeness, accuracy, and control of the data. Controls over maintenance of lease records will include authorization for updates to lease files, prevention of unauthorized access to or alteration of data and adequate support for and reconciliation of subsidiary property records. Additional processes and controls will be implemented to address completeness and accuracy of and review transfers of leasehold property costs.
Senior management is developing a formal remediation plan and time-line and will monitor the Company's remediation efforts. Under the direction of the CEO, CFO, and the CAO reporting to the Audit Committee of the Board of Directors, management will continue to assess the design of the Company's control environment to improve the effectiveness of internal control over financial reporting.
Item 9B.
Item 9B.
OTHER INFORMATION
None.
PART III
Item 10.
Item 10. DIRECTORS, EXECUTIVE OFFICERS, AND CORPORATE GOVERNANCE
Information as to Item 10 will be set forth in the 2014 Proxy Statement, or the Proxy Statement, for the Company’s Annual Meeting of Stockholders anticipated to be held in July 2014, or the Annual Meeting, and is incorporated herein by reference.
Item 11.
Item 11. EXECUTIVE COMPENSATION
Information as to Item 11 will be set forth in the Proxy Statement for the Annual Meeting and is incorporated herein by reference.
Item 12.
Item 12.
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
Information as to Item 12 will be set forth in the Proxy Statement for the Annual Meeting and is incorporated herein by reference.
Item 13.
Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
Information as to Item 13 will be set forth in the Proxy Statement for the Annual Meeting and is incorporated herein by reference.
Item 14.
Item 14.
PRINCIPAL ACCOUNTANT FEES AND SERVICES
Information as to Item 14 will be set forth in the Proxy Statement for the Annual Meeting and is incorporated herein by reference.
PART IV
Item 15.
Item 15.
EXHIBITS, FINANCIAL STATEMENT SCHEDULES
1.
Consolidated Financial Statements: See financial statements of PRC Williston, LLC for fiscal years ended December 31, 2013, 2012 and 2011. See Index to Financial Statements on page for PRC Williston, LLC financial statements included herein.
2.
Financial Statement Schedules: All financial statement schedules are omitted as inapplicable or because the required information is contained in the financial statements or the notes thereto.
3.
Exhibits: See the list of exhibits in the Index to Exhibits to this annual report on Form 10-K, which is incorporated by reference herein.
PRC WILLISTON, LLC
PRC WILLISTON, LLC
Report of Independent Registered Public Accounting Firm
Board of Directors and Member
PRC Williston, LLC
Houston, Texas
We have audited the accompanying balance sheets of PRC Williston, LLC as of December 31, 2013 and 2012, and the related statements of operations, changes in member’s deficit, and cash flows for the years then ended. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of PRC Williston, LLC as of December 31, 2013 and 2012 and the results of its operations and its cash flows for the years then ended, in conformity with accounting principles generally accepted in the United States of America.
/s/ BDO USA, LLP
Dallas, Texas
February 25, 2014
PRC WILLISTON, LLC
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Members
PRC Williston, LLC
We have audited the accompanying statements of operations, changes in member’s deficit, and cash flows for the year ended December 31, 2011, of PRC Williston, LLC (the “Company”). These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.
In our opinion, financial statements referred to above present fairly, in all material respects, the results of operations of the Company and its cash flows for the year ended December 31, 2011, in conformity with U.S. generally accepted accounting principles.
/s/ Hein & Associates LLP
Dallas, Texas
January 11, 2013
PRC WILLISTON, LLC
PART I. FINANCIAL INFORMATION
PRC WILLISTON, LLC
BALANCE SHEETS
(In thousands)
(unaudited)
The accompanying notes to financial statements are an integral part of these financial statements.
PRC WILLISTON, LLC
PRC WILLISTON, LLC
STATEMENTS OF OPERATIONS
(In thousands)
The accompanying notes to financial statements are an integral part of these financial statements.
PRC WILLISTON, LLC
PRC WILLISTON, LLC
STATEMENT OF CHANGES IN MEMBER’S DEFICIT
(In thousands)
The accompanying notes to financial statements are an integral part of these financial statements.
PRC WILLISTON, LLC
PRC WILLISTON, LLC
STATEMENTS OF CASH FLOWS
(In thousands)
The accompanying notes to financial statements are an integral part of these financial statements.
PRC WILLISTON, LLC
NOTES TO FINANCIAL STATEMENTS
NOTE 1-ORGANIZATION AND NATURE OF OPERATIONS
PRC Williston, LLC (the “Company" or “PRC Williston”) is a 87.5% - owned subsidiary of Magnum Hunter Resources Corporation, a Delaware corporation, operating directly and indirectly through its subsidiaries (“Magnum Hunter”, “MHR” or “Parent”), a Houston, Texas based independent exploration and production company engaged in the acquisition and development of producing properties and undeveloped acreage, the production of oil and natural gas, and certain midstream and oil field service activities in the United States ("U.S."). PRC Williston is engaged in secondary enhanced oil recovery projects in the U.S., and all of its properties are non-operated in the Williston Basin.
The Company is a limited liability company (“LLC”). As an LLC, the amount of loss at risk for each individual member is limited to the amount of capital contributed to the LLC, and unless otherwise noted, the individual member’s liability for indebtedness of an LLC is limited to the member’s actual capital contribution. Magnum Hunter is the sole member of the Company; however, the Company has granted a 12.5% net profits interest. The net profits interest is functionally equivalent to a nonvoting class of membership interest in that it allows participation in any future distributions.
NOTE 2-SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Basis of Presentation
Our financial statements are prepared in accordance with accounting principles generally accepted in the United States of America. The preparation of our financial statements requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses. These estimates are based on information that is currently available to us and on various other assumptions that we believe to be reasonable under the circumstances. Actual results could differ from those estimates under different assumptions and conditions. Significant estimates are required for proved oil and gas reserves which, as described below under Estimates of Proved Oil and Gas Reserves, may have a material impact on the carrying value of oil and gas property.
Divestitures and Discontinued Operations
Certain balances in the financial statements and disclosures in the footnotes have been revised as a result of the sale of all of the oil and gas assets of PRC Williston, LLC on December 30, 2013. The operating results of PRC Williston, have been reclassified as discontinued operations in the consolidated statements of operations for the years ended December 31, 2013, 2012, and 2011. See "Note 2 - Divestitures and Discontinued Operations".
Financial Instruments
The carrying amounts of financial instruments including accounts receivable, accounts payable and accrued liabilities, and accounts payable to Parent approximate fair value as of December 31, 2013 and 2012.
Oil and Gas Properties
Capitalized Costs
Our oil and gas properties consisted of the following:
________________________________
(1) No capitalized costs exist at December 31, 2013 due to the sale of the oil and gas properties of PRC Williston, LLC.
We follow the successful efforts method of accounting for our oil and gas producing activities. Costs to acquire mineral interests in oil and gas properties and to drill and equip development wells and related asset retirement costs are capitalized. Costs to drill exploratory wells are capitalized pending determination of whether the wells have proved reserves. If we determine that the wells do not have proved reserves, the costs are charged to expense. There were no costs capitalized for exploratory wells pending the determination of proved reserves at either December 31, 2013 or 2012. Geological and geophysical costs, including seismic studies and costs of carrying and retaining unproved properties are charged to expense as incurred. We capitalize interest on expenditures for significant exploration and development projects that last more than six months while activities are in progress to bring the assets to their intended use. No interest was capitalized during the periods presented.
On the sale or retirement of a complete unit of a proved property, the cost and related accumulated depreciation, depletion, and amortization are eliminated from the property accounts, and the resultant gain or loss is recognized. On the retirement or sale of a partial unit of proved property, the cost is charged to accumulated depreciation, depletion, and amortization with a resulting gain or loss recognized in income.
Capitalized amounts attributable to proved oil and gas properties are depleted by the unit-of-production method over proved reserves using the unit conversion ratio of six Mcf of gas to one Bbl of oil and the ratio of forty-two Gal of natural gas liquids to one Bbl of oil. Well costs and related equipment are depleted over proved developed reserves, and leasehold costs are depleted over total proved reserves. Depreciation and depletion expense from continuing operations for oil and gas producing property and related equipment was $0 million for the years ended December 31, 2013, 2012, and 2011.
Capitalized costs related to proved oil and gas properties, including wells and related equipment and facilities, are evaluated for impairment based on an analysis of undiscounted future net cash flows. If undiscounted cash flows are insufficient to recover the net capitalized costs related to proved properties, then we recognize an impairment charge in income from operations equal to the difference between the net capitalized costs related to proved properties and their estimated fair values based on the present value of the related future net cash flows. We recorded no impairment charge to our proved properties during the year ended December 31, 2013, we recorded $2.3 million impairments for the year ended December 31, 2012 in discontinued operations, and we incurred no impairment charge to our proved properties for the year ended December 31, 2011 based on our analysis.
Unproved oil and gas properties that are individually significant are periodically assessed for impairment of value, and a loss is recognized at the time of impairment by providing an impairment allowance in the Company’s statement of operations. We recorded no impairment to unproved properties during the year ended December 31, 2013, and $10.5 million during the year ended December 31, 2012 in discontinued operations. We did not record impairment during the year ended 2011.
On the sale of an entire interest in an unproved property for cash or cash equivalent, gain or loss on the sale is recognized, taking into consideration the amount of any recorded impairment if the property had been assessed individually. If a partial interest in an unproved property is sold, the amount received is treated as a reduction of the cost of the interest retained.
Estimates of Proved Oil and Gas Reserves
Estimates of our proved reserves included in this report are prepared in accordance with U.S. generally accepted accounting principles (“GAAP”) and SEC guidelines. The accuracy of a reserve estimate is a function of:
· the quality and quantity of available data;
· the interpretation of that data;
· the accuracy of various mandated economic assumptions;
· and the judgment of the persons preparing the estimate.
Our proved reserve information included in this report was predominately based on evaluations prepared by independent petroleum engineers. Estimates prepared by other third parties may be higher or lower than those included herein. Because these estimates depend on many assumptions, all of which may substantially differ from future actual results, reserve estimates will be different from the quantities of oil and gas that are ultimately recovered. In addition, results of drilling, testing and production after the date of an estimate may justify material revisions to the estimate.
In accordance with SEC requirements, we based the estimated discounted future net cash flows from proved reserves on the unweighted arithmetic average of the prior 12-month commodity prices as of the first day of each of the months constituting the period and costs on the date of the estimate. Future prices and costs may be materially higher or lower than these prices and costs which would impact the estimated value of our reserves.
The estimates of proved reserves may materially impact depreciation, depletion, and amortization (“DD&A”) expense. If the estimates of proved reserves decline, the rate at which we record depreciation and depletion expense will increase, reducing net income. Such a decline may result from lower estimated market prices.
Revenue Recognition
Revenues associated with sales of crude oil, natural gas, natural gas liquids and petroleum products, and other items are recognized when title passes to the customer, which is when the risk of ownership passes to the purchaser and physical delivery of goods occurs, either immediately or within a fixed delivery schedule that is reasonable and customary in the industry.
Revenues from the production of natural gas and crude oil properties in which we have an interest with other producers are recognized based on the actual volumes we sold during the period. Any differences between volumes sold and entitlement volumes, based on our net working interest, which are deemed to be non-recoverable through remaining production, are recognized as accounts receivable or accounts payable, as appropriate. Cumulative differences between volumes sold and entitlement volumes are generally not significant.
Restricted Cash
On December 23, 2013, the Chancery Court entered a temporary restraining order prohibiting the Company from transferring, assigning, removing, distributing or otherwise displacing to its Parent, or its parent’s creditors, or any other person or entity $5,000,000 of the proceeds received in connection with the sale of the Company’s assets. See “Note 8 - Contingencies.”
Accounts Receivable
Accounts receivable consists of oil and gas sales, due under normal trade terms, generally requiring payment within 30 to 60 days of production. Payments made on all accounts receivable are applied to the earliest unpaid items. We review our accounts receivable periodically and reduce the carrying amount by a valuation allowance that reflects our best estimate of the amount that may not be collectible. Based on our review, no allowance was warranted at either December 31, 2013 or 2012.
Production Costs
Production costs, including compressor rental and repair, pumpers’ salaries, saltwater disposal, ad valorem taxes, insurance, repairs and maintenance, expensed workovers and other operating expenses are expensed as incurred and included in lease operating expense on our consolidated statements of operations.
Severance Tax and Marketing
Severance taxes comprise production taxes charged by the state of North Dakota on oil and natural gas produced. These taxes are computed on the basis of volumes and/or value of production or sales. These taxes are usually levied at the time and place the minerals are severed from the producing reservoir. Marketing costs are those directly associated with marketing our production and are based on volumes produced.
Exploration and Abandonments
Exploration expenses include dry hole costs, delay rentals, and geological and geophysical costs. Abandonment costs are charges to leasehold costs associated with properties that we chose not to develop and impair such costs.
Dependence on Major Customers
For the years ended December 31, 2013, 2012, and 2011, we sold 48%; 99%; and 98%, respectively, of our oil and gas produced to Plains Marketing, L.P. (“Plains”), a subsidiary of Plains All American Pipeline, L.P. Additionally, substantially all of our accounts receivable related to oil and gas sales were due from Plains at December 31, 2013 and 2012. For the year ended December 31, 2013, we sold 52% of our oil and gas produced to Trafigura Limited. We believe that there are potential alternative purchasers and that it may be necessary to establish relationships with new purchasers if our production grows. However, there can be no assurance that we
can establish such relationships and that those relationships will result in increased purchasers. Although we are exposed to a concentration of credit risk, we believe that Plains and Trafigura are credit worthy.
Dependence on Suppliers
Our industry is cyclical, and from time to time there is a shortage of drilling rigs, fracture stimulation services, equipment, supplies and qualified personnel. During these periods, the costs and delivery times of rigs, equipment and supplies are substantially greater. If the unavailability or high cost of drilling rigs, equipment, supplies or qualified personnel were particularly severe in the areas where we operate, we could be materially and adversely affected. We believe that there are potential alternative providers of drilling services and that it may be necessary to establish relationships with new contractors as our activity level and capital program grows. However, there can be no assurance that we can establish such relationships and that those relationships will result in increased availability of drilling rigs.
Accounts Payable to Parent
In accordance with revolving credit agreement between the Company and its Parent, the Parent has loaned funds to the Company to i) pay off third party debt, ii) fund operations, principally joint interest billings offset by revenue receipts, and iii) fund the development of oil and gas properties. As of December 31, 2013 and 2012, the Company has an outstanding liability owed to its Parent in the amount of $45.7 million and $59.0 million, respectively. See “Note 5- Related Party Transactions.”
Asset Retirement Obligation
Our asset retirement obligation represents the present value of the estimated amount we will incur to plug, abandon and remediate our producing properties at the end of their productive lives, in accordance with applicable federal, state and local laws. We determine our asset retirement obligation by calculating the present value of estimated cash flows related to the liability. The retirement obligation is recorded as a liability at its estimated present value as of the asset’s inception, with an offsetting increase to proved properties. Periodic accretion of discount of the estimated liability is recorded as accretion expense in the consolidated statements of operations.
Our liability is determined using significant assumptions, including current estimates of plugging and abandonment costs, annual inflation of these costs, the productive lives of wells and our risk-adjusted interest rate. Changes in any of these assumptions can result in significant revisions to the estimated asset retirement obligation. See “Note 4 - Asset Retirement Obligations” to our financial statements for more information.
Income Taxes
The Company is not subject to federal income taxes and does not have a tax sharing agreement or allocate taxes with its member. Therefore, no provision has been made for federal or state income taxes on the Company’s books. It is the responsibility of the member to report its share of taxable income or loss on its separate income tax return. Accordingly, no recognition has been given to federal or state income taxes in the accompanying financial statements.
Based on management’s analysis, the Company did not have any uncertain tax positions as of December 31, 2013 or 2012. The Company’s income tax returns for the periods subsequent to December 31, 2009 remain open for examination by taxing authorities. Interest and penalties, and the associated tax expense related to uncertain tax positions, when applicable, will be recorded in income tax expense as the positions are recognized. At December 31, 2013, and 2012, there were no material income tax interest or penalty items recorded in the statement of operations or as a liability on the balance sheet.
NOTE 3 - DIVESTITURES AND DISCONTINUED OPERATIONS
Sale of PRC Williston, LLC and Williston Hunter ND, LLC
On December 30, 2013, PRC Williston (together with its affiliate Williston Hunter) closed on the sale of all of their oil and gas assets to Enduro Operating, LLC for a total purchase price of approximately $44.1 million in cash, after initial purchase price adjustments, of which $21.9 million was attributed to the Company, such proceeds being allocated according to the fair value of the assets sold. The effective date of the sale was September 1, 2013. PRC Williston has recognized a preliminary gain on the sale of $7.1 million, net of tax.
NOTE 4 - ASSET RETIREMENT OBLIGATIONS
The Company accounts for asset retirement obligations based on the guidance of ASC 410 which addresses accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. ASC 410 requires that the fair value of a liability for an asset’s retirement obligation be recorded in the period in which it is incurred and the corresponding cost capitalized by increasing the carrying amount of the related long-lived asset. The liability is accreted to its present value each period, and the capitalized cost is depreciated over the estimated useful life of the related asset. Both the accretion of the liability and the depreciation of the asset are included in DD&A. We have included estimated future costs of abandonment and
dismantlement in our successful efforts oil and gas properties base and deplete these costs as a component of our DD&A expense in the accompanying financial statements.
The following table summarizes the Company’s asset retirement obligation transactions during the years ended December 31:
NOTE 5 - RELATED PARTY TRANSACTIONS
The Company and its parent, Magnum Hunter, have an arrangement whereby Magnum Hunter provides funding to the Company for costs of developing oil and gas properties and Magnum Hunter allocates interest expense and general and administrative expenses to the Company. The allocation of interest expense is computed based on the amount funded to the Company multiplied by the interest rate applicable to Magnum Hunter’s revolving credit facility. The effective interest rate due by the Company to Magnum Hunter was approximately 3.42%, 3.56%, and 3.55% for the years ended December 31, 2013, 2012, and 2011, respectively. The interest expense allocated to PRC Williston was $1.9 million, $2.1 million, and $2.1 million, for the years ended December 31, 2013, 2012, and 2011, respectively. Accrued interest is included in accounts payable due to Parent. General and administrative expenses are allocated to the Company from Magnum Hunter on a pro rata basis relating to the Company’s revenues in proportion to the consolidated oil and gas sales of Magnum Hunter and all its subsidiaries. The general and administrative expense allocated to PRC Williston was $1.7 million, $1.2 million, and $2.7 million for the years ended December 31, 2013, 2012, and 2011, respectively. The accumulated charges from the general and administrative expense allocation are included in accounts payable due to Parent. At December 31, 2013, the balance due to Magnum Hunter was $45.7 million, and the balance was $59.0 million as of December 31, 2012.
The following table sets forth the Company’s related-party expenses during the years ended December 31, 2013, 2012, and 2011:
Accumulated interest and general and administrative expense allocated to PRC Williston are included in accounts payable due to Parent. At December 31, 2013, the balance due to Magnum Hunter was $45.7 million, and $59.0 million at December 31, 2012.
NOTE 6 - GUARANTEE
On May 16, 2012, the Company was named a guarantor subsidiary to the Senior Notes issued by the Parent, which are due November 2020. The Senior Notes were issued by the Parent pursuant to an indenture entered into on May 16, 2012 as supplemented, among the Parent, the subsidiary guarantors party thereto, Wilmington Trust, National Association, as the trustee, and Citibank, N.A., as the paying agent, registrar and authenticating agent. The terms of the Senior Notes are governed by the indenture, which contains affirmative and restrictive covenants that, among other things, limit the Parent’s and the guarantors’ ability to incur or guarantee additional indebtedness or issue certain preferred stock; pay dividends on capital stock or redeem, repurchase or retire capital stock or subordinated indebtedness or make certain other restricted payments; transfer or sell assets; make loans and other investments; create or permit to exist certain liens; enter into agreements that restrict dividends or other payments from restricted subsidiaries to the Company; consolidate, merge or transfer all or substantially all of their assets; engage in transactions with affiliates; and create unrestricted subsidiaries.
The indenture also contains events of default. Upon the occurrence of events of default arising from certain events of bankruptcy or insolvency, the Senior Notes shall become due and payable immediately without any declaration or other act of the trustee or the holders of the Senior Notes. Upon the occurrence of certain other events of default, the trustee or the holders of at least 25% in aggregate principal amount of the then outstanding Senior Notes may declare all outstanding Senior Notes to be due and payable immediately.
The Parent had $600.0 million in principal outstanding under the Senior Notes as of December 31, 2013. The Company shares joint and several liability with other guaranteeing subsidiaries of the Parent, and the Company does not expect the default provisions to require recourse to the lenders. As such, the Company cannot estimate any potential loss as a result of the guarantee of indebtedness of the Parent. In January 2014, PRC ceased to be a guarantor subsidiary. See “Note 9 - Subsequent Events.”
NOTE 7 - SUPPLEMENTAL OIL AND GAS DISCLOSURES (UNAUDITED)
The following table sets forth the costs incurred in oil and gas property acquisition, exploration, and development activities.
Oil and Gas Reserve Information
Proved oil and gas reserve quantities are based on estimates prepared by Magnum Hunter’s third party reservoir engineering firms. There are numerous uncertainties inherent in estimating quantities of proved reserves and projecting future rates of production and timing of development expenditures. The following reserve data only represent estimates and should not be construed as being exact.
Total Proved Reserves
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Reserves
The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves and the changes in standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves were prepared in accordance with current provisions of ASC 932. Future cash inflows at December 31, 2013, 2012, and 2011 were computed by applying the unweighted, arithmetic average on the closing price on the first day of each month for the 12-month period prior to December 31, 2013, 2012, and 2011 to estimated future production. Future production and development costs are computed by estimating the expenditures to be incurred in developing and producing the proved oil and natural gas reserves at year-end, based on year-end costs and assuming continuation of existing economic conditions.
The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves are as follows:
Changes in Standardized Measure of Discounted Future Net Cash Flows
The changes in the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves are as follows:
The commodity prices inclusive of adjustments for quality and location used in determining future net revenues related to the standardized measure calculation are as follows.
NOTE 8 - CONTINGENCIES
On December 16, 2013, Drawbridge Special Opportunities Fund LP (“Drawbridge”) and Fortress Value Recovery Fund I LLC f/k/a D.B. Zwirn Special Opportunities Fund, L.P. (“Fortress”) (collectively, “Plaintiffs”) filed suit against PRC Williston LLC (“PRC”) in the Court of Chancery of the State of Delaware in a case captioned C.A. No. 9166-VCL, Drawbridge Special Opportunities Fund LP and Fortress Value Recovery Fund I LLC f/k/a D.B. Zwirn Special Opportunities Fund, L.P. v. PRC Williston LLC. Plaintiffs allege that they are entitled to a 12.5% collective interest in any distributions on equity made by PRC. Their claims are based on
Participation Agreements entered into between PRC and the Plaintiffs in February 2007 in connection with the Plaintiffs extending credit to PRC pursuant to a credit agreement. Plaintiffs claim that they are entitled to compensation for 12.5% of alleged past distributions on equity from PRC to Magnum Hunter Resources Corporation (“Magnum Hunter”), as well as to receive 12.5% of any transfers of funds to Magnum Hunter from the proceeds of the December 30, 2013 sale of PRC’s assets for approximately $21.9 million. On December 23, 2013, the Chancery Court entered a temporary restraining order prohibiting PRC from transferring, assigning, removing, distributing or otherwise displacing to Magnum Hunter, Magnum Hunter’s creditors, or any other person or entity, $5 million of the proceeds received by PRC in connection with the sale of PRC’s assets to Enduro Operating LLC. The Court also granted Plaintiffs’ motion for expedited proceedings, ordering expedited discovery and a hearing within 90 days on Plaintiffs’ motion for a preliminary injunction. Plaintiffs’ motion for a preliminary injunction effectively seeks to extend the relief granted by the temporary restraining order until after a full trial on the merits. A hearing on Plaintiffs’ motion for a preliminary injunction is scheduled to occur on March 18, 2014.
NOTE 9 - SUBSEQUENT EVENTS
In January 2014, as permitted by the MHR debt agreements referred to in clauses (i) and (ii), PRC ceased to be a guarantor of (i) MHR’s indebtedness under MHR’s senior revolving credit facility and (ii) MHR’s indebtedness under its indenture pursuant to which MHR has issued certain senior unsecured notes.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
MAGNUM HUNTER RESOURCES CORPORATION
By:
/s/ GARY C. EVANS
Gary C. Evans
Chairman of the Board and Chief Executive Officer
Date: February 25, 2014
*
+
The schedules to this exhibit have been omitted pursuant to Item 601(b)(2) of Regulation S-K and will be provided to the SEC upon request.
@
Portions of this exhibit are subject to a request for confidential treatment and have been redacted and filed separately with the SEC.
#
Filed Herewith
^
These exhibits are furnished herewith. In accordance with Rule 406T of Regulation S-T, these exhibits are not deemed to be filed or part of a registration statement or prospectus for purposes of Section 11 or 12 of the Securities Act of 1933, as amended, are not deemed to be filed for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, and otherwise are not subject to liability under these sections.